2016Annual Report FERC Form.pdf

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ROCKY MOUNTAIN
FOWER
A DIVISloil OF PACIFICORP
1407 West North Temple, Suite 310
Salt Lake City, Utah 84116:' 1: '.:: r. i r ilii'LU
May 23,2017 . ii I I ili,'; ;l i flli $: I0
VIA OWRNIGHT DELIWRY
Idaho Public Utilities Commission
472West Washington
Boise,ID 83702-5983
Attention:Diane Hanian
Commission Secretary
RE: FERC Form 1
PacifiCorp (d.b.a. Rocky Mountain Power) submits for filing one copy of PacifiCorp's annual
FERC Form I report for the year ended December 31,2016. An electronic copy of the report is
provided on the enclosed CD for your convenience.
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,
Vice President, Regulation
Enclosure
,rt l:
I ii:!slcl'r
THIS FILING IS
Item 1: An Initial (Original)
Submission
OR Resubmission No. ____X
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
OMB No.1902-0021
OMB No.1902-0029
OMB No.1902-0205
(Expires 12/31/2019)
(Expires 12/31/2019)
(Expires 12/31/2019)
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 2016/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/forms/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/forms/form-1/form-1.pdf and
http://www.ferc.gov/docs-filing/forms.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
/ /
2016/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
NA202-203Nuclear Fuel Materials 15
204-207Electric Plant in Service 16
NA213Electric 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
NA230Extraordinary Property Losses 24
NA230Unrecovered 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
/ /
2016/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
NA302Regional 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
NA331Transmission 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
NA356Common 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
NA400aMonthly 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
NA408-409Pumped 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
/ /
2016/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
/ /2016/Q4
Nikki L. Kobliha, Vice President, Chief Financial Officer and Treasurer
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 selling electricity. In
addition to retail sales, PacifiCorp buys and sells 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.
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
2016/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
/ /2016/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 90.0%, Walter Scott, Jr. (along with family members and related entities) owns 9.0% 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
/ /
2016/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 ceased mining operations in 2015.
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. Three of the PacifiCorp Foundation's five directors are also
directors of PacifiCorp.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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
/ /
2016/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 338,000Stefan A. Bird 3
President and Chief Executive Officer, 4
Rocky Mountain Power 338,000Cindy A. Crane 5
Vice President, Chief Financial Officer and Treasurer 203,900Nikki L. Kobliha 6
President and Chief Executive Officer, 7
PacifiCorp Transmission 344,007R. Patrick Reiten 8
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FERC FORM NO. 1 (ED. 12-96) Page 104
Schedule Page: 104 Line No.: 1 Column: c
PacifiCorp sets forth the salary information for its "named executive officers" for the
year ended December 31, 2016, consistent with Item 402 of Regulation S-K promulgated by
the Securities and Exchange Commission, in its Annual Report on Form 10-K. Salary
information of other officers will be provided to the Federal Energy Regulatory Commission
upon request, but the company considers such information personal and confidential to such
officers. See 18 CFR 388.107(d),(f).
Schedule Page: 104 Line No.: 2 Column: b
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. Refer to
BHE’s Annual Report on Form 10-K for the year ended December 31, 2016, for executive
compensation information for Mr. Abel.
Schedule Page: 104 Line No.: 8 Column: b
R. Patrick Reiten, President and Chief Executive Officer of PacifiCorp Transmission,
resigned as a director and officer of PacifiCorp effective December 31, 2016. For further
information, 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
2016/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
/ /
2016/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, 2016: 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 Street, 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
1111 South 103rd Street, Omaha, Nebraska 68124Douglas L. Anderson 8
666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309Patrick J. Goodman 9
825 NE Multnomah Street, Suite 2000, Portland, Oregon 97232Natalie L. Hocken 10
1800 M Street NW, Suite 300, Washington, DC 20036Andrea L. Kelly 11
1800 M Street NW, Suite 300, Washington, DC 20036R. Patrick Reiten 12
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FERC FORM NO. 1 (ED. 12-95) Page 105
Schedule Page: 105 Line No.: 11 Column: a
Andrea L. Kelly, Senior Vice President, Legislative and Regulatory Strategy of Berkshire
Hathaway Energy Company, resigned as a director of PacifiCorp effective December 31, 2016.
For further information, refer to Item 13 in Important Changes During the Year in this
Form No. 1.
Schedule Page: 105 Line No.: 12 Column: a
R. Patrick Reiten, President and Chief Executive Officer of PacifiCorp Transmission,
resigned as a director and officer of PacifiCorp effective December 31, 2016. For further
information, 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
2016/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
/ /2016/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
/ /2016/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
03/18/201620160318-5009 ER16-1231 1
05/16/201620160516-5287 ER11-3643 2
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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 2016) to be effective 6/01/2016 in FERC Docket ER16-1231
Schedule Page: 1061 Line No.: 1 Column: e
PacifiCorp's Volume No. 11 Open Access Transmission Tariff
Schedule Page: 1061 Line No.: 2 Column: d
Transmission Formula Rate Annual Update Informational Filing of PacifiCorp in FERC Docket
ER11-3643
Schedule Page: 1061 Line No.: 2 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
2016/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
/ /2016/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 / /2016/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)
Bancroft 09/20/2016 09/20/2026 —
Newdale 11/01/2016 11/01/2031 —
Lava Hot Springs 08/09/2016 08/09/2036 —
Oregon(3)
Canyonville 10/27/2016 10/27/2021 5.0%
Joseph 06/03/2016 06/03/2036 3.5%
Powers 01/08/2016 12/31/2025 5.0%
Roseburg 07/01/2016 07/01/2026 9.0%
Winston 08/01/2016 08/01/2026 7.0%
Utah(4)
Amalga 06/08/2016 06/08/2026 —
Bear River 04/14/2016 04/14/2021 —
Box Elder County 09/28/2016 09/28/2026 —
Cache County 05/04/2016 05/04/2026 —
Centerville 10/25/2016 12/31/2021 —
Clarkston 01/11/2016 01/11/2031 —
Fielding 10/18/2016 10/18/2026 —
Glenwood 02/15/2016 02/15/2026 —
Helper 09/28/2016 09/28/2026 —
Honeyville 01/11/2016 01/11/2026 —
Marysvale 11/21/2016 11/21/2036 —
Mendon 05/24/2016 05/24/2026 —
Newton 11/01/2016 11/01/2031 —
North Salt Lake 06/30/2016 06/30/2021 —
Ogden 01/01/2016 01/01/2041 —
Salt Lake City 12/01/2016 12/01/2021 —
Sandy 02/05/2016 02/05/2026 —
Springdale 10/12/2016 03/31/2017 —
Utah County 05/04/2016 05/04/2066 —
Washington County 05/24/2016 05/24/2036 —
West Haven 04/29/2016 04/29/2026 —
Washington(4)
None
Wyoming(5)
Frannie 12/07/2016 12/07/2041 4.0%
Hudson 10/25/2016 10/25/2033 4.0%
Lovell 05/03/2016 05/03/2041 2.0%
(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
2016/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.1
ITEM 2.
None.
ITEM 3.
In December 2016, PacifiCorp finalized an agreement with the Navajo Nation Council and President of the Navajo Nation for the sale
of certain facilities located in San Juan County, Utah to the Navajo Tribal Utility Authority ("NTUA"). As a result, PacifiCorp
transferred assets, substantially consisting of distribution facilities, serving approximately 1,200 customers on the Navajo Nation
Reservation to the NTUA. PacifiCorp filed with the Utah Public Service Commission ("UPSC"), Wyoming Public Service
Commission ("WPSC") and Oregon Public Utility Commission ("OPUC") to approve the sale of certain facilities, including a power
supply agreement with the NTUA for PacifiCorp to sell power to the NTUA, effective after the close of the sale and commission
approval. Subsequently, PacifiCorp recorded the sale in Account 102, Electric plant purchased or sold. In April 2017, PacifiCorp filed
with the Federal Energy Regulatory Commission ("FERC") to approve the journal entries required by the Uniform System of
Accounts in Docket No. AC17-85-000. Commission authorizations and notifications are as follows:
WPSC – Docket No. 20000-487-EA-15, August 2016.
OPUC – Docket No. UP 337, Order No. 16-241, July 2016.
UPSC – Docket No. 15-035-84, June 2016.
Idaho Public Utilities Commission ("IPUC") – Advisory Letter to Case No. PAC-E-15-17, January 2016.
In October 2016, PacifiCorp consummated the exchange of certain transmission facilities with Western Area Power Administration
("WAPA"), in which PacifiCorp acquired from WAPA certain 230kV transmission assets located at the Thermopolis Substation in
Wyoming in exchange for selling to WAPA certain 230kV transmission assets located at the Spence Substation in Wyoming.
Commission authorizations and notifications are as follows:
OPUC – Docket No. UP 342, Order No. 16-328, August 2016.
WPSC – Docket No. 20000-496-EA-16, August 2016.
California Public Utilities Commission ("CPUC") – Advice Letter 542-E, July 2016.
FERC – Docket No. EC16-113-000, May 2016.
In April 2016, PacifiCorp acquired certain 46kV transmission facilities located in or near Fillmore, Utah and associated electric plant
from Flowell Electric Association, Inc. and recorded the transaction in Account 102, Electric plant purchased or sold. In August 2016,
the FERC approved the journal entries required by the Uniform System of Accounts in Docket No. AC16-151-000 as filed by
PacifiCorp in July 2016. Accordingly, PacifiCorp cleared Account 102, Electric plant purchased or sold and recorded the acquisition
to the appropriate accounts. Commission authorization is as follows:
FERC – Docket No. EC16-57-000, February 2016.
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 May 2016, the FERC approved the journal entries required by the Uniform System of Accounts in Docket No.
AC16-46-000 as filed by PacifiCorp in February 2016. Accordingly, PacifiCorp cleared Account 102, Electric plant purchased or sold
and recorded the sale to the appropriate accounts. Commission authorizations are as follows:
WPSC – Docket No. 20000-475-EA-15, September 2015.
OPUC – Docket No. UP 325, Order No. 15-151, May 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
2016/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.2
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.
Subsequently, PacifiCorp recorded the exchange in Account 102, Electric plant purchased or sold. In September 2016, the FERC
approved the journal entries required by the Uniform System of Accounts in Docket No. AC16-104-000 as filed by PacifiCorp in
April 2016 and supplemented in July 2016. Accordingly, PacifiCorp cleared Account 102, Electric plant purchased or sold and
recorded the exchange to the appropriate accounts. Commission authorizations and notifications are as follows:
UPSC – Docket No. 14-035-150, October 2015.
Washington Utilities and Transportation Commission ("WUTC") – Docket No. UE-144136, September 2015.
CPUC – Decision 15-08-037, Application 14-12-022, August 2015.
WPSC – Docket No. 20000-465-EA-14, August 2015.
FERC – Docket No. EC15-54-000, ER15-680-000 and ER15-681-000, June 2015.
IPUC – Case No. PAC-E-14-11, Order No. 33313, June 2015.
OPUC – Docket No. UP 315, Order No. 15-184, June 2015.
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 December 2016, the FERC approved the journal entries required by the Uniform
System of Accounts in Docket No. AC15-163-000 as filed by PacifiCorp in July 2015 and supplemented in April 2016. Accordingly,
PacifiCorp cleared Account 102, Electric plant purchased or sold and recorded the sale to the appropriate accounts. Commission
authorizations and notifications are as follows:
OPUC – Docket No. UP 312, Order No. 15-071, March 2015.
WPSC – Docket No. 20000-459-EA-14, January 2015.
IPUC – Notification letter, November 2014.
ITEM 4.
None.
ITEM 5.
In April 2017, PacifiCorp filed its 2017 Integrated Resource Plan ("IRP") with state commissions. The IRP includes investments in
renewable energy resources, upgrades to PacifiCorp’s existing wind fleet and energy efficiency measures to meet future customer
needs. The $3.5 billion plan set to be in place by 2020, also incorporates building an additional transmission line segment to facilitate
the expansion of wind generation.
In December 2016, PacifiCorp finalized an agreement with the Navajo Council and President of the Navajo Nation for the sale of
certain facilities located in San Juan County, Utah to the Navajo Tribal Utility Authority. As a result, PacifiCorp transferred
approximately 30 miles of transmission lines, along with distribution lines and four substations, serving approximately 1,200
customers on the Navajo Nation Reservation.
Refer to pages 424-425, Transmission lines added or altered during the year, in this Form No. 1 for additional information regarding
transmission lines added or removed during the year ended December 31, 2016.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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. As of December 31, 2016, PacifiCorp had $270 million of
short-term debt outstanding at a weighted average interest rate of 0.96%.
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:
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.
OPUC – Docket No. UF-4120, Order No. 98-158, dated April 16, 1998.
WUTC – Docket No. UE-980404, dated April 8, 1998.
For further discussion, refer to Note 6 of Notes to Financial Statements in this Form No. 1.
Long-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 future
issuances are as follows:
IPUC – Case No. PAC-E-14-05, Order No. 33083, dated July 29, 2014, effective through June 30, 2019.
OPUC – Docket No. UF-4288, Order No. 14-268, dated July 22, 2014.
As of December 31, 2016, PacifiCorp had $255 million of letters of credit providing credit enhancement and liquidity support for
variable-rate tax-exempt bond obligations totaling $251 million plus interest. These letters of credit were fully available as of
December 31, 2016 and expire periodically through March 2019. For further discussion, refer to Note 6 of Notes to Financial
Statements in this Form No. 1.
PacifiCorp's Mortgage and Deed of Trust creates a lien on most of PacifiCorp's electric utility property, allowing the issuance of
bonds based on a percentage of utility property additions, bond credits arising from retirement of previously outstanding bonds or
deposits of cash. The amount of bonds that PacifiCorp may issue generally is also subject to a net earnings test. As of December 31,
2016, PacifiCorp estimated it would be able to issue up to $9.7 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
2016/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, 2016, PacifiCorp's bargaining unit wage scale changes were as follows:
% Effective Estimated Annual
Unions Represented Increase (1) Date(s)Financial Impact (2)
IBEW 57 Combustion Turbine (UT) 1.87% 01/26/2016 $ 55,112
IBEW 57 Laramie (WY) 1.03% 06/26/2016 5,617
IBEW 57 Power Delivery (UT, ID & WY) 1.84% 01/26/2016 1,428,626
IBEW 57 Power Supply (UT, ID & WY) 1.87% 01/26/2016 686,990
IBEW 125 (OR, WA) 1.90% 01/26/2016 478,574
IBEW 659 (OR, CA) 1.37% 04/26/2016 436,584
UWUA 127 (WY) 0.53% 09/26/2016 239,645
UWUA 197 (OR) 1.21% 05/26/2016 17,936
Total $ 3,349,084
(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.
Subsequent to December 31, 2016, PacifiCorp received $1.7 million in dividends from Fossil Rock Fuels, LLC, a wholly owned
subsidiary of PacifiCorp, as of April 3, 2017.
For the year ended December 31, 2016, Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp, declared and paid dividends
of $55 million to PacifiCorp. In addition, Fossil Rock Fuels, LLC, a wholly owned subsidiary of PacifiCorp, declared and paid
dividends of $3.4 million consisting of $1.4 million unappropriated retained earnings distribution and $2.0 million return of capital 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, 2016, other than preferred
and common stock dividends declared and paid.
ITEM 11.
(Reserved.)
ITEM 12.
None.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.5
ITEM 13.
Nikki L. Kobliha, Vice President and Chief Financial Officer was elected as a director of PacifiCorp and appointed as PacifiCorp’s
Treasurer effective February 1, 2017.
Douglas L. Anderson, Chief Corporate Counsel of Berkshire Hathaway Energy Company, resigned as a director of PacifiCorp
effective January 13, 2017.
Andrea L. Kelly, Senior Vice President, Legislative and Regulatory Strategy of Berkshire Hathaway Energy Company, resigned as a
director of PacifiCorp effective December 31, 2016.
R. Patrick Reiten, President and Chief Executive Officer of PacifiCorp Transmission, resigned as a director and officer of PacifiCorp
effective December 31, 2016 and was appointed Senior Vice President of Government Relations for Berkshire Hathaway Energy
Company effective January 1, 2017.
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
2016/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 / /2016/Q4
UTILITY PLANT 1
27,271,434,702 26,729,137,536200-201Utility Plant (101-106, 114) 2
655,882,614 628,213,113200-201Construction Work in Progress (107) 3
27,927,317,316 27,357,350,649TOTAL Utility Plant (Enter Total of lines 2 and 3) 4
9,693,954,266 9,237,522,532200-201(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5
18,233,363,050 18,119,828,117Net 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
18,233,363,050 18,119,828,117Net 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
13,733,068 13,824,869Nonutility Property (121) 18
2,987,502 3,032,392(Less) Accum. Prov. for Depr. and Amort. (122) 19
69,928 69,928Investments in Associated Companies (123) 20
200,451,214 241,143,969224-225Investment 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
99,989,115 89,802,688Other Investments (124) 24
0 0Sinking Funds (125) 25
0 0Depreciation Fund (126) 26
0 0Amortization Fund - Federal (127) 27
6,428,837 15,562,725Other Special Funds (128) 28
0 0Special Funds (Non Major Only) (129) 29
2,153,282 0Long-Term Portion of Derivative Assets (175) 30
0 0Long-Term Portion of Derivative Assets – Hedges (176) 31
319,837,942 357,371,787TOTAL 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
14,877,880 5,873,910Cash (131) 35
8,880,097 0Special Deposits (132-134) 36
0 0Working Fund (135) 37
32,867 33,910Temporary Cash Investments (136) 38
2,458,965 10,055,988Notes Receivable (141) 39
388,665,430 400,806,409Customer Accounts Receivable (142) 40
43,345,202 42,519,736Other Accounts Receivable (143) 41
7,116,112 7,006,495(Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42
1,673,326 0Notes Receivable from Associated Companies (145) 43
24,733,333 23,759,933Accounts Receivable from Assoc. Companies (146) 44
214,693,832 192,305,988227Fuel Stock (151) 45
0 0227Fuel Stock Expenses Undistributed (152) 46
0 0227Residuals (Elec) and Extracted Products (153) 47
228,261,286 233,132,093227Plant 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 / /2016/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
65,837,449 57,531,155Prepayments (165) 57
0 0Advances for Gas (166-167) 58
0 0Interest and Dividends Receivable (171) 59
1,658,607 1,485,898Rents Receivable (172) 60
274,945,000 244,424,000Accrued Utility Revenues (173) 61
0 131,614Miscellaneous Current and Accrued Assets (174) 62
20,541,832 8,433,083Derivative Instrument Assets (175) 63
2,153,282 0(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
1,281,335,712 1,213,487,222Total Current and Accrued Assets (Lines 34 through 66) 67
DEFERRED DEBITS 68
29,888,534 33,071,963Unamortized Debt Expenses (181) 69
0 0230aExtraordinary Property Losses (182.1) 70
0 0230bUnrecovered Plant and Regulatory Study Costs (182.2) 71
1,538,109,950 1,679,069,828232Other Regulatory Assets (182.3) 72
978,052 973,951Prelim. 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
-21,901 23,727Temporary Facilities (185) 77
61,472,266 70,244,403233Miscellaneous Deferred Debits (186) 78
0 0Def. Losses from Disposition of Utility Plt. (187) 79
0 0352-353Research, Devel. and Demonstration Expend. (188) 80
5,779,388 6,351,794Unamortized Loss on Reaquired Debt (189) 81
541,859,343 606,211,204234Accumulated Deferred Income Taxes (190) 82
0 0Unrecovered Purchased Gas Costs (191) 83
2,178,065,632 2,395,946,870Total Deferred Debits (lines 69 through 83) 84
22,012,602,336 22,086,633,996TOTAL ASSETS (lines 14-16, 32, 67, and 84) 85
FERC FORM NO. 1 (REV. 12-03) Page 111
Schedule Page: 110 Line No.: 43 Column: c
Represents amounts due from Pacific Minerals, Inc., a wholly owned subsidiary of
PacifiCorp, pursuant to an umbrella loan agreement for which the interest rate is
determined daily and is equal to the lowest cost of short-term borrowings PacifiCorp could
otherwise incur externally. At December 31, 2016, the interest rate on the outstanding
loan balance was 0.96%.
Schedule Page: 110 Line No.: 44 Column: c
As of December 31, 2016, Account 146, Accounts receivable from associated companies,
included $18,474,407 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, 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.: 77 Column: c
The credit balance represents a timing difference between work incurred and advances
received from customers.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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 / /2016/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
2,877,592,4342,803,600,023Retained Earnings (215, 215.1, 216) 11 118-119
155,605,539116,946,442Unappropriated Undistributed Subsidiary Earnings (216.1) 12 118-119
00(Less) Reaquired Capital Stock (217) 13 250-251
00 Noncorporate Proprietorship (Non-major only) (218) 14
-12,014,638-12,594,198Accumulated Other Comprehensive Income (219) 15 122(a)(b)
7,502,489,7267,389,258,658Total Proprietary Capital (lines 2 through 15) 16
LONG-TERM DEBT 17
7,159,339,0007,093,197,000Bonds (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
69,10058,074Unamortized Premium on Long-Term Debt (225) 22
12,502,20611,483,368(Less) Unamortized Discount on Long-Term Debt-Debit (226) 23
7,146,905,8947,081,771,706Total Long-Term Debt (lines 18 through 23) 24
OTHER NONCURRENT LIABILITIES 25
30,062,42921,090,034Obligations Under Capital Leases - Noncurrent (227) 26
00Accumulated Provision for Property Insurance (228.1) 27
26,550,966-1,507,842Accumulated Provision for Injuries and Damages (228.2) 28
336,117,800364,084,317Accumulated Provision for Pensions and Benefits (228.3) 29
37,102,44436,933,054Accumulated Miscellaneous Operating Provisions (228.4) 30
58,1730Accumulated Provision for Rate Refunds (229) 31
32,083,86425,100,250Long-Term Portion of Derivative Instrument Liabilities 32
00Long-Term Portion of Derivative Instrument Liabilities - Hedges 33
224,250,680214,786,003Asset Retirement Obligations (230) 34
686,226,356660,485,816Total Other Noncurrent Liabilities (lines 26 through 34) 35
CURRENT AND ACCRUED LIABILITIES 36
20,000,000270,000,000Notes Payable (231) 37
445,603,914377,797,383Accounts Payable (232) 38
15,242,6740Notes Payable to Associated Companies (233) 39
140,098,106148,165,802Accounts Payable to Associated Companies (234) 40
45,700,12045,984,008Customer Deposits (235) 41
41,847,69442,398,601Taxes Accrued (236) 42 262-263
119,224,245118,648,155Interest 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 / /2016/Q4
(continued)COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
00Matured Interest (240) 46
20,333,46220,497,658Tax Collections Payable (241) 47
69,280,61976,469,862Miscellaneous Current and Accrued Liabilities (242) 48
2,207,4365,938,747Obligations Under Capital Leases-Current (243) 49
69,761,28128,451,943Derivative Instrument Liabilities (244) 50
32,083,86425,100,250(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
957,256,1621,109,292,384Total Current and Accrued Liabilities (lines 37 through 53) 54
DEFERRED CREDITS 55
33,717,01932,324,218Customer Advances for Construction (252) 56
22,505,12218,259,559Accumulated Deferred Investment Tax Credits (255) 57 266-267
00Deferred Gains from Disposition of Utility Plant (256) 58
301,476,278176,253,764Other Deferred Credits (253) 59 269
77,876,318115,848,090Other Regulatory Liabilities (254) 60 278
00Unamortized Gain on Reaquired Debt (257) 61
285,986,998306,993,377Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277
4,414,667,3874,518,977,533Accum. Deferred Income Taxes-Other Property (282) 63
657,526,736603,137,231Accum. Deferred Income Taxes-Other (283) 64
5,793,755,8585,771,793,772Total Deferred Credits (lines 56 through 64) 65
22,086,633,99622,012,602,336TOTAL 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.: 28 Column: c
As of December 31, 2016, Account 228.2, Accumulated provision for injuries and damages,
included expected insurance recoveries.
Schedule Page: 112 Line No.: 39 Column: d
Represents amounts due to Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp,
pursuant to an umbrella loan agreement for which the interest rate is determined daily and
is equal to the lowest cost of short-term borrowings PacifiCorp could otherwise incur
externally. At December 31, 2015, the interest rate on the outstanding loan balance 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
2016/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
/ /2016/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
5,201,080,711 5,235,309,367300-301Operating Revenues (400) 2
Operating Expenses 3
2,446,363,957 2,565,045,913320-323Operation Expenses (401) 4
399,131,517 422,197,831320-323Maintenance Expenses (402) 5
709,094,974 697,031,280336-337Depreciation Expense (403) 6
336-337Depreciation Expense for Asset Retirement Costs (403.1) 7
38,577,000 37,690,560336-337Amort. & Depl. of Utility Plant (404-405) 8
5,083,195 4,989,371336-337Amort. of Utility Plant Acq. Adj. (406) 9
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10
Amort. of Conversion Expenses (407) 11
150,507 437,693Regulatory Debits (407.3) 12
118,750(Less) Regulatory Credits (407.4) 13
189,632,535 185,302,308262-263Taxes Other Than Income Taxes (408.1) 14
199,451,072 121,054,868262-263Income Taxes - Federal (409.1) 15
36,762,420 25,050,102262-263 - Other (409.1) 16
749,775,939 1,039,923,787234, 272-277Provision for Deferred Income Taxes (410.1) 17
645,592,915 861,868,065234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.1) 18
-4,341,401 -4,756,408266Investment 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
188 320(Less) Gains from Disposition of Allowances (411.8) 22
Losses from Disposition of Allowances (411.9) 23
Accretion Expense (411.10) 24
4,124,088,612 4,231,980,170TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25
1,076,992,099 1,003,329,197Net 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
/ /2016/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
5,201,080,711 5,235,309,367 2
3
2,446,363,957 2,565,045,913 4
399,131,517 422,197,831 5
709,094,974 697,031,280 6
7
38,577,000 37,690,560 8
5,083,195 4,989,371 9
10
11
150,507 437,693 12
118,750 13
189,632,535 185,302,308 14
199,451,072 121,054,868 15
36,762,420 25,050,102 16
749,775,939 1,039,923,787 17
645,592,915 861,868,065 18
-4,341,401 -4,756,408 19
20
21
188 320 22
23
24
4,124,088,612 4,231,980,170 25
1,076,992,099 1,003,329,197 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
/ /2016/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)
1,076,992,099 1,003,329,197Net Utility Operating Income (Carried forward from page 114) 27
Other Income and Deductions 28
Other Income 29
Nonutilty Operating Income 30
1,554,611 1,722,065Revenues From Merchandising, Jobbing and Contract Work (415) 31
1,617,614 1,740,032(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32
Revenues From Nonutility Operations (417) 33
72,626 124,007(Less) Expenses of Nonutility Operations (417.1) 34
198,175 187,080Nonoperating Rental Income (418) 35
17,851,891 13,544,949119Equity in Earnings of Subsidiary Companies (418.1) 36
9,486,317 9,749,146Interest and Dividend Income (419) 37
27,450,081 32,841,065Allowance for Other Funds Used During Construction (419.1) 38
1,157,759 478,158Miscellaneous Nonoperating Income (421) 39
1,777,232 1,427,360Gain on Disposition of Property (421.1) 40
57,785,826 58,085,784TOTAL Other Income (Enter Total of lines 31 thru 40) 41
Other Income Deductions 42
29,654 555,201Loss on Disposition of Property (421.2) 43
1,344,292 1,343,975Miscellaneous Amortization (425) 44
2,317,647 2,364,473 Donations (426.1) 45
-6,068,477 -4,497,390 Life Insurance (426.2) 46
25,500 1,526,588 Penalties (426.3) 47
1,710,497 2,593,244 Exp. for Certain Civic, Political & Related Activities (426.4) 48
13,228,391 2,407,771 Other Deductions (426.5) 49
12,587,504 6,293,862TOTAL Other Income Deductions (Total of lines 43 thru 49) 50
Taxes Applic. to Other Income and Deductions 51
280,899 299,513262-263Taxes Other Than Income Taxes (408.2) 52
-41,603,403 4,267,107262-263Income Taxes-Federal (409.2) 53
-5,653,211 579,829262-263Income Taxes-Other (409.2) 54
148,815,498 128,771,334234, 272-277Provision for Deferred Inc. Taxes (410.2) 55
103,275,215 131,834,874234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.2) 56
Investment Tax Credit Adj.-Net (411.5) 57
311,468 553,152(Less) Investment Tax Credits (420) 58
-1,746,900 1,529,757TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59
46,945,222 50,262,165Net Other Income and Deductions (Total of lines 41, 50, 59) 60
Interest Charges 61
359,474,830 356,471,778Interest on Long-Term Debt (427) 62
4,142,215 4,088,677Amort. of Debt Disc. and Expense (428) 63
667,665 832,212Amortization 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
9,137 19,377Interest on Debt to Assoc. Companies (430) 67
12,460,408 14,445,893Other Interest Expense (431) 68
15,316,302 17,591,087(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69
361,426,927 358,255,824Net Interest Charges (Total of lines 62 thru 69) 70
762,510,394 695,335,538Income 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
762,510,394 695,335,538Net 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, 2016 and 2015, depreciation expense associated with transportation
equipment were $14,483,977 and $14,214,593, 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, 2016 and 2015, payroll taxes were
$38,739,981 and $39,835,178, 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
2016/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
/ /
2016/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)
3,135,214,887 2,861,256,994 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)
681,790,589 744,658,503 16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
( 5,674,637) -8,918,577215.1 18 Appropriation of excess earnings at certain hydroelectric generating facilities
19
20
21
( 5,674,637) -8,918,577 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)
( 950,000,000) -875,000,000238 31 Common Stock
32
33
34
35
( 950,000,000) -875,000,000 36 TOTAL Dividends Declared-Common Stock (Acct. 438)
88,057 56,510,988216.1 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
2,861,256,994 2,778,346,006 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
/ /
2016/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)
16,335,440 25,254,017 46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
16,335,440 25,254,017 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
2,877,592,434 2,803,600,023 48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
142,148,647 155,605,539 49 Balance-Beginning of Year (Debit or Credit)
13,544,949 17,851,891 50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
( 88,057) -56,510,988 52 Transfers to/from Unappropriated Retained Earnings (Account 216)
155,605,539 116,946,442 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, 2016 and dividends on preferred
stock during the year ended December 31, 2016, 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, 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.: 37 Column: c
Declared and paid dividends from subsidiaries of PacifiCorp during the year ended December
31, 2016, were as follows:
Pacific Minerals, Inc. $55,000,000
Fossil Rock Fuels, LLC 1,430,267
Trapper Mining Inc. 80,721
$56,510,988
Schedule Page: 118 Line No.: 37 Column: d
In September 2015, Trapper Mining Inc., a subsidiary of PacifiCorp, paid a dividend of
$88,057 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
2016/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
/ /2016/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:
695,335,538 762,510,394 2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
712,627,877 725,220,132 4 Depreciation and Depletion
44,050,122 45,030,703 5 Amortization:
6
7
174,992,182 149,723,307 8 Deferred Income Taxes (Net)
-5,309,560 -4,652,869 9 Investment Tax Credit Adjustment (Net)
-4,106,411 -26,219,152 10 Net (Increase) Decrease in Receivables
-7,282,585 -20,966,443 11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
20,473,475 -166,766,587 13 Net Increase (Decrease) in Payables and Accrued Expenses
48,439,923 105,266,641 14 Net (Increase) Decrease in Other Regulatory Assets
14,305,404 16,847,524 15 Net Increase (Decrease) in Other Regulatory Liabilities
32,841,065 27,450,081 16 (Less) Allowance for Other Funds Used During Construction
13,456,892 -38,659,097 17 (Less) Undistributed Earnings from Subsidiary Companies
117,602,515 5,365,962 18 Amounts Due To/From Affiliates (Net)
-46,700,000 6,300,000 19 Derivative Collateral (Net)
5,756,910 4,212,127 20 Other Operating Activities:
21
1,723,887,433 1,613,080,755 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):
-948,488,007 -930,851,398 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
-32,841,065 -27,450,081 30 (Less) Allowance for Other Funds Used During Construction
-22,770,214 -301,580 31 Other (provide details in footnote):
32
33
-938,417,156 -903,702,897 34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
19,089,066 8,657,775 37 Proceeds from Disposal of Noncurrent Assets (d)
38
-216,000 -1,672,000 39 Investments in and Advances to Assoc. and Subsidiary Companies
2,033,659 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
/ /2016/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
-484,494 -438,149 53 Other Investing Activities:
54
55
56 Net Cash Provided by (Used in) Investing Activities
-920,028,584 -895,121,612 57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
249,680,000 61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
249,910,111 66 Net Increase in Short-Term Debt (c)
15,237,000 67 Other (provide details in footnote):
68
69
264,917,000 249,910,111 70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
-122,199,000 -66,142,000 73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
-2,600,477 -15,921,244 76 Other (provide details in footnote):
-1,382,004 -1,641,181 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
-950,000,000 -875,000,000 81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
-811,427,355 -708,956,216 83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
-7,568,506 9,002,927 86 (Total of lines 22,57 and 83)
87
13,476,326 5,907,820 88 Cash and Cash Equivalents at Beginning of Period
89
5,907,820 14,910,747 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 $16,125,158 and $15,596,597 during the years ended December 31, 2016 and 2015,
respectively.
Schedule Page: 120 Line No.: 5 Column: a
Years Ended December 31,
2016 2015
Amortization of software development & other intangibles $39,921,292 $39,034,535
Amortization of electric plant acquisition adjustments 5,083,195 4,989,371
Amortization of a regulatory asset 26,216 26,216
$45,030,703 $44,050,122
Schedule Page: 120 Line No.: 20 Column: a
Years Ended December 31,
2016 2015
Depreciation and depletion included in cost of fuel $ 2,043,175 $ 1,876,649
Net (gain)/loss on sale of property (1,822,720) 390,138
Write-off of assets under construction 7,170,982 3,748,844
Change in corporate owned life insurance cash surrender
value (6,044,333) (4,474,180)
Amortization of debt issuance expenses and bond
discount/premium 4,131,189 4,077,651
Other (1,266,166) 137,808
$ 4,212,127 $ 5,756,910
Schedule Page: 120 Line No.: 31 Column: b
During the year ended December 31, 2016, the acquisition of certain transmission
facilities and associated electric plant from Flowell Electric Association, Inc., subject
to Commission approval, were as follows:

Account 101, Electric plant in service $ (387,367)
Account 108, Accumulated provision for depreciation of electric utility
plant 85,787
$ (301,580)
Schedule Page: 120 Line No.: 31 Column: c
During the year ended December 31, 2015, the acquisition of Eagle Mountain City
distribution and transmission assets and liabilities were as follows:

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,
2016 2015
Other investments/special funds $ 1,818,766 $ 1,377,796
Temporary facilities 45,628 56,895
Restricted cash 141,908 3,826,237
Investment in long-term incentive plan securities (2,444,451) (5,745,422)
$ (438,149) $ (484,494)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 120 Line No.: 67 Column: c
Net proceeds of affiliate borrowing from subsidiary company, Pacific Minerals, Inc.
Schedule Page: 120 Line No.: 76 Column: a
Years Ended December 31,
2016 2015
Net repayments of affiliate borrowing from subsidiary
company, Pacific Minerals, Inc. $(15,237,000) $ -
Long-term debt issuance and other deferred financing costs (684,244) (2,600,477)
$(15,921,244) $(2,600,477)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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 Year/Period of Report
End of
NOTES TO FINANCIAL STATEMENTS
PacifiCorp X / /2016/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 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.1
Interest and penalties on income taxes for GAAP are classified as income tax expense. All such amounts are classified as
interest income, interest expense and penalties under the FERC accounting and reporting standards.
Reclassifications
Certain other reclassifications of balance sheet, income statement and cash flow amounts have been made in order to
conform to the FERC basis of presentation. These reclassifications had no effect on net income.
Use of Estimates in Preparation of Financial Statements
The preparation of the financial statements in conformity with 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
2016/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):
2016 2015
Cash (131) $ 15 $ 6
Temporary cash investments (136) — —
Total cash and cash equivalents $15 $6
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, 2016 and 2015,
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):
2016 2015
Beginning balance $ 7 $ 7
Charged to operating costs and expenses, net 12 10
Write-offs, net (12) (10)
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.3
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 liabilities or assets. For a derivative contract not probable of inclusion in rates, changes in the fair value are
recognized in earnings.
Inventories
Inventories consist of materials and supplies, coal stocks, natural gas and fuel oil, which are stated at the lower of average cost or 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.4
Impairment
PacifiCorp evaluates long-lived assets for impairment, including utility plant, when events or changes in circumstances indicate that
the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering
event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the
residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated
recoverable amounts, the carrying value is written down to the estimated fair value and any resulting impairment loss is reflected on
the Statement of Income. The impacts of regulation are considered when evaluating the carrying value of regulated assets.
Revenue Recognition
Revenue is recognized as electricity is delivered or services are provided. Revenue recognized includes billed and unbilled amounts.
As of December 31, 2016 and 2015, unbilled revenue was $275 million and $245 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.
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
$421 million and $437 million as of December 31, 2016 and 2015, respectively, and regulatory liabilities of $9 million and
$12 million as of December 31, 2016 and 2015, 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.5
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.
New Accounting Pronouncements
In March 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-07,
which amends FASB Accounting Standards Codification ("ASC") Subtopic 715, "Compensation – Retirement Benefits." The
amendments in this guidance require that an employer disaggregate the service component from the other components of net benefit
cost. Employers should report the service cost component in the same line item or items as other compensation costs arising from
services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented
in the income statement separately from the service cost component and outside a subtotal of income from operations, if one is
presented. Additionally, the guidance will only allow the service cost component of net benefit cost to be eligible for capitalization
when applicable. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early
adoption permitted, and is required to be adopted retrospectively. PacifiCorp is currently evaluating the impact of adopting this
guidance on its financial statements and disclosures included within Notes to Financial Statements.
In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, "Statement of Cash Flows -
Overall." The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of
cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described
as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the
beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and
annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted
retrospectively. PacifiCorp is currently evaluating the impact of adopting this guidance on its financial statements and disclosures
included within Notes to Financial Statements.
In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The
amendments in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the
objective of reducing the existing diversity in practice. This guidance is effective for interim and annual reporting periods beginning
after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. PacifiCorp is currently
evaluating the impact of adopting this guidance on its financial statements.
In February 2016, the FASB issued ASU No. 2016-02, which creates FASB ASC Topic 842, "Leases" and supersedes Topic 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 balance sheet 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.6
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. The impact of this update is immaterial to PacifiCorp's 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. During 2016, the FASB issued several ASUs that clarify the
implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. 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. PacifiCorp currently does not expect the timing and amount of revenue currently recognized to be
materially different after adoption of the new guidance as a majority of revenue is recognized equal to what PacifiCorp has the right to
invoice as it corresponds directly with the value to the customer of PacifiCorp’s performance to date. PacifiCorp’s current plan is to
quantitatively disaggregate revenue in the required financial statement footnote by customer class and jurisdiction.
Subsequent Events
PacifiCorp has evaluated the impact of events occurring after December 31, 2016 up to February 24, 2017, 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 14, 2017. 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%, for the years ended December 31, 2016
and 2015.
(4) Jointly Owned Utility Facilities
Under joint facility ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly
owned generation, transmission and distribution facilities. PacifiCorp accounts for its proportionate share of each facility, and each
joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on
their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the
Statement of Income include PacifiCorp's share of the expenses of these facilities.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.7
The amounts shown in the table below represent PacifiCorp's share in each jointly owned facility as of December 31, 2016
(dollars in millions):
Facility Accumulated Construction
PacifiCorp in Depreciation and Work-in-
Share Service Amortization Progress
Jim Bridger Nos. 1 - 4 67% $ 1,420 $ 586 $ 10
Hunter No. 1 94 473 157 1
Hunter No. 2 60 296 96 —
Wyodak 80 467 197 1
Colstrip Nos. 3 and 4 10 244 132 5
Hermiston 50 178 76 2
Craig Nos. 1 and 2 19 325 226 32
Hayden No. 1 25 74 32 —
Hayden No. 2 13 43 20 —
Foote Creek 79 39 25 —
Transmission and distribution facilities Various 777 275 61
Total $4,336 $1,822 $112
(5) Regulatory Matters
Regulatory Assets
PacifiCorp had regulatory assets not earning a return on investment of $1.013 billion and $1.096 billion as of December 31, 2016 and
2015, respectively.
Utah Mine Disposition
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 2015, PacifiCorp received approval from the commissions.
In December 2014, PacifiCorp filed an advice letter with the California Public Utility Commission ("CPUC") to request approval to
sell certain Utah mining assets and to establish memorandum accounts to track the costs associated with the Utah Mine Disposition
for future recovery. 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.
On February 6, 2017, a joint motion was filed with the CPUC seeking approval of a settlement agreement reached by PacifiCorp and
all other parties. The agreement states, among other things, that the decision to sell certain Utah mining assets is in the public
interest. Parties also reserve their rights to additional testimony, briefs, and hearings to the extent the CPUC determines that
additional California Environmental Quality Act proceedings are necessary. A CPUC decision on the joint motion and settlement
agreement is expected in 2017.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.8
(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):
2016:
Credit facilities $ 1,000
Less:
Short-term debt (270)
Tax-exempt bond support (142)
Net credit facilities $588
2015:
Credit facilities $ 1,200
Less:
Short-term debt (20)
Tax-exempt bond support and letters of credit (160)
Net credit facilities $1,020
PacifiCorp has a $600 million unsecured credit facility expiring in March 2018 and a $400 million unsecured credit facility with a
stated maturity of June 2019 and which has two one-year extension options subject to bank consent. 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, 2016 and
2015, the weighted average interest rate on commercial paper borrowings outstanding was 0.96% and 0.65%, 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, 2016, PacifiCorp was in compliance with the covenants of its credit
facilities.
As of December 31, 2016 and 2015, PacifiCorp had $255 million and $310 million, respectively, of fully available letters of credit
issued under committed arrangements, of which $10 million as of December 31, 2015 were issued under the credit facilities. These
letters of credit support PacifiCorp's variable-rate tax-exempt bond obligations and expire through March 2019.
As of December 31, 2016, PacifiCorp had approximately $14 million of additional letters of credit issued on its behalf to provide
credit support for certain transactions as required by third parties. These letters of credit were all undrawn as of December 31, 2016
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.
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.9
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's
mortgage. Approximately $26 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage
as of December 31, 2016.
PacifiCorp has entered into long-term agreements that qualify as capital leases and expire at various dates through March 2035 for
transportation services, a power purchase agreement 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
$27 million and $32 million as of December 31, 2016 and 2015, respectively, were included in net utility plant in the Comparative
Balance Sheet.
As of December 31, 2016, the annual principal maturities of long-term debt and total capital lease obligations for 2017 and thereafter
are as follows (in millions):
Long-term Capital Lease
Debt Obligations Total
2017 $ 52 $ 9 $ 61
2018 586 4 590
2019 350 4 354
2020 38 3 41
2021 420 6 426
Thereafter 5,647 20 5,667
Total 7,093 46 7,139
Unamortized discount (11) — (11)
Amounts representing interest —(19)(19)
Total $7,082 $27 $7,109
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.10
(8) Income Taxes
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
2016 2015
Current:
Federal $ 158 $ 125
State 31 26
Total 189 151
Deferred:
Federal 129 146
State 21 29
Total 150 175
Investment tax credits (5) (5)
Total income tax expense $334 $321
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:
2016 2015
Federal statutory income tax rate 35% 35%
State income taxes, net of federal income tax benefit 3 3
Federal income tax credits (6) (6)
Other (2) —
Effective income tax rate 30%32%
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.11
The net deferred income tax liability consists of the following as of December 31 (in millions):
2016 2015
Deferred income tax assets:
Employee benefits $ 202 $ 190
Derivative contracts and unamortized contract values 67 94
State carryforwards 69 69
Loss contingencies — 56
Asset retirement obligations 78 81
Regulatory liabilities 44 30
Other 82 86
542 606
Deferred income tax liabilities:
Property, plant and equipment (4,826) (4,701)
Regulatory assets (586) (639)
Other (17)(18)
(5,429)(5,358)
Net deferred income tax liability $(4,887)$(4,752)
The following table provides PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December 31,
2016 (in millions):
State
Net operating loss carryforwards $ 1,415
Deferred income taxes on net operating loss carryforwards $ 52
Expiration dates 2017 - 2032
Tax credit carryforwards $ 17
Expiration dates 2017 - indefinite
The United States Internal Revenue Service has closed its examination of PacifiCorp's income tax returns through December 31,
2009. The statute of limitations for PacifiCorp's state income tax returns have expired through December 31, 2009, with the exception
of California, Oregon and Utah, for which the statute of limitations have expired through March 31, 2006.
(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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.12
Pension and Other Postretirement Benefit Plans
PacifiCorp's pension plans include non-contributory defined benefit pension plans, collectively 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. 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 earned benefits based on a cash balance formula
through December 31, 2016. Effective January 1, 2017, non-union employee participants with a cash balance benefit in the
Retirement Plan are no longer eligible to receive pay credits in their 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. The SERP was closed to new
participants as of March 21, 2006 and froze future accruals for active participants as of December 31, 2014.
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" for further information regarding the withdrawal.
Net Periodic Benefit Cost
For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets
is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the
first year in which they occur.
Net periodic benefit cost for the plans included the following components for the years ended December 31 (in millions):
Pension Other Postretirement
2016 2015 2016 2015
Service cost $ 4 $ 4 $ 2 $ 3
Interest cost 54 53 15 16
Expected return on plan assets (75) (77) (21) (23)
Net amortization 34 42 (5) (4)
Net period benefit cost (credit)$17 $22 $(9)$(8)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.13
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
2016 2015 2016 2015
Plan assets at fair value, beginning of year $ 1,043 $ 1,146 $ 305 $ 482
Employer contributions 5 4 1 1
Participant contributions — — 6 6
Actual return on plan assets 51 — 17 1
Settlement — — — (150)
Benefits paid (100) (107) (27) (35)
Plan assets at fair value, end of year $999 $1,043 $302 $305
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
Pension Other Postretirement
2016 2015 2016 2015
Benefit obligation, beginning of year $ 1,289 $ 1,378 $ 362 $ 539
Service cost 4 4 2 3
Interest cost 54 53 15 16
Participant contributions — — 6 6
Actuarial (gain) loss 29 (39) — (17)
Settlement — — — (150)
Benefits paid (100) (107) (27) (35)
Benefit obligation, end of year $1,276 $1,289 $358 $362
Accumulated benefit obligation, end of year $1,276 $1,289
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.14
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
2016 2015 2016 2015
Plan assets at fair value, end of year $ 999 $ 1,043 $ 302 $ 305
Less - Benefit obligation, end of year 1,276 1,289 358 362
Funded status $(277)$(246)$(56)$(57)
Amounts recognized on the Comparative Balance Sheet:
Miscellaneous current and accrued liabilities $ (5) $ (4) $ — $ —
Accumulated provision for pension and benefits (272) (242) (56) (57)
Amounts recognized $(277)$(246)$(56)$(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
$55 million and $52 million as of December 31, 2016 and 2015, respectively. These assets are not included in the plan assets in the
above table, but are reflected in other investments on the Comparative Balance Sheet.
Unrecognized Amounts
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in
millions):
Pension Other Postretirement
2016 2015 2016 2015
Net loss $ 518 $ 508 $ 39 $ 36
Prior service credit — (13) (13) (19)
Regulatory deferrals (7) (3) 8 9
Total $511 $492 $34 $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
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.15
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2016
and 2015 is as follows (in millions):
Accumulated
Other
Regulatory Comprehensive
Asset Loss Total
Pension
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
Net loss arising during the year 51 2 53
Net amortization (33)(1)(34)
Total 18 1 19
Balance, December 31, 2016 $491 $20 $511
Regulatory
Asset
Other Postretirement
Balance, December 31, 2014 $17
Net loss arising during the year 5
Net amortization 4
Total 9
Balance, December 31, 2015 26
Net loss arising during the year 3
Net amortization 5
Total 8
Balance, December 31, 2016 $34
The net loss, prior service credit and regulatory deferrals that will be amortized in 2017 into net periodic benefit cost are estimated to
be as follows (in millions):
Net Prior Service Regulatory
Loss Credit Deferrals Total
Pension $ 16 $ — $ (2) $ 14
Other postretirement —(7) 1 (6)
Total $16 $(7)$(1)$8
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.16
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
Pension Other Postretirement
2016 2015 2016 2015
Benefit obligations as of December 31:
Discount rate 4.05% 4.40% 4.05% 4.35%
Rate of compensation increase N/A 2.75 N/A N/A
Net periodic benefit cost for the years ended December 31:
Discount rate 4.40% 4.00% 4.35% 3.99%
Expected return on plan assets 7.50 7.50 7.50 7.08
Rate of compensation increase 2.75 2.75 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 a plan amendment effective on January 1, 2017, the benefit obligation for the Retirement Plan is no longer affected by
future increases in compensation. 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.
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $5 million and $- million,
respectively, during 2017. Funding to PacifiCorp's Retirement Plan trust is based upon the actuarially determined costs of the plan and
the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 ("ERISA") and the Pension
Protection Act of 2006, as amended ("PPA"). PacifiCorp considers contributing additional amounts from time to time in order to
achieve certain funding levels specified under the PPA. PacifiCorp's funding policy for its other postretirement benefit plan is to
generally contribute an amount equal to the net periodic benefit cost, subject to tax deductibility limitations and other considerations.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.17
The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2017 through 2021
and for the five years thereafter are summarized below (in millions):
Projected Benefit Payments
Pension Other Postretirement
2017 $ 105 $ 28
2018 109 28
2019 108 27
2020 104 30
2021 97 26
2022-2026 426 116
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, 2016:
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.
Fair Value Measurements
PacifiCorp adopted ASU No. 2015-07, "Fair Value Measurement (Topic 820) - Disclosures for Investments in Certain Entities that
Calculate Net Asset Value per Share (or its Equivalent)" effective January 1, 2016 under a retrospective method.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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 pension plan (in
millions):
Input Levels for Fair Value Measurements
Level 1(1)Level 2(1)Level 3(1)Total
As of December 31, 2016:
Cash equivalents $ — $ 10 $ — $ 10
Debt securities:
United States government obligations 25 — — 25
Corporate obligations — 36 — 36
Municipal obligations — 6 — 6
Agency, asset and mortgage-backed obligations — 37 — 37
Equity securities:
United States companies 389 — — 389
International companies 15 — — 15
Investment funds(2)83 — — 83
Total assets in the fair value hierarchy $512 $89 $—601
Investment funds(2) measured at net asset value 337
Limited partnership interests(3) measured at net asset value 61
Investments at fair value $999
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 — — 83
Total assets in the fair value hierarchy $527 $100 $—627
Investment funds(2) measured at net asset value 351
Limited partnership interests(3) measured at net asset value 65
Investments at fair value $1,043
(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
54% and 46% respectively, for 2016 and 53% and 47%, respectively, for 2015, and are invested in United States and international securities of
approximately 39% and 61%, respectively, for 2016 and 40% and 60%, respectively, for 2015.
(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
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.19
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, 2016:
Cash and cash equivalents $ 4 $ 1 $ — $ 5
Debt securities:
United States government obligations 11 — — 11
Corporate obligations — 13 — 13
Municipal obligations — 2 — 2
Agency, asset and mortgage-backed obligations — 13 — 13
Equity securities:
United States companies 93 — — 93
International companies 4 — — 4
Investment funds(2)32 ——32
Total assets in the fair value hierarchy $144 $29 $—173
Investment funds(2) measured at net asset value 125
Limited partnership interests(3) measured at net asset value 4
Investments at fair value $302
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 — — 32
Total assets in the fair value hierarchy $144 $31 $—175
Investment funds(2) measured at net asset value 126
Limited partnership interests(3) measured at net asset value 4
Investments at fair value $305
(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
62% and 38%, respectively, for 2016 and 61% and 39%, respectively, for 2015, and are invested in United States and international securities of
approximately 71% and 29%, respectively, for 2016 and 67% and 33%, respectively, for 2015.
(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
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.20
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 based on observable market inputs.
Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and
commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for
expedience purposes. A fund’s net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.
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. PacifiCorp recorded its estimate of the withdrawal obligation in December 2014 when withdrawal was
considered probable and deferred the portion of the obligation considered probable of recovery to a regulatory asset. PacifiCorp has
subsequently revised its estimate due to changes in facts and circumstances for a withdrawal occurring by July 2015. As
communicated in a letter received in August 2016, the plan trustees have determined a withdrawal liability of $115 million. Energy
West Mining Company began making installment payments in November 2016 and has the option to elect a lump sum payment to
settle the withdrawal obligation. The ultimate amount paid by Energy West Mining Company to settle the obligation is dependent on a
variety of factors, including the results of ongoing negotiations with the plan trustees.
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
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.21
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 2016 2015
Funding
improvement
plan
Surcharge
imposed
under PPA(1)2016 2015
Year contributions to plan
exceeded more than 5% of
total contributions(2)
UMWA
1974
Pension Plan 52-1050282
Critical and
Declining
Critical and
Declining Implemented Yes $—$1 None
Local 57
Trust Fund 87-0640888 At least 80% At least 80% None None $ 8 $ 8 2015, 2014
(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 years beginning July 1, 2014 and 2013. Information for the plan year beginning July 1, 2015 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 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, as of January 1, 2017, all 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 $34 million
and $35 million and for the years ended December 31, 2016 and 2015, 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
$917 million and $894 million as of December 31, 2016 and 2015, 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
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.22
The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 31
(in millions):
2016 2015
Beginning balance $ 224 $ 135
Change in estimated costs 2 62
Additions — 30
Retirements (19) (10)
Accretion 8 7
Ending balance $215 $224
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, manage, mitigate, monitor and report, 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.23
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.
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, 2016:
Not designated as hedging contracts(1):
Commodity assets $ 24 $ 2 $ 1 $ — $ 27
Commodity liabilities (6)— (14) (84)(104)
Total 18 2 (13)(84)(77)
Total derivatives 18 2 (13) (84) (77)
Cash collateral receivable — — 10 59 69
Total derivatives - net basis $18 $2 $(3)$(25)$(8)
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)
(1) PacifiCorp's commodity derivatives are generally included in rates and as of December 31, 2016 and 2015, a regulatory asset of $73 million and
$133 million, respectively, was recorded related to the net derivative liability of $77 million and $136 million, respectively.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.24
The following table reconciles the beginning and ending balances of PacifiCorp's 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):
2016 2015
Beginning balance $ 133 $ 85
Changes in fair value recognized in regulatory assets (27) 82
Net gains reclassified to operating revenue 10 40
Net losses reclassified to energy costs (43) (74)
Ending balance $73 $133
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 2016 2015
Electricity (sales) purchases Megawatt hours (3) 1
Natural gas purchases Decatherms 84 111
Fuel oil purchases Gallons 11 11
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, 2016, PacifiCorp's credit ratings from the three recognized
credit rating agencies were investment grade.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.25
The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features
totaled $97 million and $142 million as of December 31, 2016 and 2015, respectively, for which PacifiCorp had posted collateral of
$69 million and $75 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, 2016 and 2015, PacifiCorp would have been required to post
$22 million and $64 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, 2016 and December 31, 2015, PacifiCorp would have been required to post
$221 million and $261 million, respectively, of additional collateral.
PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in
legislation or regulation or other factors.
(12) Fair Value Measurements
The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, other special funds, other investments, payables,
accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments.
PacifiCorp has various financial assets and liabilities that are measured at fair value on the financial statements using inputs from the
three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the
lowest level input that is significant to the fair value measurement. The three levels are as follows:
Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the
ability to access at the measurement date.
Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or
similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset
or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other
means (market corroborated inputs).
Level 3 - Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in
pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best
information available, including its own data.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.26
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, 2016:
Assets:
Commodity derivatives $ — $ 27 $ — $ (7) $ 20
Money market mutual funds(2)13 — — — 13
Investment funds 17 ———17
$30 $27 $—$(7)$50
Liabilities - Commodity derivatives $—$(104)$—$76 $(28)
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)
(1) Represents netting under master netting arrangements and a net cash collateral receivable of $69 million and $75 million as of December 31, 2016 and 2015,
respectively.
(2) Amounts are included in other special funds, special deposits and temporary cash investments on the Comparative Balance Sheet. The fair value of these
money market mutual funds approximates cost.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.27
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 and are primarily accounted for
as available-for-sale securities. When available, 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. In the absence of a quoted market price or net asset value of an identical
security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market
prices of securities with similar characteristics.
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):
2016 2015
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $7,082 $8,204 $7,147 $8,210
(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.

Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards,
emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected
species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp
believes it is in material compliance with all applicable laws and regulations.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.28
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 begin no earlier than 2020.
Congress failed to pass legislation needed to implement the original KHSA. Hence, 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. On April 6, 2016, PacifiCorp, the states of California and Oregon, and the
United States Departments of the Interior and Commerce and other stakeholders executed an amendment to the KHSA. Consistent
with the terms of the amended KHSA, on September 23, 2016, PacifiCorp and the Klamath River Renewal Corporation ("KRRC")
jointly filed an application with the FERC to transfer the license for the four mainstem Klamath River hydroelectric generating
facilities from PacifiCorp to the KRRC. Also on September 23, 2016, the KRRC filed an application with the FERC to surrender the
license and decommission the facilities. The KRRC's license surrender application included a request for the FERC to refrain from
acting on the surrender application until after the transfer of the license to the KRRC is effective.
Under the amended KHSA, PacifiCorp and its customers continue to be protected from uncapped dam removal costs and liabilities.
The KRRC must indemnify PacifiCorp from liabilities associated with dam removal. 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. California voters approved
a water bond measure in November 2014 from which the state of California's contribution towards facilities removal costs will be
drawn. In accordance with this bond measure, additional funding of up to $250 million for facilities removal costs was included in the
California state budget in 2016, with the funding effective for at least five years. 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 removal to proceed.
If certain conditions in the amended KHSA are not satisfied and the license does not transfer to the KRRC, PacifiCorp will resume
relicensing with the FERC.
As of December 31, 2016, PacifiCorp's assets included $68 million of costs associated with the Klamath hydroelectric system's
mainstem dams and the associated relicensing and settlement costs, which are being depreciated and amortized in accordance with
state regulatory approvals through either December 31, 2019, or December 31, 2022, depending upon the state jurisdiction.
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 $227 million
over the next 10 years related to these licenses.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.29
Commitments
PacifiCorp has the following firm commitments that are not reflected on the Comparative Balance Sheet. Minimum payments as of
December 31, 2016 are as follows (in millions):
2017 2018 2019 2020 2021
2022 and
Thereafter Total
Contract type:
Purchased electricity contracts -
commercially operable $ 253 $ 160 $ 157 $ 157 $ 145 $ 1,630 $ 2,502
Purchased electricity contracts -
non-commercially operable 10 13 17 17 18 390 465
Fuel contracts 796 616 596 507 346 1,407 4,268
Construction commitments 62 46 26 4 1 4 143
Transmission 109 106 90 61 47 467 880
Operating leases and easements 5 5 5 5 4 39 63
Maintenance, service and
other contracts 53 29 31 17 20 68 218
Total commitments $1,288 $975 $922 $768 $581 $4,005 $8,539

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 $14 million for 2016 and $13 million for 2015.
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 operating 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 2016
and 2015 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.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.30
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 years ended December 31, 2016 and 2015.
Guarantees
PacifiCorp has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not
expected to have a material impact on PacifiCorp's financial results.
(14) Preferred Stock
In 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 2017, 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 2017.
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, 2016, 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, 2016, PacifiCorp's actual
common equity percentage, as calculated under this measure, was 51%, and PacifiCorp would have been permitted to dividend
$1.9 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, 2016, 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.31
(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):
2016 2015
Interest paid, net of amounts capitalized $351 $342
Income taxes paid, net(1)$187 $32
Supplemental disclosure of non-cash investing and financing activities:
Accounts payable related to utility plant additions $ 101 $ 147
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
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.32
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
/ /2016/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)
( 13,665,680)
Balance of Account 219 at Beginning of
Preceding Year
1
549,221
Preceding Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
2
1,101,821
Preceding Quarter/Year to Date Changes in
Fair Value
3
1,651,042Total (lines 2 and 3) 4
( 12,014,638)
Balance of Account 219 at End of Preceding
Quarter/Year
5
( 12,014,638)
Balance of Account 219 at Beginning of
Current Year
6
488,311
Current Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
7
( 1,067,871)
Current Quarter/Year to Date Changes in
Fair Value
8
( 579,560)Total (lines 7 and 8) 9
( 12,594,198)
Balance of Account 219 at End of Current
Quarter/Year
10
FERC FORM NO. 1 (NEW 06-02)Page 122a
Other Cash Flow
Hedges
[Insert Footnote at Line 1
to 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
/ /2016/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)
( 13,665,680) 1
549,221 2
1,101,821 3
695,335,538 696,986,580 1,651,042 4
( 12,014,638) 5
( 12,014,638) 6
488,311 7
( 1,067,871) 8
762,510,394 761,930,834( 579,560) 9
( 12,594,198) 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
/ /2016/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
26,872,537,513 26,872,537,513Plant in Service (Classified) 3
27,028,781 27,028,781Property Under Capital Leases 4
Plant Purchased or Sold 5
191,897,135 191,897,135Completed Construction not Classified 6
Experimental Plant Unclassified 7
27,091,463,429 27,091,463,429Total (3 thru 7) 8
Leased to Others 9
23,502,790 23,502,790Held for Future Use 10
655,882,614 655,882,614Construction Work in Progress 11
156,468,483 156,468,483Acquisition Adjustments 12
27,927,317,316 27,927,317,316Total Utility Plant (8 thru 12) 13
9,693,954,266 9,693,954,266Accum Prov for Depr, Amort, & Depl 14
18,233,363,050 18,233,363,050Net Utility Plant (13 less 14) 15
Detail of Accum Prov for Depr, Amort & Depl 16
In Service: 17
9,026,397,312 9,026,397,312Depreciation 18
Amort & Depl of Producing Nat Gas Land/Land Right 19
Amort of Underground Storage Land/Land Rights 20
550,553,312 550,553,312Amort of Other Utility Plant 21
9,576,950,624 9,576,950,624Total 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
117,003,642 117,003,642Amort of Plant Acquisition Adj 32
9,693,954,266 9,693,954,266Total 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
/ /2016/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
/ /2016/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 206,974,785 -177,719 3
(303) Miscellaneous Intangible Plant 669,757,688 51,991,761 4
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 876,732,473 51,814,042 5
2. PRODUCTION PLANT 6
A. Steam Production Plant 7
(310) Land and Land Rights 93,556,326 20,122 8
(311) Structures and Improvements 1,011,697,865 9,211,821 9
(312) Boiler Plant Equipment 4,374,914,312 228,239,273 10
(313) Engines and Engine-Driven Generators 11
(314) Turbogenerator Units 954,177,895 44,155,643 12
(315) Accessory Electric Equipment 484,708,784 6,003,686 13
(316) Misc. Power Plant Equipment 31,275,408 201,674 14
(317) Asset Retirement Costs for Steam Production 141,661,372 10,143,462 15
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 7,091,991,962 297,975,681 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 31,312,931 627,132 27
(331) Structures and Improvements 262,514,284 4,561,004 28
(332) Reservoirs, Dams, and Waterways 488,402,461 8,397,740 29
(333) Water Wheels, Turbines, and Generators 128,919,258 487,968 30
(334) Accessory Electric Equipment 79,819,536 1,824,262 31
(335) Misc. Power PLant Equipment 2,380,783 -2,932 32
(336) Roads, Railroads, and Bridges 22,170,609 1,276,758 33
(337) Asset Retirement Costs for Hydraulic Production 34
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 1,015,519,862 17,171,932 35
D. Other Production Plant 36
(340) Land and Land Rights 44,773,920 37
(341) Structures and Improvements 227,589,347 118,051 38
(342) Fuel Holders, Products, and Accessories 15,904,296 740,155 39
(343) Prime Movers 2,930,023,773 50,747,743 40
(344) Generators 473,476,623 2,229,021 41
(345) Accessory Electric Equipment 326,256,540 1,249,496 42
(346) Misc. Power Plant Equipment 15,921,587 19,129 43
(347) Asset Retirement Costs for Other Production 13,031,355 44
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 4,046,977,441 55,103,595 45
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 12,154,489,265 370,251,208 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
/ /2016/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
206,797,066 3
677,391,601 -38,073 44,319,775 4
884,188,667 -38,073 44,319,775 5
6
7
92,712,595 -862,212 1,641 8
1,018,623,608 351 2,286,429 9
4,545,102,284 -34,299 58,017,002 10
11
974,487,555 23,845,983 12
489,371,864 33,029 1,373,635 13
31,121,380 919 356,621 14
141,879,562 -887,420 9,037,852 15
7,293,298,848 -862,212 -887,420 94,919,163 16
17
18
19
20
21
22
23
24
25
26
31,842,095 -97,950 18 27
266,871,297 -63,720 140,271 28
496,112,457 63,720 751,464 29
129,287,827 119,399 30
81,315,515 328,283 31
2,376,872 979 32
23,251,414 195,953 33
34
1,031,057,477 -97,950 1,536,367 35
36
45,478,205 704,285 37
227,671,314 -8,452 27,632 38
16,237,258 3,743 410,936 39
2,922,254,312 -913,155 57,604,049 40
475,162,261 315,209 858,592 41
327,689,620 631,918 448,334 42
15,911,453 -29,263 43
13,031,355 44
4,043,435,778 704,285 59,349,543 45
12,367,792,103 -255,877 -887,420 155,805,073 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
/ /2016/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
3. TRANSMISSION PLANT 47
(350) Land and Land Rights 251,625,967 4,326,112 48
(352) Structures and Improvements 239,305,233 4,546,370 49
(353) Station Equipment 2,012,791,077 97,808,172 50
(354) Towers and Fixtures 1,288,991,817 2,140,800 51
(355) Poles and Fixtures 901,299,535 22,421,086 52
(356) Overhead Conductors and Devices 1,193,250,695 22,042,679 53
(357) Underground Conduit 3,519,566 -172 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) 5,910,756,444 153,285,047 58
4. DISTRIBUTION PLANT 59
(360) Land and Land Rights 62,461,151 796,264 60
(361) Structures and Improvements 110,250,312 2,354,138 61
(362) Station Equipment 971,676,422 31,672,784 62
(363) Storage Battery Equipment 63
(364) Poles, Towers, and Fixtures 1,120,755,209 39,320,107 64
(365) Overhead Conductors and Devices 724,069,029 19,504,360 65
(366) Underground Conduit 349,690,089 11,033,231 66
(367) Underground Conductors and Devices 820,180,898 23,991,529 67
(368) Line Transformers 1,274,134,081 45,536,275 68
(369) Services 709,528,257 34,747,237 69
(370) Meters 186,936,755 9,245,534 70
(371) Installations on Customer Premises 8,863,050 61,971 71
(372) Leased Property on Customer Premises 72
(373) Street Lighting and Signal Systems 61,222,785 1,444,196 73
(374) Asset Retirement Costs for Distribution Plant 1,507,080 74
TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 6,401,275,118 219,707,626 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 21,481,450 176,044 86
(390) Structures and Improvements 240,205,455 5,170,795 87
(391) Office Furniture and Equipment 80,556,278 5,622,539 88
(392) Transportation Equipment 110,652,440 3,994,617 89
(393) Stores Equipment 15,178,816 377,227 90
(394) Tools, Shop and Garage Equipment 64,061,851 2,250,713 91
(395) Laboratory Equipment 33,961,776 860,916 92
(396) Power Operated Equipment 168,265,144 5,416,614 93
(397) Communication Equipment 428,243,947 21,420,893 94
(398) Miscellaneous Equipment 8,135,600 259,442 95
SUBTOTAL (Enter Total of lines 86 thru 95) 1,170,742,757 45,549,800 96
(399) Other Tangible Property 2,559,113 97
(399.1) Asset Retirement Costs for General Plant 39,748 98
TOTAL General Plant (Enter Total of lines 96, 97 and 98) 1,173,341,618 45,549,800 99
TOTAL (Accounts 101 and 106) 26,516,594,918 840,607,723 100
(102) Electric Plant Purchased (See Instr. 8) 1,460,458 301,580 101
(Less) (102) Electric Plant Sold (See Instr. 8) -561,324 -5,796,654 102
(103) Experimental Plant Unclassified 103
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 26,518,616,700 846,705,957 104
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
/ /2016/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
47
255,798,637 10,767 164,209 48
242,638,070 -935,766 277,767 49
2,104,342,313 2,700,514 8,957,450 50
1,291,140,475 -82,247 -90,105 51
920,968,349 -181,291 2,570,981 52
1,213,340,115 -97,393 1,855,866 53
3,519,394 54
8,035,354 55
11,937,200 56
57
6,051,719,907 1,414,584 13,736,168 58
59
62,113,932 -1,142,824 659 60
112,377,028 -8,668 218,754 61
997,337,161 -999,004 5,013,041 62
63
1,151,503,495 17,995 8,589,816 64
739,638,373 3,935,016 65
359,267,271 1,456,049 66
841,132,222 3,040,205 67
1,310,749,847 -1,181 8,919,328 68
743,490,472 785,022 69
192,964,294 3,217,995 70
8,837,157 87,864 71
72
61,890,748 776,233 73
1,507,080 74
6,582,809,080 -2,133,682 36,039,982 75
76
77
78
79
80
81
82
83
84
85
21,544,358 113,136 86
241,961,606 -3,380 3,411,264 87
75,133,918 40,999 11,085,898 88
110,614,591 261,250 4,293,716 89
15,398,780 39,600 196,863 90
64,086,679 -283,518 1,942,367 91
32,873,041 15,240 1,964,891 92
163,198,650 10,483,108 93
443,004,548 55,754 6,716,046 94
8,214,144 21,341 202,239 95
1,176,030,315 147,286 40,409,528 96
1,854,828 -704,285 97
39,748 98
1,177,924,891 -556,999 40,409,528 99
27,064,434,648 -1,570,047 -887,420 290,310,526 100
-387,367 -1,374,671 101
6,357,978 102
103
27,064,434,648 -1,957,414 -8,620,069 290,310,526 104
Page 207FERC FORM NO. 1 (REV. 12-05)
Schedule Page: 204 Line No.: 97 Column: b
Account 39921, Land owned in fee
Schedule Page: 204 Line No.: 97 Column: f
Refer to footnote on line 97, column (b).
Schedule Page: 204 Line No.: 97 Column: g
Refer to footnote on line 97, column (b).
Schedule Page: 204 Line No.: 101 Column: b
Refer to Item 3 in Important Changes During the Year in this Form No. 1.
Schedule Page: 204 Line No.: 101 Column: c
Refer to footnote on Line 101, column (b).
Schedule Page: 204 Line No.: 101 Column: e
Refer to footnote on line 101, column (b).
Schedule Page: 204 Line No.: 101 Column: f
Refer to footnote on line 101, column (b).
Schedule Page: 204 Line No.: 102 Column: b
Refer to Item 3 in Important Changes During the Year in this Form No. 1.
Schedule Page: 204 Line No.: 102 Column: c
Refer to footnote on line 102, column (b).
Schedule Page: 204 Line No.: 102 Column: e
Refer to footnote on line 102, 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
2016/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
/ /2016/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
2007Barnes Butte Substation 746,2682025 2
2007Wild Horse Wind Plant 6,763,0942039 3
2007Twelve Mile Wind Plant 2,160,2072039 4
2008Jumbers Point Substation 1,173,2762022 5
2009Mountain Green Substation 284,9962025 6
2009Hoggard Substation 254,3972025 7
2009Oquirrh-Terminal 345kV Transmission Line 396,0202021 8
2010Bend Service Center 3,507,8382022 9
2010Legacy Substation 562,2762025 10
2011Aeolus Substation 1,013,5772020 11
2011Anticline Substation 964,0432020 12
2011Populus Substation 254,7532024 13
2011Snyderville Substation 253,4012017 14
2012Lassen Substation 683,3182018 15
2012Old Mill Substation 1,838,2812026 16
2013Chimney Butte-Paradise 230kV Transmission Line 598,4572025 17
2016Fiddlers Canyon Substation 1,136,5872028 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 23,502,790
Schedule Page: 214 Line No.: 3 Column: c
Land purchased for wind farms with an estimated construction date of 2039, subject to
environmental and economic reviews and the timing of completion of the Energy Gateway
Transmission Expansion Program.
Schedule Page: 214 Line No.: 4 Column: c
Land purchased for wind farms with an estimated construction date of 2039, subject to
environmental and economic reviews and the timing of completion of the Energy Gateway
Transmission Expansion Program.
Schedule Page: 214 Line No.: 18 Column: a
In June 2016, Fiddlers Canyon Substation was transferred from Account 101, Electric plant
in service, to Account 105, Electric plant held for future use.
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
2016/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
/ /2016/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
3,622,173MV-Star Software Replacement 2
2,686,462Wallowa Falls Hydro Relicensing 3
2,143,265Endur System Upgrade 4
1,291,992Prospect No. 3 Hydro Relicensing 5
6
Production: 7
111,124,301Wind Repowering/New Development/Safe Harbor Equipment Purchases 8
27,339,043Craig U2 Selective Catalytic Reduction System 9
7,254,464Lewis River System Relicensing Implementation 10
2,973,110Jim Bridger U2 Replace Finishing Superheater 11
2,891,223Oneida 3 Rotor Replacement 12
1,874,018Prospect No. 1 Rehabilitation 13
1,620,902Toketee Dam Rehabilitation Evaluation 14
1,522,562Lewis River System Maximum Flood Improvement Study 15
1,432,463Jim Bridger Replace 01/02 Emergency Diesel Generators 16
1,414,736Oneida Water Conveyance Protection 17
1,038,868Naughton U1 Feedwater High-Pressure Heater Replacement 18
19
Transmission: 20
80,741,062Aeolus - Clover 500kV Line 21
73,477,761Windstar - Populus 230 - 500kV Line 22
55,878,860Boardman - Hemingway 500kV Line 23
50,542,670Populus - Hemingway 500kV Line 24
29,165,659Snow Goose 500 - 230kV Substation 25
14,646,417Union Gap Substation Add 230 - 115kV Capacity 26
12,241,519Oquirrh - Terminal 345kV Line 27
11,447,197West Point - New 138kV Line and 40 MVa Substation 28
11,039,688Vantage - Pomona Heights 230kV Line 29
9,237,959Troutdale Substation 230kV Switchyard 115kV Ring Bus 30
6,564,216Southwest WY - Silver Creek Build 138kV Line 31
5,748,746Purgatory Flat New 138kV Substation 32
5,102,851Wallula - McNary 230kV Line 33
3,042,749Sigurd - Red Butte - Crystal 345kV Line 34
1,719,639Sams Valley New 500 - 230kV Substation 35
1,504,794Syracuse Substation - Install 2nd 345-138 kV Transformer TPL 36
1,375,150Goshen - Jefferson - Montana Stateline 161kV Reconductor 37
1,147,486Hazelwood and Fry Substations: Relay Replacement 38
1,105,505Borah Substation: Replace Series Cap C341 39
1,000,336California Lines 38 & 44 LiDAR 40
41
42
FERC FORM NO. 1 (ED. 12-87) Page 216
43 TOTAL 655,882,614
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
/ /2016/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.
Distribution: 1
4,022,847Oregon Advanced Metering Infrastructure 2
3,830,616Vineyard Substation and Timp-Vineyard 138kV Line Upgrades 3
1,766,602Lassen Substation - New Substation 4
1,135,988Stadelman Fruit, Yakima WA 5
6
98,166,715Miscellaneous Projects each under $1,000,000 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
FERC FORM NO. 1 (ED. 12-87) Page 216.1
43 TOTAL 655,882,614
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
/ /2016/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 8,565,801,806 8,565,801,806
Depreciation Provisions for Year, Charged to 2
(403) Depreciation Expense 3 709,094,974 709,094,974
(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 30,594,113 30,594,113
9
TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
10 739,689,087 739,689,087
Net Charges for Plant Retired: 11
Book Cost of Plant Retired 12 245,497,947 245,497,947
Cost of Removal 13 73,978,760 73,978,760
Salvage (Credit) 14 3,898,603 3,898,603
TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
15 315,578,104 315,578,104
Other Debit or Cr. Items (Describe, details in
footnote):
16 36,484,523 36,484,523
17
Book Cost or Asset Retirement Costs Retired 18
Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
19 9,026,397,312 9,026,397,312
Steam Production 20
Section B. Balances at End of Year According to Functional Classification
3,044,271,915 3,044,271,915
Nuclear Production 21
Hydraulic Production-Conventional 22 359,720,139 359,720,139
Hydraulic Production-Pumped Storage 23
Other Production 24 916,111,993 916,111,993
Transmission 25 1,592,275,183 1,592,275,183
Distribution 26 2,679,701,608 2,679,701,608
Regional Transmission and Market Operation 27
General 28 434,316,474 434,316,474
TOTAL (Enter Total of lines 20 thru 28) 29 9,026,397,312 9,026,397,312
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
Account 143, Other accounts receivable: depreciation expense
billed to joint owners $ 265,926
Account 182.3, Other regulatory assets or Account 254, Other regulatory
liabilities: asset retirement obligation asset depreciation 17,761,421
Account 182.3, Other regulatory assets: deferral of Carbon depreciation (5,081,468)
Account 182.3, Other regulatory assets: deferral of increased depreciation,
due to depreciation study rates, net of amortization 1,174,622
Transportation depreciation charged to operations and maintenance
expense and construction work in progress based on usage activity 14,483,977
Account 503, Steam from other sources: Blundell depletion 23,172
Account 503, Steam from other sources: Blundell depreciation 1,966,463
Total Other Accounts $ 30,594,113
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 $ 18,137,493
Other items include: 18,347,030
- 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 $ 36,484,523
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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
/ /2016/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
148,768,673 Undistributed Subsidiary Earnings 4
196,728,674 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
7,010,024 Undistributed Subsidiary Earnings 21
13,048,024 SUBTOTAL 22
23
2011FOSSIL ROCK FUELS, LLC 24
31,538,428 Paid-in Capital 25
-173,158 Undistributed Subsidiary Earnings 26
31,365,270 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 241,143,969 83,504,772
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
/ /2016/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
109,099,488 15,330,815 4
157,059,489 15,330,815 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
7,331,504 402,201 21
13,369,504 402,201 22
23
24
29,504,770 25
515,450 2,118,875 26
30,020,220 2,118,875 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 17,851,891 200,451,214
Schedule Page: 224 Line No.: 1 Column: a
Pacific Minerals, Inc. is a wholly owned subsidiary of PacifiCorp that holds a 66.67%
ownership interest in Bridger Coal Company, a coal mining joint venture with Idaho Energy
Resources Company, a subsidiary of Idaho Power Company.
Schedule Page: 224 Line No.: 4 Column: g
For the year ended December 31, 2016, Pacific Minerals, Inc., a wholly owned subsidiary of
PacifiCorp, declared and paid dividends of $55.0 million to PacifiCorp.
Schedule Page: 224 Line No.: 21 Column: g
In September 2016, Trapper Mining Inc., a subsidiary of PacifiCorp, paid a dividend of
$80,721 to PacifiCorp.
Schedule Page: 224 Line No.: 25 Column: g
For the year ended December 31, 2016, Fossil Rock Fuels, LLC, a wholly owned subsidiary of
PacifiCorp, returned $2.0 million of capital to PacifiCorp.
Schedule Page: 224 Line No.: 26 Column: g
For the year ended December 31, 2016, Fossil Rock Fuels, LLC, a wholly owned subsidiary of
PacifiCorp, declared and paid dividends of $1.4 million to 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
2016/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
/ /2016/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.
192,305,988 Electric 214,693,832 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)
134,703,542 Electric 142,252,190 5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
84,947,332 Electric 73,437,874 7 Production Plant (Estimated)
653,625 Electric 715,287 8 Transmission Plant (Estimated)
12,772,256 Electric 11,798,517 9 Distribution Plant (Estimated)
10 Regional Transmission and Market Operation Plant
(Estimated)
55,338 Electric 57,418 11 Assigned to - Other (provide details in footnote)
233,132,093 228,261,286 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
425,438,081 442,955,118 20 TOTAL Materials and Supplies (Per Balance Sheet)
Page 227FERC FORM NO. 1 (REV. 12-05)
Schedule Page: 227 Line No.: 7 Column: c
During the year ended December 31, 2016, inventory associated with the Carbon coal-fueled
generation plant retired in December 2015, was transferred to Account 182.3, Other
regulatory assets.
Schedule Page: 227 Line No.: 11 Column: b
General plant materials and supplies
Schedule Page: 227 Line No.: 11 Column: c
General plant materials and supplies
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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
/ /2016/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.
2017
558,841.00 151,733.00Balance-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
27,605.00 Charges to Account 509 18
Other: 19
20
Cost of Sales/Transfers: 21
22
23
24
25
26
27
Total 28
531,236.00 151,733.00Balance-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
/ /2016/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.
2018 2019
1 4,072,762.00 151,417.00 156,646.00 5,091,399.00
2
3
4
5 156,644.00 156,644.00
6
7
8
9
10
11
12
13
14
15
16
17
18 27,605.00
19
20
21
22
23
24
25
26
27
28
29 4,229,406.00 151,417.00 156,646.00 5,220,438.00
30
31
32
33
34
35
36 110,921.00 2,259.00 2,259.00 119,957.00
37 4,528.00 4,528.00
38
39 2,269.00 4,528.00
40 113,180.00 2,259.00 2,259.00 119,957.00
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-95) Page 229a
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2016/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2. List each study separately.
3. In column (a) provide the name of the study.
4. In column (b) report the cost incurred to perform the study at the end of period.
5. In column (c) report the account charged with the cost of the study.
6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
7. In column (e) report the account credited with the reimbursement received for performing the study.
the Period
Transmission Studies 0.0 0 1
2,678Q0542 561.6 2
10,242Q1918 561.6 10,242 456 3
13,811Q1919 561.6 13,811 456 4
2,876Q1918-1919 561.6 2,876 456 5
26,349Q1977 561.6 26,349 456 6
2,776Q2065 561.6 2,776 456 7
4,581Q2068 561.6 8
3,424Q2068-2072 561.6 3,424 456 9
2,781Q2089 561.6 10
959Q2111 561.6 11
8,432Q2111-2115 561.6 8,432 456 12
4,510Q2132-2138 561.6 4,510 456 13
4,300Q10264 561.6 4,300 456 14
589AREF 81045934 561.6 15
2,056AREF 81460501 561.6 16
4,531AREF 82205457 561.6 17
1,622AREF 82206368 561.6 18
824AREF 82324247 561.6 19
407AREF 83020531 561.6 20
Generation Studies 0.0 0 21
274GIQ0252 561.7 274 456 22
6,949GIQ0397 561.7 6,949 456 23
( 90,815)GIQ0409 561.7 ( 90,815) 456 24
412GIQ0564 561.7 412 456 25
385GIQ0589 561.7 385 456 26
8,517GIQ0627 561.7 8,517 456 27
3,643GIQ0629 561.7 3,643 456 28
10,252GIQ0634 561.7 10,252 456 29
9,339GIQ0636 561.7 9,339 456 30
13,058GIQ0641 561.7 13,058 456 31
5,072GIQ0642 561.7 5,072 456 32
134GIQ0647 561.7 134 456 33
599GIQ0648 561.7 599 456 34
209GIQ0649 561.7 209 456 35
1,963GIQ0650 561.7 1,963 456 36
966GIQ0651 561.7 966 456 37
966GIQ0652 561.7 966 456 38
1,121GIQ0653 561.7 1,121 456 39
4,840GIQ0656 561.7 4,840 456 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
/ /2016/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 0.0 0 1
733AREF 83163541 561.6 2
9,186AREF 83205077 561.6 3
1,706AREF 817749198 561.6 4
588 561.6 5
( 2,773)Customer Studies Accruals 561.6 6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 0.0 0 21
557GIQ0659 561.7 557 456 22
866GIQ0660 561.7 866 456 23
925GIQ0661 561.7 925 456 24
1,213GIQ0662 561.7 1,213 456 25
137GIQ0663 561.7 137 456 26
198GIQ0664 561.7 198 456 27
1,196GIQ0666 561.7 1,196 456 28
137GIQ0667 561.7 137 456 29
198GIQ0668 561.7 198 456 30
868GIQ0670 561.7 868 456 31
5,164GIQ0671 561.7 5,164 456 32
812GIQ0672 561.7 812 456 33
1,561GIQ0677 561.7 1,561 456 34
618GIQ0682 561.7 618 456 35
6,478GIQ0684 561.7 6,478 456 36
6,822GIQ0686 561.7 6,822 456 37
38,426GIQ0687 561.7 38,426 456 38
5,510GIQ0702 561.7 5,510 456 39
1,977GIQ0703 561.7 1,977 456 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
/ /2016/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
3,679GIQ0704 561.7 3,679 456 22
28,484GIQ0706 561.7 28,484 456 23
29,579GIQ0707 561.7 29,579 456 24
34,924GIQ0708 561.7 34,924 456 25
33,046GIQ0710 561.7 33,046 456 26
37,529GIQ0711 561.7 37,529 456 27
33,689GIQ0712 561.7 33,689 456 28
35,894GIQ0713 561.7 35,894 456 29
8,846GIQ0714 561.7 8,846 456 30
29,537GIQ0715 561.7 29,537 456 31
3,250GIQ0716 561.7 3,250 456 32
52,791GIQ0718 561.7 52,791 456 33
20,037GIQ0719 561.7 20,037 456 34
39,385GIQ0720 561.7 39,385 456 35
31,728GIQ0721 561.7 31,728 456 36
10,500GIQ0722 561.7 10,500 456 37
287GIQ0723 561.7 287 456 38
9,062GIQ0724 561.7 9,062 456 39
3,602GIQ0725 561.7 3,602 456 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
/ /2016/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
22,096GIQ0726 561.7 22,096 456 22
9,684GIQ0727 561.7 9,684 456 23
13,551GIQ0728 561.7 13,551 456 24
25,763GIQ0729 561.7 25,763 456 25
19,866GIQ0730 561.7 19,866 456 26
14,055GIQ0731 561.7 14,055 456 27
19,632GIQ0732 561.7 19,632 456 28
24,265GIQ0733 561.7 24,265 456 29
14,303GIQ0734 561.7 14,303 456 30
22,759GIQ0735 561.7 22,759 456 31
33,646GIQ0736 561.7 33,646 456 32
11,130GIQ0737 561.7 11,130 456 33
13,241GIQ0738 561.7 13,241 456 34
15,785GIQ0739 561.7 15,785 456 35
7,752GIQ0740 561.7 7,752 456 36
26,707GIQ0741 561.7 26,707 456 37
4,684GIQ0742 561.7 4,684 456 38
7,595GIQ0743 561.7 7,595 456 39
4,962GIQ0744 561.7 4,962 456 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
/ /2016/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
19,294GIQ0745 561.7 19,294 456 22
2,287GIQ0746 561.7 2,287 456 23
7,424GIQ0747 561.7 7,424 456 24
2,095GIQ0748 561.7 2,095 456 25
8,433GIQ0749 561.7 8,433 456 26
10,878GIQ0750 561.7 10,878 456 27
12,387GIQ0751 561.7 12,387 456 28
12,803GIQ0752 561.7 12,803 456 29
14,823GIQ0753 561.7 14,823 456 30
12,117GIQ0754 561.7 12,117 456 31
8,779GIQ0755 561.7 8,779 456 32
758GIQ0756 561.7 758 456 33
18,421GIQ0757 561.7 18,421 456 34
9,068GIQ0758 561.7 9,068 456 35
1,478GIQ0759 561.7 1,478 456 36
237GIQ0760 561.7 237 456 37
2,032GIQ0761 561.7 2,032 456 38
8,065GIQ0762 561.7 8,065 456 39
8,572GIQ0763 561.7 8,572 456 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
/ /2016/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
17,179GIQ0764 561.7 17,179 456 22
1,993GIQ0765 561.7 1,993 456 23
2,212GIQ0766 561.7 2,212 456 24
1,868GIQ0767 561.7 1,868 456 25
2,163GIQ0768 561.7 2,163 456 26
13,110GIQ0769 561.7 13,110 456 27
14,993GIQ0770 561.7 14,993 456 28
1,487GIQ0771 561.7 1,487 456 29
1,426GIQ0772 561.7 1,426 456 30
1,566GIQ0773 561.7 1,566 456 31
1,835GIQ0774 561.7 1,835 456 32
1,881GIQ0775 561.7 1,881 456 33
2,634GIQ0776 561.7 2,634 456 34
1,683GIQ0777 561.7 1,683 456 35
1,240GIQ0778 561.7 1,240 456 36
10,340GIQ0779 561.7 10,340 456 37
5,635GIQ0780 561.7 5,635 456 38
11,751GIQ0781 561.7 11,751 456 39
4,050GIQ0782 561.7 4,050 456 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
/ /2016/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
1,144GIQ0783 561.7 1,144 456 22
950GIQ0784 561.7 950 456 23
1,232GIQ0785 561.7 1,232 456 24
1,754GIQ0786 561.7 1,754 456 25
1,280GIQ0787 561.7 1,280 456 26
1,020GIQ0788 561.7 1,020 456 27
1,578GIQ0789 561.7 1,578 456 28
1,176GIQ0790 561.7 1,176 456 29
881GIQ0791 561.7 881 456 30
8,043GIQ0792 561.7 8,043 456 31
6,841GIQ0793 561.7 6,841 456 32
4,400GIQ0794 561.7 4,400 456 33
2,742GIQ0795 561.7 2,742 456 34
1,654GIQ0796 561.7 1,654 456 35
2,966GIQ0797 561.7 2,966 456 36
1,412GIQ0798 561.7 1,412 456 37
1,973GIQ0799 561.7 1,973 456 38
2,392GIQ0800 561.7 2,392 456 39
1,110GIQ0801 561.7 1,110 456 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
/ /2016/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
995GIQ0802 561.7 995 456 22
1,616GIQ0803 561.7 1,616 456 23
2,016GIQ0804 561.7 2,016 456 24
2,084GIQ0805 561.7 2,084 456 25
1,737GIQ0806 561.7 1,737 456 26
1,399GIQ0807 561.7 1,399 456 27
2,275GIQ0809 561.7 2,275 456 28
1,620GIQ0810 561.7 1,620 456 29
1,945GIQ0811 561.7 1,945 456 30
1,354GIQ0812 561.7 1,354 456 31
1,354GIQ0813 561.7 1,354 456 32
1,061GIQ0814 561.7 1,061 456 33
894GIQ0815 561.7 894 456 34
969GIQ0816 561.7 969 456 35
1,185GIQ0817 561.7 1,185 456 36
578GIQ0818 561.7 578 456 37
667GIQ0824 561.7 667 456 38
995GIQ0825 561.7 995 456 39
667GIQ0826 561.7 667 456 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
/ /2016/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
400GIQ0827 561.7 400 456 22
400GIQ0828 561.7 400 456 23
481GIQ0829 561.7 481 456 24
481GIQ0830 561.7 481 456 25
191GIQ0832 561.7 191 456 26
191GIQ0833 561.7 191 456 27
191GIQ0834 561.7 191 456 28
1,860GIQ0835 561.7 1,860 456 29
618GIQ0836 561.7 618 456 30
378GIQ0838 561.7 378 456 31
378GIQ0839 561.7 378 456 32
64GIQ0841 561.7 64 456 33
205GIQ0843 561.7 205 456 34
205GIQ0844 561.7 205 456 35
27,395Pre-Application Studies - East 561.7 27,395 456 36
24,657Pre-Application Studies - West 561.7 24,657 456 37
( 4,300)Q10264 561.7 ( 4,300) 456 38
98,723Customer Studies Accruals 561.7 ( 23,364) 456 39
40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.8
Schedule Page: 231.1 Line No.: 5 Column: a
AREFS 83163541, 83163568, 83163576 and 83163584
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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
/ /
2016/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)
856,824 458,210 2,890,302908 2,491,688DSM Balancing Account - CA 1
908,075 263,284 5,157,139908,431 4,512,348DSM Balancing Account - ID 2
14,269,911 72,273,519908,431 58,003,608DSM Balancing Account - UT 3
1,943,274 2,515,256 10,807,670908 11,379,652DSM Balancing Account - WA 4
323,788 3,731,359 4,785,934908,431 8,193,505DSM Balancing Account - WY 5
68,998 66,002908 135,000Irrigation Load Control - OR 6
6,395,828 4,754,305 3,453,095555 1,811,572Deferred Excess Net Power Costs - CA 7
22,396,531 12,380,361 16,551,278555 6,535,108Deferred Excess Net Power Costs - ID 8
40,428,344 12,864,998 29,160,809555,431 1,597,463Deferred Excess Net Power Costs - UT 9
16,420,025 2,885,525 13,667,160555 132,660Deferred Excess Net Power Costs - WY 10
11,354,395 2,766,087 8,588,308456,431Deferred Excess RECs in Rates - UT 11
613,882 621,409456 7,527Deferred Excess RECs/SO2 in Rates - WY 12
3,169,877 736,202 2,433,675456,254Deferred Excess RECs in Rates - WA 13
436,870,019 420,840,992 19,951,122282,283 3,922,095Deferred Income Tax Electric 14
78,736 75,159 3,939282,283 362Solar ITC Basis Adjustment Regulatory Asset 15
1,788,655 894,326 894,329410.1Tax Adj on Postretirement Benefits - OR (5) 16
4,408 4,408Tax Revenue Requirement Adjustment - WY (4) 17
473,328,654 490,943,147 32,443,693 50,058,186Pension 18
25,768,508 34,446,629 886,736 9,564,857Other Postretirement 19
3,417,221 2,190,893 1,226,328Postemployment Costs 20
130,146 103,930 26,216407.3Powerdale Decommissioning - ID (10) 21
2,393,193 1,914,554 478,639403Carbon Plant Regulatory Asset - ID (6) 22
17,223,206 13,778,565 3,444,641403Carbon Plant Regulatory Asset - UT (6) 23
5,790,939 4,632,751 1,158,188403Carbon Plant Regulatory Asset - WY (6) 24
3,119,560 3,119,560Carbon Plant Inventory Regulatory Asset 25
3,258,921 5,003,777 1,744,856Depreciation Study Deferral - ID 26
1,984,669 1,856,626 128,043403Depreciation Study Deferral - UT (17) 27
6,853,959 6,411,768 442,191403Depreciation Study Deferral - WY (17) 28
1,352,992 1,298,704 54,288930.2Generating Plant Liquidated Damages - WY 29
630,000 595,000 35,000930.2Generating Plant Liquidated Damages - UT 30
26,170,339 22,835,039 4,483,442404 1,148,142Klamath Hydroelectric Relicensing Costs - UT (10) 31
1,486,166 547,534 938,632557Cholla Plant Transaction Costs (26) 32
265,319 213,131 52,188456Washington Colstrip Unit No. 3 (22) 33
44,491,898 48,931,374 3,437,942253,925 7,877,418Environmental Costs (10) 34
65,097,432 81,673,452 16,576,020Asset Retirement Obligations Regulatory Difference 35
110,071,947 97,918,622 12,153,325242Unamortized Contract Values 36
132,542,310 72,824,222 59,718,088175,244Unrealized Loss on Derivative Contracts 37
796,625 7,679,928555 6,883,303Greenhouse Gas Allowance Compliance - CA 38
5,336,104 5,546,365 4,745,435 4,955,696Solar Feed-In Tariff Deferral - OR (1) 39
21,683 1,311,983 1,290,300Solar Incentive Subscriber Program - UT 40
49,313 56,405555 7,092Renewable Portfolio Standards Compliance - CA 41
339,537 339,537Renewable Portfolio Standards Compliance 42
1,442,958 410,913 1,290,508928 258,463Deferred Intervenor Funding Grants - OR (1) 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
/ /
2016/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)
40,406 40,605 199Deferred Intervenor Funding Grants - CA 1
26,865 26,865Deferred Intervenor Funding Grants - ID 2
197,343 347,657 545,000Catastrophic Event Regulatory Asset - CA (1) 3
3,091 660,564 657,473Alternative Rate for Energy (CARE) - CA 4
303,336 261,175 1,440,142501 1,397,981Deferred Overburden Cost - ID 5
842,293 734,674 4,237,214501 4,129,595Deferred Overburden Cost - WY 6
1,939,461 3,366,686 1,427,225BPA Balancing Account - OR 7
282,902 182,475421.1 465,377Asset Sales Balancing Account - OR 8
474,686 854,625 7,068,568924 7,448,507Property Insurance Reserve - OR 9
122,561 261,099924 138,538Property Insurance Reserve - WY 10
73,531 264,453 190,922Misc. Regulatory Assets/Liabilities - OR 11
6,648 6,648Depreciation Deferral - WA 12
186,332,549 166,424,633 20,480,463 572,547Utah Mine Disposition 13
233,459 205,017 28,442407.3Preferred Stock Redemption Loss - WY (10) 14
677,439 594,908 82,531407.3Preferred Stock Redemption Loss - UT (10) 15
108,762 95,444 13,318407.3Preferred Stock Redemption Loss - WA (10) 16
162,586 162,586Merwin Fish Collector Project - WA (1) 17
1,729 10,270 8,541Mobile Home Park Conversion - CA 18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
1,679,069,828TOTAL :44 1,538,109,950 360,494,449 219,534,571
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232.1
Schedule Page: 232 Line No.: 7 Column: a
Weighted average remaining life is approximately one year for deferred excess net power
cost mechanisms being amortized.
Schedule Page: 232 Line No.: 8 Column: a
Weighted average remaining life is approximately one year for deferred excess net power
cost mechanisms being amortized, including Monsanto and Agrium net power cost components.
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 net power
cost mechanisms being amortized.
Schedule Page: 232 Line No.: 11 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.: 12 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.: 13 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.: 17 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 232 Line No.: 18 Column: a
Weighted average remaining life being amortized is 21 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.: 18 Column: d
Pensions are associated with labor and generally charged to operations and maintenance
expense and construction work in progress. Pension curtailments for Oregon, California,
Idaho and remeasurement date changes for Oregon, Utah and California are charged to
Account 920, Administrative and general salaries.
Schedule Page: 232 Line No.: 19 Column: a
Weighted average remaining life of portion being amortized is 21 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
Other postretirement measurement date changes for Oregon, Utah, California and Wyoming's
share of settlement losses are charged to Account 920, Administrative and general
salaries.
Schedule Page: 232 Line No.: 20 Column: a
Weighted average remaining life is five years.
Schedule Page: 232 Line No.: 20 Column: d
Other postemployment costs are associated with labor and generally charged to operations
and maintenance expense and construction work in progress. Other postemployment
remeasurements are charged to Account 228.3, Accumulated provision for pensions and
benefits.
Schedule Page: 232 Line No.: 29 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Weighted average remaining life is 26 years.
Schedule Page: 232 Line No.: 30 Column: a
Weighted average remaining life is 17 years.
Schedule Page: 232 Line No.: 36 Column: a
Weighted average remaining life is seven years. Represents frozen values of contracts
previously accounted for as derivatives and recorded at fair value.
Schedule Page: 232 Line No.: 37 Column: a
Weighted average remaining life is five years.
Schedule Page: 232 Line No.: 39 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.: 3 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 232.1 Line No.: 13 Column: a
Weighted average remaining life is approximately two years for the net property, plant and
equipment not considered probable of disallowance and for the portion of losses associated
with the assets held for sale. Additionally, the weighted average remaining life is
approximately five years for closure costs incurred to date considered probable of
recovery.
Schedule Page: 232.1 Line No.: 13 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Account 445, Other sales to public authorities
Account 501, Fuel
Account 506, Miscellaneous General Expenses
Schedule Page: 232.1 Line No.: 17 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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
/ /2016/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.
286,209 148,828 137,381557Joseph Settlement (21) 1
278,130 232,410 45,720557Lacomb Irrigation (24) 2
994,160 952,880 41,280557Bogus Creek (41) 3
Mead Phoenix Availability and 4
11,867,960 11,448,619 419,341565Transmission Charge (50) 5
63,183 47,709 15,474557TGS Buyout (23) 6
1,412,872 1,494,708 500 82,336 142, 419Point-to-Point Transmission 7
3,534,017 3,362,323 171,694557Hermiston Swap (40) 8
Oregon Prepaid REC Purchases 9
11,950 11,950555for RPS Compliance (1) 10
Deferred Coal Costs - Wyodak 11
2,346,272 2,011,090 335,182151Settlement (22) 12
Deferred Coal Costs - Naughton 13
1,376,154 1,376,154151Settlement (7) 14
Deferred Colstrip Plant 15
25,000 25,000501Costs (5) 16
300,283 229,147 137,875 66,739 931LT Lease Commissions Prepaid 17
5,147,854 12,156,745 7,008,891Lake Side Maintenance Prepaid 18
10,805,583 12,382,314 4,801,047 6,377,778 107Lake Side 2 Maintenance Prepaid 19
2,856,589 5,793,373 2,936,784Chehalis Maintenance Prepaid 20
20,193,323 3,512,380 19,857,053 3,176,110 107Currant Creek Maint. Prepaid 21
331,194 136,613 319,581 125,000 454Lease Incentives 22
1,396,981 1,324,377 741,503 668,899 427, 431Credit Agreement Costs 23
142,490 29,165 117,825 4,500 427PCRB LOC/SBBPA Costs 24
259,714 191,737 67,977427PCRB Mode Conversion Costs 25
549,568 460,359 89,209189, 427'94 Series Restruct. Costs (16) 26
186,399 191,902 5,503Deferred S-3 Shelf Regis. Costs 27
LT Prepaid IBEW 57 Pension 28
850,198 856,610 6,412Contribution 29
3,902,426 3,063,345 990,335 151,254 565BPA LT Transmission Prepaid 30
306,510 306,510Emission Reduction Credits 31
1,785,425 1,785,425Unamortized Contract Values 32
Sales of Electric Utility 33
711,003 149,584 932,037 370,618Facilities & Properties 34
108,381 60,723 47,658921, 923IT Licenses and Maint. Prepaid 35
36
37
38
39
40
41
42
43
44
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)
70,244,403 61,472,266
Schedule Page: 233 Line No.: 17 Column: a
The weighted average remaining life of long-term prepaid lease commissions being amortized
is one year.
Schedule Page: 233 Line No.: 22 Column: a
The weighted average remaining life is one year.
Schedule Page: 233 Line No.: 23 Column: a
The weighted average remaining life is two years.
Schedule Page: 233 Line No.: 24 Column: a
The weighted average remaining life is one year.
Schedule Page: 233 Line No.: 25 Column: a
The weighted average remaining life is eight years.
Schedule Page: 233 Line No.: 29 Column: d
Pensions are associated with labor and generally charged to operations and maintenance
expense and construction work in progress, including Account 228.3, Accumulated provision
for pensions and benefits.
Schedule Page: 233 Line No.: 34 Column: d
Account 102, Electric plant purchased or sold
Account 421.1, Gain on disposition of property
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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
/ /2016/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
202,357,014 189,756,726Employee benefits 2
66,912,983 93,561,265Derivative contracts and unamortized contract values 3
69,101,510 68,772,466State carryforwards 4
56,218,611Loss contingencies 5
77,524,010 80,689,134Asset retirement obligations 6
125,963,826 117,213,002Other 7
541,859,343 606,211,204TOTAL 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
541,859,343 606,211,204TOTAL (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 $ 29,935,861 $ 44,474,964
Other 87,277,141 81,488,862
$117,213,002 $125,963,826
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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
/ /2016/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
100.006.00% Series 15
100.007.00% 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
/ /2016/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
593,000 5,930 15
1,804,600 18,046 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, 2016, 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
2016/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
/ /2016/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, 2016.
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
2016/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
/ /2016/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
/ /2016/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
18,750,000 8.635% Series due October 1, 2016 3
19,609,000 8.470% Series due October 1, 2017 4
3,067,221 500,000,000 5.65% Series due July 15, 2018 5
905,000 6 D
2,515,793 350,000,000 5.50% Series due January 15, 2019 7
2,292,500 8 D
3,007,139 400,000,000 3.85% Series due June 15, 2021 9
744,000 10 D
2,424,350 350,000,000 2.95% Series due February 1, 2022 11
308,000 12 D
254,129 100,000,000 2.95% Series due February 1, 2022 13
-81,000 14 P
1,859,352 300,000,000 2.95% Series due June 1, 2023 15
900,000 16 D
3,345,164 425,000,000 3.60% Series due April 1, 2024 17
255,000 18 D
2,121,421 250,000,000 3.35% Series due July 1, 2025 19
320,000 20 D
2,874,150 300,000,000 7.70% Series due November 15, 2031 21
864,000 22 D
1,892,365 200,000,000 5.90% Series due August 15, 2034 23
722,000 24 D
2,912,021 300,000,000 5.25% Series due June 15, 2035 25
1,080,000 26 D
2,907,881 350,000,000 6.10% Series due August 1, 2036 27
1,141,000 28 D
589,216 600,000,000 5.75% Series due April 1, 2037 29
24,000 30 D
5,127,281 600,000,000 6.25% Series due October 15, 2037 31
750,000 32 D
FERC FORM NO. 1 (ED. 12-96)Page 256
33 TOTAL 7,192,699,000 76,839,200
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
/ /2016/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
109,18910/01/201604/15/199210/01/201604/15/1992 3
1,722,000 246,92210/01/201704/15/199210/01/201704/15/1992 4
500,000,000 28,250,00007/15/201807/17/200807/15/201807/17/2008 5
6
350,000,000 19,250,00001/15/201901/08/200901/15/201901/08/2009 7
8
400,000,000 15,400,00006/15/202105/12/201106/15/202105/12/2011 9
10
350,000,000 10,325,00002/01/202201/06/201202/01/202201/06/2012 11
12
100,000,000 2,950,00002/01/202203/06/201202/01/202203/06/2012 13
14
300,000,000 8,850,00006/01/202306/06/201306/01/202306/06/2013 15
16
425,000,000 15,300,00004/01/202403/13/201404/01/202403/13/2014 17
18
250,000,000 8,375,00007/01/202506/19/201507/01/202506/19/2015 19
20
300,000,000 23,100,00011/15/203111/21/200111/15/203111/21/2001 21
22
200,000,000 11,800,00008/15/203408/24/200408/15/203408/24/2004 23
24
300,000,000 15,750,00006/15/203506/13/200506/15/203506/13/2005 25
26
350,000,000 21,350,00008/01/203608/10/200608/01/203608/10/2006 27
28
600,000,000 34,500,00004/01/203703/14/200704/01/203703/14/2007 29
30
600,000,000 37,500,00010/15/203710/03/200710/15/203710/03/2007 31
32
FERC FORM NO. 1 (ED. 12-96)Page 257
33 7,093,197,000 359,474,830
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
/ /2016/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.
2,290,333 300,000,000 6.35% Series due July 15, 2038 1
1,671,000 2 D
6,134,687 650,000,000 6.00% Series due January 15, 2039 3
6,175,000 4 D
2,737,911 300,000,000 4.10% Series due February 1, 2042 5
987,000 6 D
115,202 15,000,000 8.53% Series C Medium-Term Notes due Dec. 16, 2021 7
38,400 5,000,000 8.375% Series C Medium-Term Notes due Dec. 31, 2021 8
33,243 5,000,000 8.26% Series C Medium-Term Notes due Jan. 7, 2022 9
30,594 4,000,000 8.27% Series C Medium-Term Notes due Jan. 10, 2022 10
131,471 15,000,000 8.05% Series E Medium-Term Notes due Sept. 1, 2022 11
70,118 8,000,000 8.07% Series E Medium-Term Notes due Sept. 9, 2022 12
438,238 50,000,000 8.12% Series E Medium-Term Notes due Sept. 9, 2022 13
105,177 12,000,000 8.11% Series E Medium-Term Notes due Sept. 9, 2022 14
87,648 10,000,000 8.05% Series E Medium-Term Notes due Sept. 14, 2022 15
208,198 26,000,000 8.08% Series E Medium-Term Notes due Oct. 14, 2022 16
200,190 25,000,000 8.08% Series E Medium-Term Notes due Oct. 14, 2022 17
37,914 5,000,000 8.23% Series E Medium-Term Notes due Jan. 20, 2023 18
30,331 4,000,000 8.23% Series E Medium-Term Notes due Jan. 20, 2023 19
-81,560 20 P
246,981 27,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 21
100,622 11,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 22
137,211 15,000,000 7.23% Series F Medium-Term Notes due Aug. 16, 2023 23
274,423 30,000,000 7.24% Series F Medium-Term Notes due Aug. 16, 2023 24
38,250 5,000,000 6.75% Series F Medium-Term Notes due Sept. 14, 2023 25
15,300 2,000,000 6.75% Series F Medium-Term Notes due Sept. 14, 2023 26
15,300 2,000,000 6.72% Series F Medium-Term Notes due Sept. 14, 2023 27
152,326 20,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 28
121,861 16,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 29
91,396 12,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 30
904,467 100,000,000 6.71% Series G Medium-Term Notes due Jan. 15, 2026 31
68,661,215 6,737,359,000Subtotal - First Mortgage Bonds 32
FERC FORM NO. 1 (ED. 12-96)Page 256.1
33 TOTAL 7,192,699,000 76,839,200
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
/ /2016/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.
300,000,000 19,050,00007/15/203807/17/200807/15/203807/17/2008 1
2
650,000,000 39,000,00001/15/203901/08/200901/15/203901/08/2009 3
4
300,000,000 12,300,00002/01/204201/06/201202/01/204201/06/2012 5
6
15,000,000 1,279,50012/16/202112/16/199112/16/202112/16/1991 7
5,000,000 418,75012/31/202112/31/199112/31/202112/31/1991 8
5,000,000 413,00001/07/202201/08/199201/07/202201/08/1992 9
4,000,000 330,80001/10/202201/09/199201/10/202201/09/1992 10
15,000,000 1,207,50009/01/202209/18/199209/01/202209/18/1992 11
8,000,000 645,60009/09/202209/09/199209/09/202209/09/1992 12
50,000,000 4,060,00009/09/202209/11/199209/09/202209/11/1992 13
12,000,000 973,20009/09/202209/11/199209/09/202209/11/1992 14
10,000,000 805,00009/14/202209/14/199209/14/202209/14/1992 15
26,000,000 2,100,80010/14/202210/15/199210/14/202210/15/1992 16
25,000,000 2,020,00010/14/202210/15/199210/14/202210/15/1992 17
5,000,000 411,50001/20/202301/20/199301/20/202301/20/1993 18
4,000,000 329,20001/20/202301/29/199301/20/202301/29/1993 19
20
27,000,000 1,960,20007/21/202307/22/199307/21/202307/22/1993 21
11,000,000 798,60007/21/202307/22/199307/21/202307/22/1993 22
15,000,000 1,084,50008/16/202308/16/199308/16/202308/16/1993 23
30,000,000 2,172,00008/16/202308/16/199308/16/202308/16/1993 24
5,000,000 337,50009/14/202309/14/199309/14/202309/14/1993 25
2,000,000 135,00009/14/202309/14/199309/14/202309/14/1993 26
2,000,000 134,40009/14/202309/14/199309/14/202309/14/1993 27
20,000,000 1,350,00010/26/202310/26/199310/26/202310/26/1993 28
16,000,000 1,080,00010/26/202310/26/199310/26/202310/26/1993 29
12,000,000 810,00010/26/202310/26/199310/26/202310/26/1993 30
100,000,000 6,710,00001/15/202601/23/199601/15/202601/23/1996 31
6,700,722,000 354,973,161 32
FERC FORM NO. 1 (ED. 12-96)Page 257.1
33 7,093,197,000 359,474,830
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
/ /2016/Q4
Line
No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense,
Premium or Discount
Principal Amount
Of Debt issued(For new issue, give commission Authorization numbers and dates)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than as
specified by the Uniform System of Accounts.
Pollution Control Obligations - Secured by Pledged First Mortgage Bonds: 1
510,479 21,260,000 Poll Ctrl Rev Refunding Bonds, Sweetwater County, WY, Series 1994 2
209,777 8,190,000 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1994 3
3,274,246 121,940,000 Poll Ctrl Rev Refunding Bonds, Emery County, UT, Series 1994 4
206,519 9,365,000 Poll Ctrl Rev Refunding Bonds, Carbon County, UT, Series 1994 5
422,858 15,060,000 Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1994 6
771,836 45,000,000 Poll Ctrl Rev Refunding Bonds, Lincoln Cnty, WY, Series 1991 7
304,824 8,500,000 Poll Ctrl Revenue Bonds, City of Forsyth, MT, Series 1986 8
132,043 5,300,000 Environ. Imprvmnt Rev Bonds, Converse County, WY, Series 1995 9
404,262 22,000,000 Environ. Imprvmnt Rev Bonds, Lincoln County, WY, Series 1995 10
6,236,844 256,615,000Subtotal Pollution Control Obligations - Secured by Pledged First Mortgage Bonds 11
12
Pollution Control Obligations - Unsecured: 13
380,198 45,000,000 Poll Ctrl Rev Refndng Bonds, City of Forsyth, MT, Series 1988 14
422,443 50,000,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Series 1988A 15
351,905 41,200,000 Poll Ctrl Rev Refndng Bonds, City of Gillette, WY, Ser. 1988 16
167,524 9,335,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992A 17
242,163 22,485,000 Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 18
151,908 6,305,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992B 19
225,000 24,400,000 Environ. Imprvmnt Rev Bonds, Sweetwater County, WY, Series 1995 20
1,941,141 198,725,000Subtotal - Pollution Control Obligations - Unsecured 21
22
76,839,200 7,192,699,000TOTAL ACCOUNT 221 23
24
Reacquired Bonds: (Account 222) 25
26
Advances from Associated Companies: (Account 223) 27
28
Other Long-Term Debt: (Account 224) 29
30
Long-Term Debt Authorized but Unissued 31
32
FERC FORM NO. 1 (ED. 12-96)Page 256.2
33 TOTAL 7,192,699,000 76,839,200
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
/ /2016/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
21,260,000 300,31311/01/202411/17/199411/01/202411/17/1994 2
8,190,000 71,22911/01/202411/17/199411/01/202411/17/1994 3
121,940,000 1,525,01811/01/202411/17/199411/01/202411/17/1994 4
22,04302/18/201611/17/199411/01/202411/17/1994 5
15,060,000 146,88911/01/202411/17/199411/01/202411/17/1994 6
8101/01/201601/17/199101/01/201601/17/1991 7
74,39612/01/201612/01/198612/01/201612/01/1986 8
5,300,000 46,33011/01/202511/17/199511/01/202511/17/1995 9
22,000,000 210,29011/01/202511/17/199511/01/202511/17/1995 10
193,750,000 2,396,589 11
12
13
45,000,000 577,05001/01/201801/01/198801/01/201801/01/1988 14
50,000,000 419,89901/01/201701/01/198801/01/201701/01/1988 15
41,200,000 334,56701/01/201801/01/198801/01/201801/01/1988 16
9,335,000 117,06412/01/202009/29/199212/01/202009/29/1992 17
22,485,000 276,89712/01/202009/29/199212/01/202009/29/1992 18
6,305,000 80,31912/01/202009/29/199212/01/202009/29/1992 19
24,400,000 299,28411/01/202512/14/199511/01/202512/14/1995 20
198,725,000 2,105,080 21
22
7,093,197,000 359,474,830 23
24
25
26
27
28
29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 257.2
33 7,093,197,000 359,474,830
Schedule Page: 256.2 Line No.: 5 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.: 23 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.: 23 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 during the year.
Schedule Page: 256.2 Line No.: 31 Column: a
PacifiCorp currently has an effective shelf registration statement filed with the United
States Securities and Exchange Commission on Form S-3 to issue up to $1.325 billion
additional 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, 2016), 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
by the counties of Emery, Utah; Carbon, Utah; Converse, Wyoming; Lincoln, Wyoming;
Sweetwater, Wyoming; and Moffat, Colorado (total of $300,345,000 authorized and
$166,450,000 available as of December 31, 2016) and authorization to borrow the proceeds
of new pollution control revenue bonds issued 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 (total of
$150,000,000 authorized and available as of December 31, 2016) is as follows:
IPUC - Case No. PAC-E-08-05, Order No. 30606, dated August 4, 2008.
OPUC - Docket No. UF-4250, Order No. 08-382, dated July 29, 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
2016/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
/ /2016/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.
762,510,394Net Income for the Year (Page 117) 1
2
3
Taxable Income Not Reported on Books 4
5
6
7
121,404,353Other 8
Deductions Recorded on Books Not Deducted for Return 9
10
11
12
1,306,879,433Other 13
Income Recorded on Books Not Included in Return 14
15
16
17
28,740,446Other 18
Deductions on Return Not Charged Against Book Income 19
20
21
22
23
24
1,467,788,648Other 25
-30,374,888State Tax Deductions 26
663,890,198Federal Tax Net Income 27
Show Computation of Tax: 28
29
232,361,569Federal Income Tax at 35.00% 30
-8,357,383Provision to Return Adjustment 31
13,449Tax Reserve Changes 32
647,104Tax Settlement 33
-66,817,070Renewable Energy Production Tax Credits 34
35
157,847,669Federal 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 71,153,413
Regulatory Asset - REC Sales Deferral - UT 8,588,308
Regulatory Asset - REC Sales Deferral - WA 2,433,675
Regulatory Asset - REC Sales Deferral - WY 613,882
Regulatory Asset - WA Colstrip #3 52,188
Regulatory Liability - BPA Balancing Account - WA 1,120,640
Regulatory Liability - Deferred Excess NPC - OR 8,251,457
Regulatory Liability - Deferred Excess NPC - UT 4,840,097
Regulatory Liability - Deferred Excess NPC - WA 8,731,562
Regulatory Liability - Deferred Excess NPC - WY 3,186,133
Regulatory Liability - Depreciation Decrease - OR 1,038,665
Regulatory Liability - DSM Balance Reclass 4,404,501
Regulatory Liability - OR Direct Access 5 Year Opt Out 524,790
Regulatory Liability - Sale of REC - OR 650
Regulatory Liability - Sale of REC - UT 408,173
Regulatory Liability - Sale of REC - WY 523,321
Regulatory Liability - UT Home Energy Lifeline 316,781
Regulatory Liability - WA Accel Depreciation 2,801,877
Regulatory Liability - WA Low Energy Program 391,092
Transmission Service Deposits 123,914
Reimbursements 1,863,634
Unearned Joint Use Pole Contact Revenue 35,600
Total $121,404,353
Schedule Page: 261 Line No.: 13 Column: a
Particulars (Details) Amounts
Fed/State Tax Expense 334,027,316
50% Meals and Entertainment 821,250
Accrued Bonus 200,000
Accrued Royalties 1,871,877
Avoided Costs 15,278,163
Bear River Settlement Agreement 106,557
Book Depreciation 760,803,372
Book Depreciation Allocated to Medicare and M&E 85,425
Capitalized Labor and Benefit Costs 402,542
Coal Pile Inventory Adjustment 500,581
Deferred Coal Costs - Naughton Contract Settlement 1,376,155
Deferred Revenue - Other 70,833
Environmental Liability - Regulated 3,211,981
Hermiston Swap 171,693
Hydro Relicensing Obligation 1,344,292
Inventory Reserve 305,796
Joseph Settlement 137,381
Lewis River Settlement Agreement 49,793
Lobbying Expenses 2,102,435
LT Incentive Plan 2,481,404
LT Prepaid IBEW 57 Pension Contribution 850,198
Medicare Subsidy 7,987,383
Miscellaneous Current and Accrued Liability 1,399,928
Penalties 15,595
Pension Liability UMWA Withdrawal Obligation 4,438,442
Prepaid Membership Fees 3,080,016
Prepaid Surety Bond 158,745
Prepaid Taxes - IPUC 81,704
Prepaid Water Rights 40,000
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Regulatory Asset - Carbon Plant Decomm/Inventory - CA 52,048
Regulatory Asset - Carbon Plant Decomm/Inventory - WA 277,798
Regulatory Asset - Carbon Unrecovered Plant - ID 478,639
Regulatory Asset - Carbon Unrecovered Plant - UT 3,444,641
Regulatory Asset - Carbon Unrecovered Plant - WY 1,158,188
Regulatory Asset - Cholla Plant Transaction Costs 1,122,425
Regulatory Asset - Deferred Excess NPC - CA 1,641,523
Regulatory Asset - Deferred Excess NPC - ID 10,016,170
Regulatory Asset - Deferred Excess NPC - UT 27,563,345
Regulatory Asset - Deferred Excess NPC - WY '09 & After 13,534,499
Regulatory Asset - Deferred Intervenor Funding Grants - OR 1,032,044
Regulatory Asset - Deferred Overburden Costs - ID 42,161
Regulatory Asset - Deferred Overburden Costs - WY 107,619
Regulatory Asset - DSM - Noncurrent 15,669,270
Regulatory Asset - Depreciation Increase - UT 128,043
Regulatory Asset - Depreciation Increase - WY 442,191
Regulatory Asset - Environmental Costs - WA 49,913
Regulatory Asset - FAS 158 Pension Liability 33,267,071
Regulatory Asset - GHG Allowance Compliance Costs - CA 796,626
Regulatory Asset - Goodnoe Hills Settlement - WY 21,250
Regulatory Asset - Klamath Hydroelectric Relicensing Costs - UT 3,335,301
Regulatory Asset - Lake Side Settlement - WY 27,331
Regulatory Asset - Liquidated Damages - Naughton Unit #2 - WY 5,708
Regulatory Asset - Pension MMT - UT 283,176
Regulatory Asset - Post Employment Costs 1,226,328
Regulatory Asset - Post Merger Loss - Reacquired Debt 572,406
Regulatory Asset - Postretirement - CA 17,488
Regulatory Asset - Postretirement - OR 193,035
Regulatory Asset - Postretirement - UT 278,648
Regulatory Asset - Postretirement Settlement Loss 375,321
Regulatory Asset - Postretirement Settlement Loss CC - WY 22,244
Regulatory Asset - Powerdale Decommissioning - ID 26,216
Regulatory Asset - Preferred Stock Redemption - WY 28,442
Regulatory Asset - Preferred Stock Redemption Loss - UT 82,531
Regulatory Asset - Preferred Stock Redemption Loss - WA 13,318
Regulatory Asset - REC Sales Deferral - CA 49,313
Regulatory Asset - Tax Revenue Requirement Adj - WY 4,407
Regulatory Asset - Liquidated Damages - UT 35,000
Regulatory Asset - Merwin Project - WA 166,018
Regulatory Liability - ARO/Reg Diff - Trojan - WA Portion 8,448
Regulatory Liability - Blue Sky - CA 50,590
Regulatory Liability - Blue Sky - UT 2,151,203
Regulatory Liability - Blue Sky - WA 51,295
Regulatory Liability - Blue Sky - WY 80,145
Regulatory Liability - Contra-Carbon Decommmissioning - WY 535,226
Regulatory Liability - Energy Savings Assistance - CA 724,546
Regulatory Liability - Injuries & Damages Reserve - OR 3,562,162
Regulatory Liability - OR Energy Conservation Charge 944,486
Regulatory Liability - Property Insurance Reserve - ID 60,937
Regulatory Liability - Property Insurance Reserve - WY 211,272
Regulatory Liability - Solar Incentive Program - UT 2,014,911
Reserve for Bad Debts 139,320
TGS Buyout 15,474
Trapper Mine Contract Obligation 206,750
Utah Mine Disposition 32,613,041
Intercompany Adjustment 2,521,075
Total $1,306,879,433

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 261 Line No.: 18 Column: a
Particulars (Details) Amounts
Fed/State Tax Expense - Interest (146,973)
Book Fixed Asset Gain/Loss (1,830,691)
Deferred Revenue - Lease Incentives (106,311)
Dividend Received Deduction - Deferred Compensation (187,822)
Investment Gain/Loss - Tax (1,692)
MCI F.O.G. Wire Lease (417)
Officer's Life Insurance (5,802,438)
Regulatory Asset - Alt Rate for Energy Program (CARE) - CA (657,473)
Regulatory Asset - BPA Balancing Account - OR (1,427,225)
Regulatory Liability - BPA Balancing Account - ID (13,004)
Regulatory Liability - Depreciation Decrease - WA (274,982)
Regulatory Liability - GHG Allowance Revenues - CA (306,548)
Trapper Mining Stock Basis (132,979)
Equity Earnings in Subsidiaries (17,851,891)
Total $(28,740,446)
Schedule Page: 261 Line No.: 25 Column: a
Particulars (Details) Amounts
Accrued Final Reclamation (1,281,561)
Accrued Retention (2,500)
Accrued Severance (431,953)
Accrued Vacation (581,139)
Amortization NOPAs 99-00 RAR (50,796)
Basis Intangible Difference (304,497)
Capitalized Depreciation (4,931,895)
Cholla SHL NOPA (Lease Amortization) (227,265)
Contra Receivable from Joint Owners (430,376)
Cost of Removal (73,978,760)
CWIP Reserve (394,527)
Debt AFUDC (15,207,203)
Deferred Compensation Mark to Market Gain/Loss - Income Statement (384,981)
Deferred Compensation (1,364,961)
Deferred Revenue - Other (114,471)
Deseret Settlement Receivable (115,019)
Energy West Accrued Liabilities (645,912)
Environmental Liability - Non-Regulated (129,197)
Equity AFUDC - Temp (27,254,684)
FAS 112 Book Reserve - Post Employment Benefits (962,263)
FAS 158 Pension Liability (19,248,547)
FAS 158 Postretirement Liability (4,308,429)
FAS 158 SERP Liability (1,231,046)
Federal Tax Depreciation (910,975,456)
Federal Tax Fixed Asset Gain/Loss (5,912,813)
Fuel Cost Adjustment (2,634,272)
Income Tax Interest (573,227)
Injuries & Damages Accrual - Cash Basis (21,391,976)
Insurance Reserve (6,386,531)
LT Incentive Plan Mark to Market Gain/Loss - Income Statement (651,003)
N Umpqua Settlement Agreement (329,362)
Non-deductible Postretirement Costs (7,987,383)
Oregon Regulatory Asset/Regulatory Liability Consolidation (1,445)
Pension/Retirement Accrual (268,151)
Pre-1943 Preferred Stock Dividend - Deduction (64,760)
Prepaid Taxes - OPUC (71,425)
Prepaid Taxes - Property Taxes (663,387)
Prepaid Taxes - UPSC (437,298)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Qualified Production Activities Deduction (25,541,142)
Regulatory Asset - CA Mobile Home Park Conversion (8,541)
Regulatory Asset - Carbon Plant Decomm/Inventory (3,449,406)
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 Intervenor Funding Grants - CA (199)
Regulatory Asset - Depreciation Increase - ID (1,744,857)
Regulatory Asset - DSM Balance Reclass (4,404,501)
Regulatory Asset - Energy West Mining (12,705,124)
Regulatory Asset - Environmental Costs (4,489,389)
Regulatory Asset - FAS 158 Postretirement Liability (6,137,965)
Regulatory Asset - Asset Sales Balancing Account - OR (282,902)
Regulatory Asset - Postretirement Settlement Loss CC - UT (372,012)
Regulatory Asset - RPS Compliance Purchases (339,537)
Regulatory Asset - Solar Feed-In Tariff Deferral - OR (210,261)
Regulatory Asset - Storm Damage Deferral - CA (197,343)
Regulatory Asset - UT Subscriber Solar Program (1,290,300)
Regulatory Liability - 50% Bonus Tax Depreciation - WY (506,122)
Regulatory Liability - Blue Sky - ID (5,189)
Regulatory Liability - Blue Sky - OR (451,730)
Regulatory Liability - Property Insurance Reserve - OR (379,938)
Regulatory Liability - Property Insurance Reserve - UT (1,184,998)
Regulatory Liability - Solar Feed-in Tariff Deferral - CA (312,936)
Regulatory Liability - Trojan Decommissioning (131,950)
Repairs Deduction (167,797,688)
Rogue River - Habitat Enhancement Liability (38,743)
Tax Depletion - SRC (31,569)
USA Power Litigation (121,583,765)
Wasatch Workers Compensation Reserve (61,724)
Western Coal Carrier Retiree Medical Accrual (908,000)
Total $(1,467,788,648)
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:
Energy West Mining Company
Glenrock Coal Company
Interwest Mining Company
Pacific Minerals, Inc.
BHE Sub-Group:
ABA Holding, LLC
ABA Management, L.L.C.
Alamo 6 Solar Holdings, LLC
Alaska Gas Transmission Company, LLC
Allie Beth Allman Real Estate, Ltd
Apex Home Maintenance, LLC
Arizona HomeServices, LLC
Berkshire Hathaway Energy Company
BG Energy Holding Company LLC
BHE AC Holding, LLC
BHE America Transco, 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
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
BHES CSG Holdings, 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
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.
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
CTHM, L.L.C.
CTRE, L.L.C.
Dakota Dunes Development Company
DCCO, Inc.
Denver Rental, LLC
Desert Valley Company
DG-SB Project Holdings, LLC
Edina Financial Services, Inc.
Edina Realty Insurance, LLC
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 Network Realty, Inc.
First Realty Group, Inc.
First Realty, Ltd
First Reserve Insurance, Inc.
First Weber Illinois, LLC
First Weber, Inc.
Florida Network LLC
Florida Network Property Management, LLC
For Rent, Inc.
FR Kingfisher Holdings II, LLC
FR Mariah Holdings II, LLC
FRTC, LLC
FSRI Holdings, Inc.
Geronimo Community Solar Gardens Holding Company, LLC
Geronimo Community Solar Gardens, LLC
Gilbraltar Title Services, 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 Agency, LLC
HomeServices Insurance, Inc.
HomeServices Northeast, LLC
HomeServices of Alabama, Inc.
HomeServices of America, Inc.
HomeServices of California, Inc.
HomeServices of Colorado, LLC
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
HomeSvc of IL LLC d/b/a Koenig & Strey GMAC RE
HS Franchise Holding, LLC
HSGA Real Estate Group, L.L.C.
HSW Affiliates Holding, LLC
Huff Commercial Group, 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
Huff-Drees Realty, Inc.
IES Holding II LLC
IMO Company, Inc.
Imperial Magma 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
Kentwood City Properties, LLC
Kentwood Commercial, LLC
Kentwood DTC, LLC
Kentwood Real Estate Services, LLC
Kentwood, 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.
MES Holding LLC
MHC Investment Company
MHC, Inc.
Mid-America Referral Network, Inc.
MidAmerican Central California Transco LLC
MidAmerican Energy Company
MidAmerican Energy Machining Services LLC
MidAmerican Energy 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
NNGC Acquisition LLC
Norcon Holdings, Inc.
Northern Aurora Inc.
Northern Consolidated Power, Inc.
Northern Natural Gas Company
Novatus Texas Holdings, LLC
NRS Referral Services, LLC
NV Energy, Inc.
NVE Holdings, LLC
NVE Insurance Co, Inc.
NW Referral Services, LLC
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
PCG Agencies, Inc.
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 Projects Holding, 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.
Professional Referrals, Inc.
Pru-One, Inc.
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 Insurance, LLC
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 Felipe Energy Company
Saranac Energy Company, Inc.
SECI Holdings, Inc.
Semonin Realtors, Inc.
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 Kentwood Company at Cherry Creek, LLC
The Referral Company
TIAC LLC
TitleSouth, LLC
TLTC LLC
Topaz Solar Farms, LLC
TPZ Holding, LLC
TRMC LLC
Two Rivers, 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
TX Jumbo Road Wind, LLC
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 amountof 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 Corporation2701 Camelback Development, Inc.
3Wire Group Inc.
6991 Development, Inc.
A.E. Company, Inc.
AAA Aircraft SupplyAccra Manufacturing 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.Aerocraft Heat Treating Co., Inc.
Aerospace Dynamics International, Inc.
Affiliated Agency Operations Co.
Affordable Housing Partners, Inc.
Aipcf V Chi Blocker, 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.
Alu-Forge, Inc.
American All Risk Insurance Services, Inc.
American Commercial Claims Administrators, Inc.
American Dairy Queen CorporationAmerican Employers Group, Inc.
AmGUARD Insurance Company
Andrews Laser Works Corporation
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.
Arcturus Manufacturing Corporation
Artform International Inc.
Astrex Electronics, Inc.Astrex Holding 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
Atlanta International Insurance Company
Atlantic Precision, Inc.
AU Captive Risk Assurance Co.
AU Holding Company, Inc.
Avibank Manufacturing, Inc.
Baroness Small Estates, Inc.
Bayport Systems, Inc.
BCC Development, Inc.
Ben Bridge Jeweler, Inc.
Benjamin Moore & Co.
Benson Industries, Inc.
Benson, Ltd.
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.
Brittain Machine Inc.
Brooks Sports, Inc.
Brookwood Insurance Company
BTM Manufacturing LP
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.
Caledonian Alloys Inc.
California Insurance Company
Camp Manufacturing Company
Campbell Hausfeld Holdings. Inc.
Campbell Hausfeld/Scott Fetzer Company
Cannon Equipment LLC
Cannon Muskegon 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
Carefree/Scott Fetzer Company
Carlton Forge Works
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.
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.
Compass Aerospace Northwest Inc.
Complementary Coatings Corporation
Composites Horizons LLC
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
Designed Metal Connections, Inc.
Dickson Testing Co., Inc.
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
Duracell Distributing Inc.
Duracell Manufacturing Co.
Duracell U.S. Operations 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.11
Dynamic Development, Inc.
EastGUARD Insurance Company
Eco Color Company
Ecodyne Corporation
ELIM/STAFF
Ellis & Watts Global Industries, Inc.
Elm Street Corporation
Empire Distributors of North Carolina, Inc.
Empire Distributors, Inc.
Environment One Corporation
Exacta Aerospace Inc.
Executive Jet Management, Inc.
Exsif Worldwide, Inc.
ExtruMed, Inc.
Faraday Capital Limited
Farrow Machine & Manufacturing Co Inc.
Fatigue Technology Inc.
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.
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.
Fortner Aerospace Manufacturing 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)
FTI Manufacturing Inc.
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.12
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
Greenville Metals Inc.
GUARDco, Inc.
H. H. Brown Shoe Company, Inc.
H.J. Justin & Sons, Inc.
Hackney Ladish Inc.
Halex/Scott Fetzer Company
Hallmark Sweet, Inc.
Hamilton Aviation Inc.
Hawthorn Life International, Ltd.
HDS Redevelopment Corporation
HeatPipe Technology, Inc.
Helicomb International 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.
Howell Penncraft, Inc.
Huntington Alloys Corporation
IdeaLife Insurance Company
Illinois Insurance Company
Ingersoll Cutting Tool Company
Innovative Building Products, Inc.
Innovative Coatings Technology Corporation
International American Group Inc.
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.
JL Fiber Services 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.
Ken's Spray Equipment, Inc.
Klune Holdings Inc.
Klune Industries Inc.
Kova Solutions, Inc.
L.A. Terminals, Inc.
Leesburg Yarn Mills, Inc.
Lipotec Group Corp.
LJ Aero Holdings Inc.
LJ Synch Holdings Inc.
LMG Ventures, LLC
Lockwood Street Urban Renewal Corporation
Los Angeles Junction Railway 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.13
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.
McLane Midwest, Inc.
McLane Minnesota, Inc.
McLane New Jersey, Inc.
McLane Ohio, Inc.
McLane Southern, Inc.
McLane Suneast, Inc.
McLane Western, Inc.
McWilliams Forge Company
Meadowbrook Meat Company, Inc.
Medical Protective Finance Corporation
Medical Protective Insurance Services, Inc.
MedPro Group, Inc.
MedPro Risk Retention Services, Inc.
Metalac Fasteners 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.14
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
Noranco Manufacturing (USA) Ltd.
NorGUARD Insurance Company
North American Casualty Co.
Northern States Agency, Inc.
Norvell Electronics, Inc.
Noveon Hilton Davis, Inc.
NSS Technologies 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.
PCC Flow Technologies Holdings Inc.
PCC Flow Technologies Inc.
PCC Rollmet Inc.
PCC Specialty Products Inc.
PCC Structurals Inc.
Penn Coal Land, Inc.
Pennsylvania Insurance Company
Perfection Hy-Test Company
Permaswage Holdings, Inc.
PFVT Development, Inc.
Pine Canyon Land Company
PJR Management, Inc.
Plasma Coating Corporation
Plaza Financial Services Co.
Plaza Resources Co.
PLICO
PLICO Financial, Inc.
PLICO Sponsored Captive Insurance - Cell 1
PLICO Sponsored Captive Insurance Co.
Precision Brand Products, Inc.
Precision Castparts Corp
Precision Founders Inc.
Precision MO Corp
Precision Steel Warehouse - Charlotte
Precision Steel Warehouse, Inc.
Press Forge Company
Primus International Holding Company
Primus International Inc.
Princeton Advertising & Marketing Group, Inc.
Princeton Insurance Company
Princeton Risk Protection, 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.15
Priority One Financial Services, Inc.
Pro Installations, Inc.
Procrane Holdings, Inc.
Professional Datasolutions, Inc.
Progressive Incorporated
Promesa Health, Inc.
Protective Coating Inc.
QS Partners LLC
R.C. Willey Home Furnishings
Rabun Apparel, Inc.
Radnor Specialty Insurance Company
Railserve, Inc.
Railsplitter Holdings Corporation
Rathgibson Holding Co LLC
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.
Shultz Steel Company
SHX Flooring, Inc.
SidePlate Systems, Inc.
Smilemakers Canada Inc.
Smilemakers, Inc.
SN Management, Inc.
Soco West, Inc.
Somerset Services, Inc.
SOS Metals San Diego, LLC
SOS Metals, Inc.
Southern Energy Homes, Inc.
Southwest United Industries Inc.
Special Metals Corporation
Specialized Pipe Services, Inc.
Spectra Contract Flooring Puerto Rico, Inc.
SPS International Investment Company
SPS Technologies LLC
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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.16
Stern/Leach Company
Strategic Staff Management, Inc.
Stratoflight
Synchronous Aerospace Group
Syrgis Holdings, Inc.
Taegutec Inc.
TBS USA, Inc.
Texas Honing 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 Duracell Company Inc.
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
THI Acquisition Inc.
TIMET Asia Inc.
TIMET Real Estate Corporation
Titanium Metals Corporation
TMCA International Inc.
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
University Swaging Corporation
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.17
Warwick Chemicals USA, Inc.
Wayne/Scott Fetzer Company
Weaver Manufacturing Inc.
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.
World Book, Inc.
World Book/Scott Fetzer Company
World Investments, Inc.
Worldwide Containers, Inc.
WPLG, Inc.
Wyman Gordan Investment Castings Inc.
Wyman Gordon Company
Wyman Gordon Forgings Cleveland Inc.
Wyman Gordon Forgings Inc.
Wyman Gordon Pennsylvania LLC
Wyman SC 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.18
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2016/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
150,912,651 6,921,569 157,847,669 66,502 Income 2
35,752,642 35,723,112 5,000 723,563 FICA 3
236,260 236,789 -37,013 Unemployment 4
1,522,888 Foreign Withholding Taxes 5
186,901,553 6,921,569 193,807,570 5,000 2,275,940Subtotal 6
7
State: 8
9
Arizona: 10
3,657,040 3,664,096 1,824,992 Property 11
403,675 -498,945 -95,270 Income 12
4,060,715 -498,945 3,568,826 1,824,992Subtotal 13
14
California: 15
2,291,272 2,291,272 Property 16
26,463 26,533 -70 Unemployment 17
2,393,072 -258,409 2,134,663 Franchise-Income 18
170,889 121,479 58,400 Use 19
1,226,334 1,298,156 1,244,516 Local Franchise 20
6,108,030 -258,409 5,872,103 1,302,846Subtotal 21
22
Colorado: 23
2,102,437 2,192,437 2,110,000 Property 24
-136 -136 Income 25
2,102,437 -136 2,192,301 2,110,000Subtotal 26
27
Idaho: 28
5,551,509 5,799,246 3,124,891 Property 29
2,507,662 -390,274 2,117,388 Income 30
44,225 44,759 15,140 KWh 31
36,089 35,925 1,328 Unemployment 32
274,494 288,232 13,218 Use 33
8,413,979 -390,274 8,285,550 3,154,577Subtotal 34
35
Montana: 36
5,080,479 5,460,331 2,348,559 Property 37
-54,340 -52,959 -107,299 Corporate License-Income 38
378 378 Unemployment 39
216,983 214,983 62,000 Energy License 40
12,597,489
FERC FORM NO. 1 (ED. 12-96)Page 262
TOTAL41 426,729,279 424,577,879 1,906,359 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 (Continued)
PacifiCorp X
/ /2016/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
-41,603,403 199,451,072 79,951 2
35,723,112 689,033 3
236,789 -36,484 4
1,522,888 5
-5,643,502 199,451,072 2,255,388 6
7
8
9
10
3,664,096 1,832,048 11
-80,755 -14,515 12
-80,755 3,649,581 1,832,048 13
14
15
128,461 2,162,811 16
26,533 17
-286,833 2,421,496 18
121,479 8,990 19
1,298,156 1,316,338 20
-10,360 5,882,463 1,325,328 21
22
23
236,932 1,955,505 2,200,000 24
-136 25
236,932 1,955,369 2,200,000 26
27
28
22,016 5,777,230 3,372,628 29
-385,536 2,502,924 30
44,759 15,674 31
35,925 1,164 32
288,232 26,956 33
-39,363 8,324,913 3,416,422 34
35
36
5,460,331 2,728,411 37
-34,552 -72,747 38
378 39
214,983 60,000 40
FERC FORM NO. 1 (ED. 12-96)Page 263
41 12,903,355 425,846,027 883,252 42,398,601
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
/ /2016/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.
154,601 152,601 44,000 Wholesale Energy 1
5,398,101 -52,959 5,720,994 2,454,559Subtotal 2
3
Nevada: 4
24,942 31,184 10,000 Commerce Tax 5
24,942 31,184 10,000Subtotal 6
7
New Mexico: 8
22,087 22,087 Property 9
15,050 107,510 122,560 Income 10
37,137 107,510 144,647Subtotal 11
12
Oregon: 13
24,270,769 23,979,696 11,864,822 Property 14
1,439,343 1,442,029 46,369 Unemployment 15
12,693,784 -945,826 11,747,958 Excise-Income 16
43,458 10,049 53,507 City of Portland-Income 17
1,494,919 1,475,126 727,667 Department of Energy 18
1,000,374 948,617 396,062 Tri-Met 19
1,259 1,259 Lane County 20
29,046,163 29,447,424 4,539,937 Franchise 21
69,990,069 -935,777 69,095,616 12,592,489 4,982,368Subtotal 22
23
Texas: 24
234 234 Unemployment 25
234 234Subtotal 26
27
Utah: 28
72,373,158 72,351,881 729,731 Property 29
18,122,058 -2,986,220 15,135,838 Income 30
194,970 193,477 5,092 Unemployment 31
1,208 1,208 Navajo Nation 32
3,397,402 3,212,088 459,962 Use 33
94,088,796 -2,986,220 90,894,492 1,194,785Subtotal 34
35
Washington: 36
10,789,701 9,539,701 11,250,000 Property 37
62,135 52,906 10,631 Unemployment 38
24,790 26,281 2,390 Business & Occupation 39
12,752,327 12,692,327 1,335,000 Public Utility 40
12,597,489
FERC FORM NO. 1 (ED. 12-96)Page 262.1
TOTAL41 426,729,279 424,577,879 1,906,359 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 (Continued)
PacifiCorp X
/ /2016/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.
152,601 42,000 1
-34,174 5,755,168 2,830,411 2
3
4
31,184 16,242 5
31,184 16,242 6
7
8
22,087 9
-22,175 144,735 10
-22,175 166,822 11
12
13
1,058,502 22,921,194 12,155,895 14
1,442,029 49,055 15
-2,212,032 13,959,990 16
-8,557 62,064 17
1,475,126 747,460 18
948,617 344,305 19
1,259 20
29,447,424 4,941,198 21
1,229,818 67,865,798 12,903,355 5,334,558 22
23
24
234 25
234 26
27
28
28,559 72,323,322 708,454 29
-2,622,771 17,758,609 30
193,477 3,599 31
1,208 32
3,212,088 274,648 33
811,353 90,083,139 986,701 34
35
36
298,142 9,241,559 10,000,000 37
52,906 1,402 38
26,281 3,881 39
12,692,327 1,275,000 40
FERC FORM NO. 1 (ED. 12-96)Page 263.1
41 12,903,355 425,846,027 883,252 42,398,601
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
/ /2016/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a) (b) (c) (d) (e) (f)
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
1,352,196 1,487,586 103,284 Natural Gas Use Tax 1
643,026 613,867 70,697 Use 2
24,459 24,459 Forest excise tax 3
25,648,634 24,437,127 12,772,002Subtotal 4
5
Wyoming: 6
15,660,709 16,203,823 7,558,796 Property 7
1,770,434 2,051,320 1,767,169 Wind Generation Tax 8
79,646 78,722 2,746 Unemployment 9
1,988,258 2,008,258 274,900 Franchise 10
1,747,635 1,779,917 139,621 Use 11
71,079 71,079 Annual Report 12
21,317,761 22,193,119 9,743,232Subtotal 13
14
2,603State Other: 15
16
Miscellaneous: 17
25,020 25,020 Goshute Possessory 18
245,033 245,033 Sho-Ban Possessory 19
39,605 39,630 19,790 Navajo Possessory 20
39,261 39,261 Ute Possessory 21
70,038 70,038 Crow Possessory 22
66,534 66,534 Umatilla Possessory 23
485,491 485,516 22,393Subtotal 24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
12,597,489
FERC FORM NO. 1 (ED. 12-96)Page 262.2
TOTAL41 426,729,279 424,577,879 1,906,359 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 (Continued)
PacifiCorp X
/ /2016/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.
1,487,586 238,674 1
613,867 41,538 2
24,459 3
2,476,960 21,960,167 11,560,495 4
5
6
99,645 16,104,178 8,101,910 7
2,051,320 2,048,055 8
78,722 1,822 9
2,008,258 294,900 10
1,779,917 171,903 11
71,079 12
1,958,284 20,234,835 10,618,590 13
14
2,603 15
16
17
25,020 18
245,033 19
39,630 19,815 20
39,261 21
70,038 22
66,534 23
485,516 22,418 24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 263.2
41 12,903,355 425,846,027 883,252 42,398,601
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, Federal, 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.: 12 Column: f
Represents a reclassification of the balance at end of year to Account 143, Other accounts
receivable.
Schedule Page: 262 Line No.: 12 Column: l
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262 Line No.: 16 Column: l
$126,974 Account 408.2, Taxes other than income taxes, other income and deductions
1,487 Account 589, Rents
$128,461
Schedule Page: 262 Line No.: 17 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 18 Column: f
Represents a reclassification of a portion of the balance at end of year to Account 146,
Accounts receivable from associated companies.
Schedule Page: 262 Line No.: 18 Column: l
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262 Line No.: 19 Column: l
Charged to same account as related goods.
Schedule Page: 262 Line No.: 24 Column: l
$ 1,050 Account 408.2, Taxes other than income taxes, other income and deductions
235,882 Account 107, Construction work in progress
$236,932
Schedule Page: 262 Line No.: 25 Column: f
Represents a reclassification of the balance at end of year to Account 143, Other accounts
receivable.
Schedule Page: 262 Line No.: 29 Column: l
$ 1,075 Account 408.2, Taxes other than income taxes, other income and deductions
20,941 Account 107, Construction work in progress
$ 22,016
Schedule Page: 262 Line No.: 30 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.: 30 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.: 32 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 33 Column: l
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Charged to same account as related goods.
Schedule Page: 262 Line No.: 38 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.: 38 Column: l
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262 Line No.: 39 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 10 Column: f
Represents a reclassification of the balance at end of year to Account 143, Other accounts
receivable.
Schedule Page: 262.1 Line No.: 10 Column: l
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262.1 Line No.: 14 Column: l
$ 23,430 Account 408.2, Taxes other than income taxes, other income and deductions
126,911 Account 589, Rents
908,161 Account 107, Construction work in progress
$1,058,502
Schedule Page: 262.1 Line No.: 15 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 16 Column: 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.: 16 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.: 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.: 19 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
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.: 25 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 29 Column: l
Account 408.2, Taxes other than income taxes, other income and deductions
Schedule Page: 262.1 Line No.: 30 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.: 30 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.: 31 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
work in progress.
Schedule Page: 262.1 Line No.: 33 Column: l
Charged to same account as related goods.
Schedule Page: 262.1 Line No.: 37 Column: l
$ 37,622 Account 408.2, Taxes other than income taxes, other income and deductions
260,520 Account 107, Construction work in progress
$ 298,142
Schedule Page: 262.1 Line No.: 38 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.2 Line No.: 1 Column: l
Account 151, Fuel stock
Schedule Page: 262.2 Line No.: 2 Column: l
Charged to same account as related goods.
Schedule Page: 262.2 Line No.: 3 Column: l
Account 408.2, Taxes other than income taxes, other income and deductions
Schedule Page: 262.2 Line No.: 7 Column: l
$ 3,788 Account 408.2, Taxes other than income taxes, other income and deductions
15,134 Account 589, Rents
80,723 Account 107, Construction work in progress
$ 99,645
Schedule Page: 262.2 Line No.: 9 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.2 Line No.: 11 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
2016/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
/ /2016/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% 20,324,195 411.4, 420 4,452,276 5
30% 257,462 420 11,695 6
Idaho 108,299 411.4, 420 10,698 7
TOTAL 20,689,956 4,474,669 8
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
9
10
Idaho 190 -39,394 1,815,166 446,700 420 178,200 11
Total Nonutility -39,394 1,815,166 446,700 178,200 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
/ /2016/Q4
Line
No.ADJUSTMENT EXPLANATIONAverage Periodof Allocationto Income
1
2
3
4
15,871,919 38.82 and 30 5
245,767 24 6
97,601 38.82 and 30 7
16,215,287 8
9
10
2,044,272 30 11
2,044,272 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% $20,003,128 - $ - 411.4(1) $4,334,949 $ - $15,668,179 38.82
10% 321,067 - - 420(2) 117,327 - 203,740 30
$20,324,195 $ - $4,452,276 $ - $15,871,919
(1) Internal Revenue Code 46(f)2
(2) Internal Revenue Code 46(f)1
Schedule Page: 266 Line No.: 6 Column: e
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 $ 53,634 - $ - 411.4(1) $ 6,452 $ - $ 47,182 38.82
Idaho 54,665 - - 420(2) 4,246 - 50,419 30
$ 108,299 $ - $ 10,698 $ - $ 97,601
(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
2016/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
/ /2016/Q4
Line
No.
Description and Other DEBITS
Credits
Account(c)(b)(a)
Balance at
End of Year
(d)
Deferred Credits Amount
(e)
Balance at
Beginning of Year Contra
(f)
1. Report below the particulars (details) called for concerning other deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
5,895,811Working Capital Deposits 5,093,355 802,456131 1
5,860,476Reclamation Costs - Trapper Mine 6,072,271 211,795 2
Western Coal Carriers Benefits 3
11,791,000 Obligation 10,883,000 908,000131 4
114,470Program Incentives 114,470921 5
9,671,098Deferred Compensation Plans 8,306,137 1,343,311 2,708,272131, 920 6
8,484,695Long-Term Incentive Plan 10,966,099 3,068,906 587,502426.5 7
Regulated Environmental 8
22,938,098 Liabilities 26,150,079 7,748,757 4,536,776131, 182.3 9
Non-Regulated Environmental 10
2,222,843 Liabilities 2,093,646 99,464 228,661131, 426.5 11
Unearned Joint Use Pole 12
2,864,521 Contact 2,900,121 6,244,123 6,208,523454 13
3,400Misc. Security Deposits 5,400 3,800 1,800131, 172 14
906,925Lease Incentives 800,614 106,311931 15
120,418Cowlitz/Lewis River O&M (1) 122,234 293,362 291,546539 16
17,975Employee Housing Security Deposits 18,900 5,200 4,275131, 545 17
413,417Cogeneration Bonds-Sunnyside 413,417 18
2,392,500Transmission Security Deposits 1,638,000 754,500131 19
234,282Transmission Service Deposits 358,196 123,914 20
557,618MCI F.O.G. Wire Lease (1) 557,201 3,343,206 3,343,623454 21
97,918,622Unamortized Contract Values 90,593,913 1,785,425 9,110,134242 22
121,583,766Loss Contingency - USA Power 1,007,891 122,591,657131 23
2,550,482Accrued Right-of-Way Obligations 3,813,087 1,768,105 505,500566 24
Navajo Tribal Utility Authority 25
480,148 Escrow 466,678 946,826131 26
95,833Facility Use Fee (2) 45,833 50,000456 27
Eagle Mountain Contract 28
4,107,880 Liability (2) 1,504,075 2,603,805555 29
Energy Supply Management 30
250,000 Deferral 370,833 350,000 229,167456 31
Deer Creek Accrued Royalties 3,547,353 3,547,353 32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-94) Page 269
47 TOTAL 31,411,290 156,633,804 176,253,764 301,476,278
Schedule Page: 269 Line No.: 13 Column: a
The weighted average remaining life is one year.
Schedule Page: 269 Line No.: 15 Column: a
The weighted average remaining life is eight 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
2016/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
/ /2016/Q4
Line
No.Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable
property.
2. For other (Specify),include deferrals relating to other income and deductions.
1 Accelerated Amortization (Account 281)
2 Electric
3 Defense Facilities
2,392,006 23,398,385 285,986,998 4 Pollution Control Facilities
5 Other (provide details in footnote):
6
7
2,392,006 23,398,385 285,986,998 8 TOTAL Electric (Enter Total of lines 3 thru 7)
9 Gas
10 Defense Facilities
11 Pollution Control Facilities
12 Other (provide details in footnote):
13
14
15 TOTAL Gas (Enter Total of lines 10 thru 14)
16
2,392,006 23,398,385 285,986,998 17 TOTAL (Acct 281) (Total of 8, 15 and 16)
18 Classification of TOTAL
1,523,140 20,016,569 251,774,964 19 Federal Income Tax
868,866 3,381,816 34,212,034 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
/ /2016/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
306,993,377 4
5
6
7
306,993,377 8
9
10
11
12
13
14
15
16
306,993,377 17
18
270,268,393 19
36,724,984 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
/ /2016/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 4,414,667,387 580,057,875 465,799,659 2
Gas 3
4
TOTAL (Enter Total of lines 2 thru 4) 4,414,667,387 580,057,875 465,799,659 5
Nonutility 6
7
8
TOTAL Account 282 (Enter Total of lines 5 thru 8) 4,414,667,387 580,057,875 465,799,659 9
Classification of TOTAL 10
Federal Income Tax 3,913,838,011 488,380,217 387,589,122 11
State Income Tax 500,829,376 91,677,658 78,210,537 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
/ /2016/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
182.3 653,619 653,619 4,518,977,533 12,627,237182.3 2,679,167 2
3
4
653,619 653,619 4,518,977,533 12,627,237 2,679,167 5
6
7
8
653,619 653,619 4,518,977,533 12,627,237 2,679,167 9
10
579,306 579,306 4,005,871,103 10,541,888 1,783,885 11
74,313 74,313 513,106,430 2,085,349 895,282 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
/ /2016/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
75,601,640 35,015,081 639,634,358Regulatory Assets 3
9,695,623 9,172,918 17,892,378Other 4
5
6
7
8
85,297,263 44,187,999 657,526,736TOTAL 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
85,297,263 44,187,999 657,526,736TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19
Classification of TOTAL 20
75,313,779 39,122,329 578,903,244Federal Income Tax 21
9,983,484 5,065,670 78,623,492State 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
/ /2016/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
585,921,442 39,048,246 62,379,675 35,103,755 24,898,683 3
17,215,789 12,831,957190, 283190, 283 8,155,245 9,124,337 13,954,933 4
5
6
7
8
603,137,231 51,880,203 70,534,920 44,228,092 38,853,616 9
10
11
12
13
14
15
16
17
18
603,137,231 51,880,203 70,534,920 44,228,092 38,853,616 19
20
531,020,244 45,486,262 62,217,336 39,057,541 34,018,017 21
72,116,987 6,393,941 8,317,584 5,170,551 4,835,599 22
23
FERC FORM NO. 1 (ED. 12-96)Page 277
NOTES (Continued)
Schedule Page: 276 Line No.: 3 Column: g
Account 182.3, Other regulatory assets
Account 190, Accumulated deferred income taxes
Schedule Page: 276 Line No.: 3 Column: i
Account 182.3, Other regulatory assets
Account 190, Accumulated deferred income taxes
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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
/ /2016/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)
4,404,503 4,404,503DSM Balancing Account - UT 1
2,342,401 26,490,248 3,286,888 27,434,735Oregon Energy Conservation Charge 131,232 2
4,840,097 4,840,097Deferred Excess Net Power Costs - UT 3
132,174 141,321 9,147Deferred Excess Net Power Costs - WA Hydro 182.3 4
8,863,736 8,863,736Deferred Excess Net Power Costs - WA 5
3,186,133 3,186,133Deferred Excess Net Power Costs - WY 6
408,173 408,173Deferred Excess RECs in Rates - UT 7
523,321 523,321Deferred Excess RECs/SO2 in Rates - WY 8
968,175 906,139 62,036Income Tax Reg. Liability - WA Flow Through 411.1 9
10,803,718 2,338,409 8,465,568 259Investment Tax Credit Regulatory Liability 190 10
968,851 897,059 462,729 390,937Tax on Bonus Depreciation - WY (1)440,442 11
718,381 11,292,335 411,834 10,985,788Greenhouse Gas Allowance Compliance - CA 456,555,419 12
1,530,061 312,936 1,217,125Solar Feed-In Tariff Deferral - CA 440,442,444 13
13,835,120 4,994,002 15,850,031 7,008,913Solar Incentive Program - UT 440,442,444,445 14
33,376 34,025 649Renewable Portfolio Standards Compliance - OR 15
1,264,950 25,235 1,581,730 342,015Utah Home Energy Lifeline 142 16
1,614,504 404,013 2,005,596 795,105Washington Low Income Program 142 17
614,202 724,546 1,338,748California Energy Savings Assistance Program 908 18
11,797,468 20,048,925 8,251,4572013 FERC Rate True-up - OR 19
7,427,115 2,007,237 5,419,878Asset Retirement Obligations Reg. Difference 230 20
54,637 1,175,277 1,120,640BPA Balancing Account - WA 21
3,643,237 23,528 3,630,232 10,523BPA Balancing Account - ID 440,442 22
2,998,214 2,188,982 2,546,484 1,737,252Blue Sky - OR 440,442 23
206,954 134,741 258,249 186,036Blue Sky - WA 440,442 24
180,416 21,237 231,006 71,827Blue Sky - CA 440,442 25
4,589,446 846,254 6,740,649 2,997,457Blue Sky - UT 440,442 26
157,316 59,224 152,127 54,035Blue Sky - ID 440,442 27
484,045 117,508 564,191 197,654Blue Sky - WY 440,442 28
5,219,979 8,782,141 3,562,162Injuries & Damages Reserve - OR 29
494,674 52,607 555,611 113,544Property Insurance Reserve - ID 924 30
4,287,834 3,337,234 3,102,836 2,152,236Property Insurance Reserve - UT 924 31
88,711 88,711Property Insurance Reserve - WY 32
1,854,938 2,893,603 1,038,665Depreciation Deferral - OR 33
268,334 268,334Depreciation Deferral - WA (1)440,442,444 34
2,801,877 2,801,877Deferred Steam Accel. Depreciation - WA 35
3,432 3,432Merwin Fish Collector Project - WA 36
1,006,205 524,790 1,530,995Direct Access 5-Year Opt Out - OR (10)442 37
38
39
40
FERC FORM NO. 1/3-Q (REV 02-04) Page 278
41 TOTAL 96,450,762 58,478,990 115,848,090 77,876,318
Schedule Page: 278 Line No.: 10 Column: a
Weighted average remaining life is 39 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
2016/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
/ /2016/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
1,781,722,516(440) Residential Sales 1,851,336,999 2
(442) Commercial and Industrial Sales 3
1,556,424,635Small (or Comm.) (See Instr. 4) 1,544,450,403 4
1,435,608,671Large (or Ind.) (See Instr. 4) 1,428,765,000 5
19,942,747(444) Public Street and Highway Lighting 20,068,906 6
16,902,061(445) Other Sales to Public Authorities 21,985,292 7
(446) Sales to Railroads and Railways 8
(448) Interdepartmental Sales 9
4,810,600,630TOTAL Sales to Ultimate Consumers 4,866,606,600 10
269,833,622(447) Sales for Resale 177,098,460 11
5,080,434,252TOTAL Sales of Electricity 5,043,705,060 12
(Less) (449.1) Provision for Rate Refunds 13
5,080,434,252TOTAL Revenues Net of Prov. for Refunds 5,043,705,060 14
Other Operating Revenues 15
9,141,277(450) Forfeited Discounts 9,371,769 16
5,531,248(451) Miscellaneous Service Revenues 5,643,618 17
(453) Sales of Water and Water Power 75,033 18
19,100,070(454) Rent from Electric Property 20,494,188 19
(455) Interdepartmental Rents 20
28,322,174(456) Other Electric Revenues 21,137,492 21
92,780,346(456.1) Revenues from Transmission of Electricity of Others 100,653,551 22
(457.1) Regional Control Service Revenues 23
(457.2) Miscellaneous Revenues 24
25
154,875,115TOTAL Other Operating Revenues 157,375,651 26
5,235,309,367TOTAL Electric Operating Revenues 5,201,080,711 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
/ /2016/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
15,565,510 1,574,480 1,598,695 16,057,814 2
3
17,261,893 201,691 205,329 16,856,945 4
21,402,658 33,305 33,258 20,924,472 5
140,686 3,496 3,470 141,491 6
270,465 3 2 337,215 7
8
9
54,641,212 1,812,975 1,840,754 54,317,937 10
8,889,451 6,640,965 11
63,530,663 1,812,975 1,840,754 60,958,902 12
13
63,530,663 1,812,975 1,840,754 60,958,902 14
Page 301
Line 12, column (b) includes $ of unbilled revenues.
Line 12, column (d) includes MWH relating to unbilled revenues
274,945,000
3,291,966
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:
2016 2015
Account service charges -
disconnects/reconnects/returned check charges $ 4,337,678 $ 4,450,368
Customer contract flat rate billings 1,265,230 1,038,530

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:
2016 2015
Amortization of California greenhouse gas
allowance revenue $ 11,196,617 $ 11,212,184
Wind-based ancillary services 10,840,910 9,683,694
Energy exchange credits 4,908,564 10,083,346
Flyash/by-product sales 4,323,364 5,099,321
Revenue from generation interconnection and
transmission service request studies 1,244,979 1,077,939
Timber sales 727,541 (a)
Maintenance charges for work on transmission facilities 524,742 336,138
Steam sales 468,274 665,336
Phase shifting equipment fee from
Western Electricity Coordinating Council 404,456 1,130,302
Service territory fixed cost recovery fee 351,447 317,733
Deferral of Oregon retail customers' allocated share of
the incremental Open Access Transmission Tariff revenues
associated with FERC Docket No. ER11-3643-000 (7,093,960) (5,114,029)
Renewable energy credit sales, including
amortization and deferrals (7,116,003) (6,901,286)
Power sale and exchange agreements (a) 550,096
(a) 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
2016/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
/ /2016/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
812 4 06LNX00311 - LINE EXT 80%GTY
1,178 221 5,330 0.1170 137,880 5 06NETMT135 - RES NET MTR
285 311 916 0.2921 83,249 6 06OALT015R-OUTD AR LGT SR
165,079 17,351 9,514 0.1333 22,000,937 7 06RESD000D-RES SRVC
112,830 11,186 10,087 0.1337 15,090,056 8 06RESDDL06-CA LOW INCOME
1,240 477 2,600 0.2189 271,375 9 06RGNSV025-CA SMALL GEN
162 7 23,143 0.1003 16,249 10 06RESD0DM9 - MULTI FAMILY
1,134 16 70,875 0.0895 101,485 11 06RESD0DS8-MULT FAM SBMET
73,724 6,848 10,766 0.1350 9,951,186 12 06RESD00DN - RES SVC DEL NO
-1,645,230 13 REVENUE_ACCT ADJ
1,755,548 14 DSM REVENUE-RESIDENTIAL
19,678 15 BLUE SKY REV-RESIDENTIAL
121,356 16 SOLAR FEED-IN REVENUE
1,000 17 UNBILLED REV - UNCOLLECTIBLE
6,840 0.1499 1,025,000 18 UNBILLED REVENUE
19
20 IDAHO
1,155 21 07LNX00010-MNTHLY 80%GUAR
2,154 22 07LNX00035-ADV 80%MO GUAR
1,988 167 11,904 0.1007 200,226 23 07NETMT135 - ID RES NET MTR
10 1 10,000 0.3859 3,859 24 07OALCO007-CUST OWN LIGHT
97 122 795 0.4155 40,300 25 07OALT07AR-SECURITY AR LG
459,502 48,864 9,404 0.1168 53,649,081 26 07RESD0001-RES SRVC
208,460 12,476 16,709 0.1011 21,069,190 27 07RESD0036-RES SRVC-OPTIO
306 2 153,000 0.0763 23,363 28 07RGNSV06A-LRG GEN SVC-RES
8,071 985 8,194 0.1161 936,937 29 07RGNSV23A-SM GEN SVC-RES
-364,717 30 REVENUE_ACCT ADJ
1,892,920 31 DSM REVENUE-RESIDENTIAL
53,432 32 BLUE SKY REV-RESIDENTIAL
-7,000 33 UNBILLED REV - UNCOLLECTIBLE
34,214 0.1040 3,557,000 34 UNBILLED REVENUE
35
36 OREGON
1 37 01CHCK000R-RES CHECK MTR
4,842,357 0.0597 289,273,265 38 01COST0004 - 01RESD0004
94,191 0.0600 5,651,543 39 01COSTR023 RES GEN SRV CST
43,218 0.0602 2,602,794 40 01COSTR028, OR RES GEN SVC
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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 1 01FXRENEWR - FIXED
44,674 0.0589 2,630,846 2 01HABIT004 - 01RESD0004
174 0.0619 10,779 3 01HABTR023-RES GEN SVC HAB
9,825 4 01LNX00102-LINE EXT 80% G
4,458 5 01LNX00109-REF/NREF ADV +
188 6 01LNX00300 - LINE EXT 80% GTY
232 7 01LNX00311 - LINE EXT 80% GTY
3,752 1,637,576 8 01NETMT135-NET METERING
21 12,552 9 01NMTOU135-TOU NET METERING
2,224 2,555 870 0.1631 362,726 10 01OALTB15R-OUTD AR LGT RE
15,752 0.0617 971,566 11 01PTOU0004 - 01RESD0004
5 0.0466 233 12 01PTOU0005-01RESEV05T TOU
318,137 0.0578 18,392,266 13 01RENEW004 - 01RESD0004
571 0.0595 34,000 14 01RENWR023-RENEW USAGE
487,137 286,567,470 15 01RESD0004-RES SRVC
1,121 822,045 16 01RESD004T - RES TIME OPT
1 326 17 01RESEV05T-ELECT VEHICLE
16,933 7,172,026 18 01RGNSB023-SMALL GENERAL
200 1,283,575 19 01RGNSB028 -GEN SVC > 30 KW
56 141,719 20 01RNETM023-NET METER RES
3 21 01UPPL000R-BASE SCH FALL
463 368,107 22 01VIR04136-VOLUME INCENTIVE
-429,396 23 REVENUE ADJ - DEF NPC
-2,110,813 24 REVENUE_ACCT ADJ
14,934,257 25 DSM REVENUE-RESIDENTIAL
653,015 26 BLUE SKY REV-RESIDENTIAL
1,803,388 27 SOLAR FEED-IN REVENUE
-1,000 28 UNBILLED REV - UNCOLLECTIBLE
120,767 0.1264 15,260,000 29 UNBILLED REVENUE
30
31 UTAH
-4 32 08BLSKY01R-BLUESKY ENERGY
835 33 08CFR00001-MTH FACILITY S
1 34 08CHCK000R-UT RES CHECK M
99,383 35 08COOLKPRR -COOL KEEPER
2,793 36 08LNX00001-MTHLY 80% GUAR
396 37 08LNX00005-MTHLY MIN GUAR
24,234 38 08LNX00013-80% MNTHLY MIN
1,656 39 08LNX00108-ANN COST MTHLY
11,554 8 1,444,250 0.0766 885,121 40 08MHTP0006-MOBILE HOME &
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
120 1 120,000 0.0802 9,626 1 08MHTP0023-MOBILE HOME &
48,943 10,828 4,520 0.1195 5,849,091 2 08NETMT135 - NET MTR
49 8 6,125 0.1086 5,319 3 08NMT03135-LOW INCOME RES
2,588 2,765 936 0.2857 739,388 4 08OALT007R-SECURITY AR LG
1 2 500 0.1100 110 5 08PTLD000R-POST TOP LIGHT
6,425,562 735,335 8,738 0.1116 717,255,319 6 08RESD0001-RES SRVC
3,149 387 8,137 0.1097 345,310 7 08RESD0002-RES SRVC-OPTIO
179,763 24,390 7,370 0.1096 19,701,464 8 08RESD0003-LIFELINE PRGRM
94,718 242 391,397 0.0777 7,359,254 9 08RGNSV006-GEN SRVC-RES
94,881 13,026 7,284 0.1120 10,622,324 10 08RGNSV023-GEN SRVC-RES
9,721 25 388,840 0.0859 834,818 11 08RGNSV06A-UT SM GEN SVC
30 1 30,000 0.1405 4,214 12 08RGNSV06B-UT SM GEN SVC
1,392 8 174,000 0.0993 138,229 13 08RNM06135 - UT NET MTR, GEN
666 95 7,011 0.1056 70,337 14 08RNM23135 - UT NET MTR, GEN
4 15 08UPPL000R-BASE SCH FALL
13,865,997 16 REVENUE ADJ - DEF NPC
-5,451,075 17 REVENUE_ACCT ADJ
29,451,444 18 DSM REVENUE-RESIDENTIAL
702,357 19 BLUE SKY REV-RESIDENTIAL
1,883,729 20 SOLAR FEED-IN REVENUE
46,000 21 UNBILLED REV - UNCOLLECTIBLE
23,210 0.1068 2,478,000 22 UNBILLED REVENUE
23
24 WASHINGTON
2,605 25 02LNX00109-REF/NREF ADV +
5,029 462 10,885 0.0996 501,095 26 02NETMT135 - WA RES NET MTR
993 1,078 921 0.1517 150,626 27 02OALTB15R-WA OUTD AR LGT
1,413,531 101,402 13,940 0.0943 133,293,557 28 02RESD0016-WA RES SRVC
62,028 4,540 13,663 0.0936 5,807,396 29 02RESD0017-BILL ASSISTANCE
2,107 85 24,788 0.1035 218,004 30 02RESD0018-WA 3 PHASE RES
345 16 21,563 0.1012 34,922 31 02RESD018X-WA 3 PHASE RES
20,871 3,471 6,013 0.1180 2,463,039 32 02RGNSB024-WA SM GEN SVC
1,058,271 33 REVENUE ADJ - DEF NPC
-6,055,394 34 REVENUE_ACCT ADJ
4,725,777 35 DSM REVENUE-RESIDENTIAL
110,987 36 BLUE SKY REV-RESIDENTIAL
3,000 37 UNBILLED REV - UNCOLLECTIBLE
66,880 0.1024 6,846,000 38 UNBILLED REVENUE
39
40
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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 WYOMING
-2 2 05BLSKY01R-BLUESKY ENERGY
751 3 05LNX00102-LINE EXT 80% G
1,338 152 8,803 0.1216 162,669 4 05NETMT135 - EXP PARTIALREQ
864 1,018 849 0.1402 121,133 5 05OALT015R-OUTD AR LGT SR
879,200 101,390 8,671 0.1122 98,673,675 6 05RESD0002-WY RES SRVC
9,309 1,459 6,380 0.1231 1,145,773 7 05RGNSV025-WY SM GEN SVC
1 86 8 09OALT207R-SECURITY AR LG
-68,513 9 REVENUE ADJ - DEF NPC
-41,901 10 REVENUE_ACCT ADJ
777,553 11 DSM REVENUE-RESIDENTIAL
13,965 12 DSM REVENUE-RES GEN SVC
96,166 13 BLUE SKY REV-RESIDENTIAL
11,000 14 UNBILLED REV - UNCOLLECTIBLE
27,899 0.1153 3,217,000 15 UNBILLED REVENUE
603 16 05LNX00109-REF/NREF ADV +
113,236 12,425 9,114 0.1137 12,878,388 17 05RESD0002-WY RES SRVC
428 133 3,218 0.1680 71,903 18 05RGNSV025- SM GEN SVC-RES
71 85 835 0.2490 17,676 19 09OALT207R-SECURITY AR LG
285 23 12,391 0.1209 34,461 20 05NETMT135 - EXP PARTIAL REQ
2 21 09RES00002
4 22 09RESD0002
184,797 23 DSM REVENUE-RESIDENTIAL
986 24 DSM REVENUE-RES GEN SVC
18,612 25 BLUE SKY REV-RESIDENTIAL
-137 0.1022 -14,000 26 UNBILLED REVENUE
27
-126,838 28 LESS MULTIPLE BILLINGS
29
16,057,814 1,598,695 10,044 0.1153 1,851,336,999 30 TOTAL RESIDENTIAL SALES
31
32 COMMERCIAL SALES
33 CALIFORNIA
53,181 6,469 8,221 0.1786 9,498,208 34 06GNSV0025-CA GEN SRVC
863 85 10,153 0.1963 169,444 35 06GNSV025F-GEN SRVC-< 20
80,622 1,046 77,076 0.1604 12,927,829 36 06GNSV0A32-GEN SRVC-20 KW
31,172 9 3,463,556 0.1082 3,371,795 37 06LGSV048T-LRG GEN SERV
2,471 1 2,471,000 0.1079 266,671 38 06NMT48135-CA GEN SVC NET
64,156 157 408,637 0.1357 8,706,109 39 06LGSV0A36-LRG GEN SRVC-O
3,971 40 06LNX00102-LINE EXT 80% GTY
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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.
3,775 1 06LNX00105-CNTRCT $ MIN G
95,113 2 06LNX00109-REF/NREF ADV +
722 3 06LNX00300 - 80% MTHLY MIN
17,297 4 06LNX00311 - LINE EXT 80% GTY
2,259 4 564,750 0.1389 313,819 5 06NMT36135-G SVC NT ->100
660 479 1,378 0.2957 195,172 6 06OALT015N-OUTD AR LGT SR
164 36 4,556 0.2315 37,966 7 06RCFL0042-AIRWAY & ATHLE
66 10 6,600 0.1825 12,045 8 06NMT25135-CA GEN SVC NET
674 13 51,846 0.1862 125,479 9 06NMT32135-CA GEN SVC NET
1,792 10 06LNX00110-REF/NREF ADV +
-1,096,878 11 REVENUE_ACCT ADJ
1,133,181 12 DSM REVENUE-COMMERCIAL
1,524 13 BLUE SKY REV-COMMERCIAL
114,661 14 SOLAR FEED-IN REVENUE
1,485 0.1609 239,000 15 UNBILLED REVENUE
16
17 IDAHO
4,806 95 50,589 0.0898 431,609 18 07CISH0019-COMM & IND SPA
235,865 1,003 235,160 0.0843 19,886,222 19 07GNSV0006-GEN SRVC-LRG P
41,261 2 20,630,500 0.0654 2,698,737 20 07GNSV0009-GEN SRVC-HI VO
142,125 6,587 21,577 0.1019 14,486,853 21 07GNSV0023-GEN SRVC-SML P
898 2 449,000 0.0852 76,499 22 07GNSV0035-GEN SRVCOPTION
24,624 181 136,044 0.0909 2,237,499 23 07GNSV006A-GEN SRVC-LRG P
24,814 1,255 19,772 0.1018 2,526,740 24 07GNSV023A-GEN SRVC-SML P
4 5 800 0.1020 408 25 07GNSV023F-GEN SRVC SML P
5,810 26 07LNX00010-MNTHLY 80%GUAR
217,767 27 07LNX00035-ADV 80%MO GUAR
53,578 28 07LNX00040-ADV+REFCHG+80%
254 173 1,468 0.3924 99,660 29 07OALT007N-SECURITY AR LG
10 10 1,000 0.3940 3,940 30 07OALT07AN-SECURITY AR LG
24,045 31 07LNX00312 - ID LINE EXT
1,780 4 445,000 0.0867 154,300 32 07NMT06135 - NET MTR - LG GEN
1,003 21 47,762 0.0883 88,539 33 07NMT23135 - NET MTR - SM GEN
751 34 07LNX00015-ANNUAL 80%GUAR
27,741 35 07LNX00311 - LINE EXT 80% GTY
6,099 36 07LNX00300 - 80% MTHLY MIN
-214,593 37 REVENUE_ACCT ADJ
1,078,790 38 DSM REVENUE-COMMERCIAL
1 5,669 39 BLUE SKY REV-COMMERCIAL
13,937 0.0862 1,202,000 40 UNBILLED REVENUE
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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 OREGON
984,643 0.0582 57,306,127 2 01COST0023, OR GEN SRV, COST
907,439 0.0489 44,338,916 3 01COST0048 - 01LGSV0048
2,860 0.0619 177,059 4 01COST023F - GEN SRV COST
23,262 0.0592 1,377,468 5 01COSTB023 - OR GEN SRV,
1,105,059 0.0520 57,447,941 6 01COSTL030 - OR LRG GEN SRV,
1,894,258 0.0603 114,268,242 7 01COSTS028, OR GEN SERV
2,863 1,587,840 8 01GNSB0023, OR GEN SRV BPA
304 2,014,352 9 01GNSB0028, OR GEN SRV BPA
56 30,270 10 01GNSB023T - OR GEN SRV TOU
56,171 53,326,987 11 01GNSV0023, GEN SRV < 30 KW
8,940 57,406,844 12 01GNSV0028, GEN SRV > 30 KW
10,360 765 13,542 0.1584 1,641,056 13 01GNSV023F - GEN SRV - FLAT RA
160 2 80,000 0.0921 14,739 14 01GNSV023M - GEN SRV, MANUAL
199 161,759 15 01GNSV023T, OR GEN SRV, TOU
2,814 0.0592 166,668 16 01HABT0023, OR HABITAT BLEND
26 0.0613 1,593 17 01HABTB023 - OR HABITAT BLEND
21 939,194 18 01LGSB0030, GEN DEL SRV, > 200
630 29,050,037 19 01LGSV0030 - LG GEN SRV > 1000
90 16,849,563 20 01LGSV0048-1000KW AND OVR
58,872 1 58,872,000 0.0627 3,691,026 21 01LGSV048M-LRG GEN SRVC 1
2,360 22 01LNX00100-LINE EXT 60% G
514,572 23 01LNX00102-LINE EXT 80% G
2,427 24 01LNX00103-LINE EXT 80% G
13,548 25 01LNX00105-CNTRCT $ MIN G
1,077,598 26 01LNX00109-REF/NREF ADV +
12,224 27 01LNX00110-REF/NREF ADV +
178,121 28 01LNX00311 - LINE EXT 80% GTY
306 29 01LNX00120 - LINE EXT 60% GTY
201,683 30 01LNX00300 - LINE EXT 80% GTY
40,688 5 8,137,600 0.0985 4,009,173 31 01LPRS047M-PART REQ SRVC
35 32 01NM23T135-OR NET MTR TOU
273 232,093 33 01NMT23135 - NET MTR GEN < 30
156 1,175,220 34 01NMT28135 - NET MTR GEN > 30
26 1,296,887 35 01NMT30135 -NET MTR GEN > 200
3 365,453 36 01NMT48135-NET MTR GEN SVC =
5,451 2,833 1,924 0.1481 807,121 37 01OALT015N-OUTD AR LGT NR
1,455 1,058 1,375 0.1678 244,079 38 01OALTB15N-OUTD AR LGT NR
2,833 0.0590 167,270 39 01PTOU0023, OR GEN SRV, TOU
462 0.0602 27,808 40 01PTOUB023, OR GEN SRV, TOU
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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.
1,423 104 13,683 0.0989 140,665 1 01RCFL0054-REC FIELD LGT
9,007 0.0595 535,873 2 01RENW0023, OR RENW USAGE
92 0.0618 5,683 3 01RENWB023 - OR RENEWABLE
3,054 0.0525 160,185 4 01STDAY023 - DAY STD OFR SCH
13,048 0.0539 703,146 5 01STDAY028 - DAY STD OFF SCH
4,487 0.0467 209,359 6 01STDAY030 - STD DAY OFF SCH
105 156,342 7 01VIR23136-VOL INC <=30KW
98 648,988 8 01VIR28136-VOL INC >30KW
7 307,160 9 01VIR30136-VOL INC >200KW
1 127,245 10 01VIR48136-VOL INC >1000KW
1 82,745 11 01LGSB0048 - LG GSVC > 1000
419 1 419,000 0.0954 39,976 12 01LGSV028M - LGSV, <1000 kW, M
10 157,826 13 01GNSV0728 - GEN SVC DIR ACC
18 2,277,912 14 01GNSV0730 -GEN SVC DIR ACC
3 5,224,840 15 01GNSV0748 LG GEN SVC DIR
-322,734 16 REVENUE ADJ - DEF NPC
-779,156 17 REVENUE_ACCT ADJ
10,013,396 18 DSM REVENUE-COMMERCIAL
101 941,521 19 BLUE SKY REV-COMMERCIAL
1,519,379 20 SOLAR FEED-IN REVENUE
-66,183 0.0631 -4,175,000 21 UNBILLED REVENUE
22
23 UTAH
7,385 24 08ABL-NRES - APPLICANT BUILT
38,958 25 08CFR00051-MTH FAC SRVCHG
2 26 08CFR00052-ANN FAC SVCCHG
2,109 27 08COOLKPRN - A/C DIRECT LOAD
4,982,089 11,125 447,828 0.0846 421,564,259 28 08GNSV0006-GEN SRVC-DISTR
665,283 33 20,160,091 0.0584 38,823,800 29 08GNSV0009-GEN SRVC-HI VO
1,217,086 70,373 17,295 0.1002 121,957,443 30 08GNSV0023-GEN SRVC-DISTR
269,664 2,150 125,425 0.1184 31,929,816 31 08GNSV006A-GEN SRVC-ENERG
5,118 31 165,097 0.1025 524,598 32 08GNSV006B-GEN SRVC-DEM&
5,224 6 870,667 0.0654 341,491 33 08GNSV006M-MNL DIST VOLTG
21,682 2 10,841,000 0.0692 1,501,397 34 08GNSV009A-GEN SRVC HI VO
1,311 129 10,163 0.1446 189,629 35 08GNSV023F-GEN SRVC FIXED
157 5 31,400 0.0879 13,804 36 08GNSV023M-GNSV DIST VOLT
219 1 219,000 0.1340 29,354 37 08GNSV06AM-MNL ENERGY TOD
34,920 583 59,897 0.0792 2,765,910 38 08GNSV06MN-GNSV DIST VOLT
292,685 39 08LNX00002-MTHLY 80% GUAR
15,711 40 08LNX00004-ANNUAL 80%GUAR
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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.
3,518 1 08LNX00006-FIXD MTHLY MIN
1,518,560 2 08LNX00014-80% MIN MNTHLY
184,040 3 08LNX00017-ADV/REF&80%ANN
32,101 4 08LNX00158-ANNUALCOST MTH
143,302 5 08LNX00300 - LINE EXT 80% PLUS
60,823 6 08LNX00310 - IRR 80% ANN MIN
14,886 7 08LNX00312 UT IRG LINE EXT
97,709 209 467,507 0.0857 8,370,003 8 08NMT06135-NET MTR GEN SV
77,691 9 8,632,333 0.0719 5,584,197 9 08NMT08135 -NET MTR GEN SVC
5,188 419 12,382 0.1085 562,759 10 08NMT23135 - UT NET MTR, GEN
3,082 36 85,611 0.1678 517,205 11 08NMT6A135-NET MTR GEN SVC T
7,853 4,139 1,897 0.2329 1,828,696 12 08OALT007N-SECURITY AR LG
2 226 13 08POLE0075-POLES W/LIGHT
81,723 4 20,430,750 0.0662 5,411,008 14 08PRSV031M-BKUP MNT&SUPPL
6 2 3,000 0.0753 452 15 08PTLD000N-POST TOP LIGHT
171 20 8,550 0.0933 15,948 16 08TOSS015F-TRAFFIC SIG NM
2,759 972 2,838 0.1075 296,597 17 08TOSS0015-TRAF & OTHER S
16,380 491 33,360 0.0720 1,179,270 18 08MONL0015-MTR OUTDONIGHT
360,063 19 08LNX00311 - LINE EXT 80% GTY
895,391 131 6,835,046 0.0752 67,344,677 20 08GNSV0008 -GEN SVC TOU
23,435 4 5,858,750 0.0852 1,997,028 21 08GNSV008M -GEN SVC TOU
14,401,163 22 REVENUE ADJ - DEF NPC
-4,644,360 23 REVENUE_ACCT ADJ
27,123,428 24 DSM REVENUE-COMMERCIAL
105,521 25 BLUE SKY REV-COMMERCIAL
1,309,687 26 SOLAR FEED-IN REVENUE
-80,190 0.0645 -5,174,000 27 UNBILLED REVENUE
28
29 WASHINGTON
27,949 1,483 18,846 0.0971 2,713,484 30 02GNSB0024-WA GEN SRVC DO
154 6 25,667 0.1286 19,798 31 02GNSB024F-GEN SRVC DOM/F
190 80 2,375 0.3917 74,425 32 02GNSB24FP-WA GEN SVC
469,123 13,828 33,926 0.0925 43,371,560 33 02GNSV0024-WA GEN SRVC
1,074 107 10,037 0.1388 149,113 34 02GNSV024F-WA GEN SRVC-FL
58,463 101 578,842 0.0823 4,809,779 35 02LGSB0036-LRG GEN SVC IRG
750,628 872 860,812 0.0800 60,017,523 36 02LGSV0036-WA LRG GEN SRV
183,993 35 5,256,943 0.0727 13,371,075 37 02LGSV048T-LRG GEN SRVC 1
41,673 38 02LNX00102-LINE EXT 80% G
150 39 02LNX00103-LINE EXT 80% G
1,818 40 02LNX00105-CNTRCT $ MIN G
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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.
253,163 1 02LNX00109-REF/NREF ADV +
26,767 2 02LNX00110-REF/NREF ADV +
669 3 02LNX00112-YR INCURRED CH
5,679 4 02LNX00300-LINE EXT 80% G
67,003 5 02LNX00311 - LINE EXT 80% GTY
7,432 6 02LNX00312 - WA IRG LINE EXT
1,518 791 1,919 0.1413 214,489 7 02OALT015N-WA OUTD AR LGT
520 472 1,102 0.1550 80,595 8 02OALTB15N-WA OUTD AR LGT
277 28 9,893 0.0925 25,612 9 02RCFL0054-WA REC FIELD L
-1 10 02RFNDCENT - CENTRALIA RFN
2,483 61 40,705 0.0948 235,346 11 02NMT24135, NET MTR, WA
8,576 10 857,600 0.0818 701,643 12 02NMT36135-NET METER LG SVC
10,285 2 5,142,500 0.0730 750,863 13 02NMT48135-WA LG SVC NET
991,442 14 REVENUE ADJ - DEF NPC
-5,282,153 15 REVENUE_ACCT ADJ
4,216,679 16 DSM REVENUE-COMMERCIAL
3 23,525 17 BLUE SKY REV-COMMERCIAL
-66,476 0.0775 -5,151,000 18 UNBILLED REVENUE
19
20 WYOMING
1 21 05CHCK000N-WY NRES CHECK
221,344 17,745 12,474 0.1008 22,318,400 22 05GNSV0025-WY GEN SRVC
865,019 3,281 263,645 0.0878 75,954,764 23 05GNSV0028-GEN SVC > 15 KW
999 175 5,709 0.1603 160,143 24 05GNSV025F-GEN SRVC-FL RA
153,043 19 8,054,895 0.0759 11,609,471 25 05LGSV0046-WY LRG GEN SRV
12,334 1 12,334,000 0.0729 899,708 26 05LGSV048T-LRG GENSRV TIM
1,092 27 05LNX00100-LINE EXT 60% G
1,270,131 28 05LNX00102-LINE EXT 80% G
2,868 29 05LNX00103-LINE EXT 80% G
5,800 30 05LNX00105-CNTRCT $ MIN G
560,901 31 05LNX00109-REF/NREF ADV +
8,766 32 05LNX00110-REF/NREF ADV +
1,496 33 05LNX00114-TEMP SVC 12MO>
380 25 15,200 0.0951 36,145 34 05NMT25135 - NET MTR, GEN
7,178 20 358,900 0.0912 654,617 35 05NMT28135-NET MTR SM GEN
2,637 1,621 1,627 0.1414 372,754 36 05OALT015N-OUTD AR LGT SR
706 55 12,836 0.0727 51,326 37 05RCFL0054-WY REC FIELD L
158,593 38 05LNX00300 - LINE EXT 80% GTY
76,648 39 05LNX00311 - LINE EXT 80% GTY
5,471 40 05LNX00312 - WY IRG LINE EXT
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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.
-98,073 1 REVENUE ADJ - DEF NPC
-24,521 2 REVENUE_ACCT ADJ
1,093,706 3 DSM REVENUE-SMALL
49,980 4 DSM REVENUE-LARGE
6,181 5 BLUE SKY REV-COMMERCIAL
-46,510 0.0827 -3,845,000 6 UNBILLED REVENUE
30,673 2,372 12,931 0.1001 3,070,949 7 05GNSV0025-WY GEN SRVC
91,482 387 236,388 0.0875 8,006,846 8 05GNSV0028-GEN SVC > 15 KW
199 33 6,030 0.1286 25,593 9 05GNSV025F-GEN SRVC-FL RA
62,888 10 05LNX00102-LINE EXT 80% G
188,520 11 05LNX00109-REF/NREF ADV +
1,747 12 05LNX00110-REF/NREF ADV +
488 13 05LNX00114-TEMP SVC 12MO>
75 5 15,000 0.0855 6,415 14 05NMT25135 - WY NET MTR, GEN
414 2 207,000 0.0903 37,396 15 05NMT28135-NET MTR SM GEN
273 138 1,978 0.2155 58,832 16 09OALT207N-SECURITY AR LG
289 12 24,083 0.0614 17,741 17 09MONL0213-WY MTR OUTDOOR
6,582 18 05LNX00300 - LINE EXT 80%
5,748 19 05LNX00311 - LINE EXT 80%
123,221 20 DSM REVENUE-SMALL
511 21 BLUE SKY REV-COMMERCIAL
-1,441 0.0791 -114,000 22 UNBILLED REVENUE
23
-23,920 24 LESS MULTIPLE BILLINGS
25
16,856,945 205,329 82,097 0.0916 1,544,450,403 26 TOTAL COMMERCIAL SALES
27
28 INDUSTRIAL SALES
29 CALIFORNIA
645 89 7,247 0.1835 118,336 30 06GNSV0025-CA GEN SRVC
2,635 19 138,684 0.1677 441,950 31 06GNSV0A32-GEN SRVC-20 KW
44,525 8 5,565,625 0.1106 4,924,044 32 06LGSV048T-LRG GEN SERV
6,835 13 525,769 0.1395 953,577 33 06LGSV0A36-LRG GEN SRVC-O
-176,008 34 REVENUE_ACCT ADJ
182,786 35 DSM REVENUE-INDUSTRIAL
12 36 BLUE SKY REV-INDUSTRIAL
22,696 37 SOLAR FEED-IN REVENUE
-455 0.1209 -55,000 38 UNBILLED REVENUE
39
40
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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
2,217 2 07CFR00001-MTH FACILITY S
44 2 22,000 0.0999 4,394 3 07CISH0019-COMM & IND SPA
89,653 107 837,879 0.0734 6,580,538 4 07GNSV0006-GEN SRVC-LRG P
75,600 16 4,725,000 0.0668 5,051,900 5 07GNSV0009-GEN SRVC-HI VO
14,208 317 44,820 0.0976 1,386,991 6 07GNSV0023-GEN SRVC-SML P
999 1 999,000 0.0828 82,753 7 07GNSV0035-GEN SRVCOPTION
3,579 22 162,682 0.0852 305,015 8 07GNSV006A-GEN SRVC LG P
2,071 144 14,382 0.1063 220,055 9 07GNSV023A-GEN SRVC-SML P
4 1 4,000 0.1523 609 10 07GNSV023S-IDAHO TRAFFIC
1,996 11 07LNX00108-ANN COST MTHLY
13 16 813 0.3832 4,981 12 07OALT007N-SECURITY AR LG
1 240 13 07OALT07AN-SECURITY AR LG
1,319,900 1 1,319,900,000 0.0651 85,974,980 14 07SPCL0001
109,469 1 109,469,000 0.0640 7,006,866 15 07SPCL0002
-75,522 16 REVENUE_ACCT ADJ
345,198 17 DSM REVENUE-INDUSTRIAL
26,453 0.0440 1,165,000 18 UNBILLED REVENUE
19
20 OREGON
18,466 0.0584 1,078,716 21 01COST0023, GEN SRV CST BSD
1,278,714 0.0491 62,843,220 22 01COST0048 - 01LGSV0048
1 0.0640 64 23 01COST023F - GEN SRV CST-BSD
166 0.0563 9,344 24 01COSTB023 - GEN SRV, CST-BSD
196,692 0.0522 10,265,074 25 01COSTL030 - LRG GEN SRV, CST
91,263 0.0601 5,487,120 26 01COSTS028, OR GEN SERV
13 10,419 27 01GNSB0023, OR GEN SRV, BPA
2 10,382 28 01GNSB0028, OR GEN SRV, BPA
995 1,043,818 29 01GNSV0023, OR GEN SRV, < 30
441 3,545,210 30 01GNSV0028, OR GEN SRV > 30
2 2 1,000 0.3450 690 31 01GNSV023F - GEN SRV - FLT
1 311 32 01GNSV023M - OR GEN SRV
3 2,741 33 01GNSV023T, GEN SRV, TOU OPT
4 2,785,201 34 01GNSV0748 LG GEN SVC DIR
140 7,501,515 35 01LGSV0030 - LG G SRV > 1000
82 24,234,180 36 01LGSV0048-1000KW AND OVR
106,711 3 35,570,333 0.0698 7,444,224 37 01LGSV048M-LRG GEN SRVC 1
54,809 38 01LNX00102-LINE EXT 80% G
1,204 39 01LNX00109-REF/NREF ADV +
17,144 40 01LNX00300 - LINE EXT 80% GTY
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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.
268,992 3 89,664,000 0.0648 17,423,613 1 01LPRS047M-PART REQ SRVC
4 3,431 2 01NMT23135 - NET MTR GEN < 30
5 38,616 3 01NMT28135 - NET MTR GEN > 30
2 58,233 4 01NMT30135 - NET MTR GEN > 200
283 127 2,228 0.1441 40,773 5 01OALT015N-OUTD AR LGT NR
4 4 1,000 0.1365 546 6 01OALTB15N-OR OUTD AR LGT
41 0.0633 2,596 7 01PTOU0023, GEN SRV, TOU ENG
81 0.0568 4,603 8 01RENW0023, RENW USAGE SPLY
170 0.0539 9,159 9 01STDAY028 - DAY STD OFF SCH
1 1,210 10 01VIR23136-VOL INC <=30KW
2 13,962 11 01VIR28136-VOL INC >30 KW
1 37,768 12 01VIR30136-VOL INC >200KW
-106,662 13 REVENUE ADJ - DEF NPC
-1,192,390 14 REVENUE_ACCT ADJ
834,548 15 DSM REVENUE-INDUSTRIAL
35 594,092 16 BLUE SKY REV-INDUSTRIAL
1,008,689 17 SOLAR FEED-IN REVENUE
39,953 0.1130 4,514,000 18 UNBILLED REVENUE
19
20 UTAH
18,561 21 08CFR00051-MTH FAC SRVCHG
1,471 2 735,500 0.1128 165,987 22 08EFOP0021-ELEC FURNACE O
962 2 481,000 0.1650 158,719 23 08EFOP021M-ELEC FURNACE O
655,080 1,032 634,767 0.0877 57,474,508 24 08GNSV0006-GEN SRVC-DISTR
3,326,730 114 29,181,842 0.0562 186,910,163 25 08GNSV0009-GEN SRVC-HI VO
54,472 3,298 16,517 0.1017 5,540,520 26 08GNSV0023-GEN SRVC-DISTR
65,544 261 251,126 0.1175 7,699,193 27 08GNSV006A-GEN SRVC-ENERG
121 1 121,000 0.0825 9,984 28 08GNSV006B-GEN SRVC-DEM&
14,967 6 2,494,500 0.0914 1,367,625 29 08GNSV009A-GEN SRVC HI VO
436,435 10 43,643,500 0.0561 24,470,061 30 08GNSV009M-MANL HIGH VOLT
4 1 4,000 0.6430 2,572 31 08GNSV023F-GEN SRVC FIXED
1,355 24 56,458 0.0865 117,186 32 08GNSV06MN-GNSV DIST VOLT
1,385 1 1,385,000 0.1226 169,753 33 08GNSV09AM-MAN TOD HIVOLT
606,211 34 08LNX00002-MTHLY 80% GUAR
16,085 35 08LNX00014-80% MIN MNTHLY
1,452 36 08LNX00311 - LINE EXT 80% GTY
65,412 37 08LNX00300 - LINE EXT 80% PLUS
4,173 38 08LNX00310 - IRR 80% ANN MIN
1,160 438 2,648 0.2146 248,931 39 08OALT007N-SECURITY AR LG
9 9 1,000 0.1468 1,321 40 08TOSS0015-TRAF & OTHER S
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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.
16 6 2,667 0.1530 2,448 1 08MONL0015-MTR OUTDONIGHT
2,260 6 376,667 0.0919 207,659 2 08NMT06135-NET MTR GEN SV
157 12 13,083 0.1073 16,844 3 08NMT23135 -NET MTR G <25
3,738 10 373,800 0.1388 518,893 4 08NMT6A135-NET MTR GEN SVC T
21,585 2 10,792,500 0.0878 1,895,372 5 08PRSV031M-BKUP MNT&SUPPL
567,236 1 567,236,000 0.0524 29,742,630 6 08SPCL0001
1,014,177 1 1,014,177,000 0.0452 45,819,520 7 08SPCL0002
938,861 1 938,861,000 0.0530 49,785,690 8 08SPCL0003
244 2 122,000 0.1319 32,179 9 08GNSV06AM-MNL ENERGY TOD
942,351 95 9,919,484 0.0763 71,924,436 10 08GNSV0008 - GEN SVC TOU
44,711 6 7,451,833 0.0788 3,521,853 11 08GNSV008M - GEN SVC TOU
8,897,132 12 REVENUE ADJ - DEF NPC
-4,164,720 13 REVENUE_ACCT ADJ
13,766,171 14 DSM REVENUE-INDUSTRIAL
8 38,376 15 BLUE SKY REV-INDUSTRIAL
1,633,391 16 SOLAR FEED-IN REVENUE
33,459 0.1033 3,456,000 17 UNBILLED REVENUE
18
19 WASHINGTON
1,033 46 22,457 0.1047 108,183 20 02GNSB0024-WA GEN SRVC DO
4 1 4,000 0.4318 1,727 21 02GNSB24FP-WA GEN SVC
15,204 330 46,073 0.0938 1,426,093 22 02GNSV0024-WA GEN SRVC
33 4 8,250 0.2598 8,572 23 02GNSV024F-WA GEN SRVC-FL
99,781 101 987,931 0.0831 8,290,853 24 02LGSV0036-WA LRG GEN SRV
646,631 31 20,859,065 0.0641 41,442,827 25 02LGSV048T-LRG GEN SRVC 1
40,490 26 02LNX00103-LINE EXT 80% G
104 38 2,737 0.1320 13,732 27 02OALT015N-WA OUTD AR LGT
27 14 1,929 0.1497 4,043 28 02OALTB15N-WA OUTD AR LGT
1,597 1 1,597,000 0.1801 287,631 29 02PRSV47TM-LRG PART REQMT
1,462 11 132,909 0.1326 193,809 30 02LGSB0036-LRG GEN SVC IRG
528,733 31 REVENUE ADJ - DEF NPC
-2,205,953 32 REVENUE_ACCT ADJ
1,745,930 33 DSM REVENUE-INDUSTRIAL
14,392 0.0832 1,197,000 34 UNBILLED REVENUE
35
36 WYOMING
19,225 1,164 16,516 0.0955 1,836,035 37 05GNSV0025-WY GEN SRVC
239,015 472 506,388 0.0783 18,705,301 38 05GNSV0028-GEN SVC > 15 KW
26 8 3,250 0.1652 4,295 39 05GNSV025F-GEN SRVC-FL RA
1,615,452 60 26,924,200 0.0687 111,001,957 40 05LGSV0046-WY LRG GEN SRV
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
11,699 1 11,699,000 0.0757 885,298 1 05LGSV046M-WY LRG GEN SRV
273,912 1 273,912,000 0.0609 16,673,768 2 05LGSV048M-TOU>1000KW MAN
1,710,573 11 155,506,636 0.0591 101,065,367 3 05LGSV048T-LRG GENSRV TIM
63,483 4 05LNX00100-LINE EXT 60% G
1,146,531 5 05LNX00102-LINE EXT 80% G
-5,948 6 05LNX00103-LINE EXT 80% G
42,239 7 05LNX00105-CNTRCT $ MIN G
291,635 8 05LNX00109-REF/NREF ADV +
283 9 05LNX00110-REF/NREF ADV +
92,199 10 05LNX00300 - LINE EXT 80%
24,193 11 05LNX00311 - LINE EXT 80%
77 38 2,026 0.1267 9,755 12 05OALT015N-OUTD AR LGT SR
1,232,040 8 154,005,000 0.0690 85,062,668 13 05PRSV033M-PART SERV REQ
-459,678 14 REVENUE ADJ - DEF NPC
116,966 15 REVENUE_ACCT ADJ
225,620 16 DSM REVENUE-SMALL
1,257,553 17 DSM REVENUE-LARGE
-3,984 18 BLUE SKY REV-INDUSTRIAL
44,252 0.0799 3,537,000 19 UNBILLED REVENUE
8,498 290 29,303 0.0871 740,517 20 05GNSV0025-WY GEN SRVC
48,039 71 676,606 0.0776 3,728,964 21 05GNSV0028-GEN SVC > 15 KW
4,379 3 1,459,667 0.0631 276,172 22 05GNSV028M-GEN SVC > 15 KW
38,724 3 12,908,000 0.0728 2,820,607 23 05LGSV0046-WY LRG GEN SRV
216,747 3 72,249,000 0.0626 13,578,041 24 05LGSV048M-TOU>1000KW MAN
1,212,174 13 93,244,154 0.0641 77,709,839 25 05LGSV048T-LRG GENSRV TIM
312,414 26 05LNX00102-LINE EXT 80% G
2,134,795 27 05LNX00109-REF/NREF ADV +
1,649 28 05LNX00300 - LINE EXT 80%
96,485 2 48,242,500 0.0638 6,152,519 29 05PRSV033M-PART SERV REQ
5 3 1,667 0.1798 899 30 09OALT207N-SECURITY AR LG
52,005 31 DSM REVENUE-SMALL
399,576 32 DSM REVENUE-LARGE
23 33 BLUE SKY REV-INDUSTRIAL
7,353 0.0836 615,000 34 UNBILLED REVENUE
35
-934 36 LESS MULTIPLE BILLINGS
37
19,385,150 9,771 1,983,947 0.0660 1,279,414,294 38 TOTAL INDUSTRIAL SALES
39
40
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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 IRRIGATION SALES
2 CALIFORNIA
12,397 768 16,142 0.1422 1,762,946 3 06APSV0020-AG PMP SRVC
246 2 123,000 0.0975 23,975 4 06APSV0115-CA AGRI PUMP TOU
53,695 591 90,854 0.1481 7,953,897 5 06APSV020L-AG PMP SRVC-NO
784 6 130,667 0.1219 95,574 6 06APSV115L-CA AGRI PUMP TOU,
2,682 1 2,682,000 0.1141 305,916 7 06LGSV048T-LRG GEN SERV
2,418 8 06LNX00103-LINE EXT 80% G
509 9 06LNX00109-REF/NREF ADV +
29,452 10 06LNX00110-REF/NREF ADV +
5,448 11 06LNX00310-80% ANN MIN + 80%
30,328 12 06LNX00312 - CA IRG LINE EXT
498 9 55,333 0.2017 100,434 13 06NML20135-AGRI PUMP-NET MTR
24 1 24,000 0.1583 3,800 14 06NMT20135-AGRI PUMP-NET
2,998 276 10,862 0.1759 527,432 15 06USBR0020-KLAM IRG ONPRJ
38 1 38,000 0.1255 4,769 16 06USBR0115-CA AGR PMP TOU
17,066 360 47,406 0.1664 2,839,748 17 06USBR020L-KLAM IRG PRJ-NO
767 7 109,571 0.1339 102,696 18 06USBR115L-CA AGR PMP TOU
-478,695 19 REVENUE_ACCT ADJ
509,920 20 DSM REVENUE-IRRIGATION
23 21 BLUE SKY REV-IRRIGATION
52,642 22 SOLAR FEED-IN REVENUE
-16 0.5000 -8,000 23 UNBILLED REVENUE
24
25 IDAHO
433,327 2,670 162,295 0.0929 40,259,658 26 07APSA010L - IRG & PUMP LG
5,751 350 16,431 0.1108 636,944 27 07APSA010S - IRG & PUMP SM
186,470 1,481 125,908 0.0945 17,614,213 28 07APSAL10X - IRG & PUMP - LG
7,500 426 17,606 0.1087 815,517 29 07APSAS10X - IRG & PUMP - SM
2,166 2 1,083,000 0.0777 168,268 30 07APSV006A-LRG POWER OPT
326 4 81,500 0.1010 32,917 31 07APSV023A-SM POWER OPT S
21,526 47 458,000 0.0833 1,792,800 32 07APSVCNLL-LG LOAD CANAL
41 12 3,417 0.1476 6,051 33 07APSVCNLS-SM LOAD CANAL
2,657 34 07LNX00015-ANNUAL 80%GUAR
477 35 07LNX00035-ADV 80%MO GUAR
145,883 36 07LNX00040-ADV+REFCHG+80%
844 37 07LNX00310 80% ANNUAL GTY
1,661 38 07LNX00311 - LINE EXT 80% GTY
56,021 39 07LNX00312 - ID LINE EXT
4,265 32 133,281 0.0944 402,654 40 07APSN010L - ID LG IRR & PUMP
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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.
179 6 29,833 0.1054 18,874 1 07APSN010S - IRRIGATION SM
266 18 14,778 0.1188 31,594 2 07APSNS10X - IRRIGATION SM
-262,486 3 REVENUE_ACCT ADJ
1,665,919 4 DSM REVENUE-IRRIGATION
5 123 5 BLUE SKY REV-IRRIGATION
-23 0.0870 -2,000 6 UNBILLED REVENUE
7
8 OREGON
2,968 1,706,166 9 01APSV0041-AG PMP SRVC
10 22,285 10 01APSV0215-OR IRR TOU PILO
818 2,774,582 11 01APSV041L-PUMP SERV >30KW
61 30,659 12 01APSV041T - AGR PUMP SRV
1,963 983,513 13 01APSV041X-AG PMP SRVC
361 1,548,429 14 01APSV41XL-OR Pumping Serv
139,150 0.0589 8,197,344 15 01COST0041 -01APSV0041
116,822 0.0497 5,807,445 16 01COST0048 - 01LGSV0048
6,180 0.0410 253,399 17 01COST0215-OR TOU PILOT COST
506 0.0601 30,399 18 01COSTS028 G SERV CST > 30
74,976 0.0589 4,414,496 19 01CSTUSB41-USBR IRR CONTRA
3,574 20 01GNSB0028-OR GENL SVC > 30
2 15,292 21 01GNSV0028, OR GEN SRV > 30
11 0.0597 657 22 01HABIT041 - 01APSV0041 AG
3 1,113,335 23 01LGSB0048 - LG GEN SVC > 1000
3 1,477,572 24 01LGSV0048-1000KW AND OVR
41,190 25 01LNX00103-LINE EXT 80% G
303 26 01LNX00109-REF/NREF ADV +
189,657 27 01LNX00110-REF/NREF ADV +
17,246 28 01LNX00310-LINE EXTENSION
578 0.0585 33,823 29 01PTOU0041 - 01APSV0041 AG
145 0.0588 8,522 30 01RENEW041 - 01APSV0041 AG
136 0.0549 7,462 31 01STDAY041 - DAILY STD OFFER
84 232,057 32 01USBR0215-OR IRG TOU PILOT
9 72,811 33 01USBRGV41-IRG TOU W/O BPA
484 1,402,306 34 01USBROF41-KLAMATH BASIN
1,164 1,956,320 35 01USBRON41-KLAMATH BASIN
24 60,774 36 01VIR41136-OR VOLUME INC
95 344,323 37 01VRU41136-VOL INC USB
7 54,000 38 01VRU41215-VOL INC USB TOU
35,861 39 01LNX00312 - OR IRG LINE EXT
14 12,483 40 01NMT41135 - NETMTR AG PMP
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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 1 01NMT41215-NET MTR APSV TOU
7 27,245 2 01NMU41135 -NET MTR <PRJ
-50,685 3 REVENUE_ACCT ADJ
629,597 4 DSM REVENUE-IRRIGATION
353 5 BLUE SKY REV-IRRIGATION
35,884 6 SOLAR FEED-IN REVENUE
3,306 0.1455 481,000 7 UNBILLED REVENUE
8
9 UTAH
203,511 2,913 69,863 0.0777 15,809,475 10 08APSV0010-IRR & SOIL DRA
36,429 239 152,423 0.0714 2,601,090 11 08APSV10NS- LG SOIL DRAIN
5,619 12 08LNX00004-ANNUAL 80%GUAR
11,574 13 08LNX00014-80% MIN MNTHLY
193,562 14 08LNX00017-ADV/REF&80%ANN
19,656 15 08LNX00310 - IRR, 80% ANN MIN
368 16 08LNX00311 - LINE EXT 80% GTY
25,487 17 08LNX00312 UT IRG LINE EXT
7,109 36 197,472 0.0764 543,401 18 08NMT10135-UT IRR_SOIL DRNG
-115,100 19 REVENUE_ACCT ADJ
729,302 20 DSM REVENUE-IRRIGATION
38,170 21 SOLAR FEED-IN REVENUE
-197 0.0609 -12,000 22 UNBILLED REVENUE
23
24 WASHINGTON
117,096 3,177 36,857 0.0873 10,224,628 25 02APSV0040-WA AG PMP SRVC
51,703 1,989 25,994 0.0889 4,594,621 26 02APSV040X-WA AG PMP SRVC
9,308 27 02LNX00103-LINE EXT 80% G
76 28 02LNX00105-CNTRCT $ MIN G
9,250 29 02LNX00109-REF/NREF ADV +
178,594 30 02LNX00110-REF/NREF ADV +
12,468 31 02LNX00310 - IRG 80% ANN MIN
170 32 02LNX00311 - LINE EXT 80%
39,308 33 02LNX00312 - WA IRG LINE EXT
154 6 25,667 0.0965 14,855 34 02NMT40135-WA NET MTR -IRG
99,305 35 REVENUE ADJ - DEF NPC
-619,160 36 REVENUE_ACCT ADJ
518,251 37 DSM REVENUE-IRRIGATION
6 229 38 BLUE SKY REV-IRRIGATION
1,863 0.4455 830,000 39 UNBILLED REVENUE
40
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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 WYOMING
20,534 689 29,803 0.0835 1,713,878 2 05APS00040-AG PUMPING SVC
1,124 19 59,158 0.0821 92,262 3 05APSNS040-AG PUMPING SVC -
5,589 4 05LNX00103-LINE EXT 80% G
1,019 5 05LNX00109-REF/NREF ADV +
45,944 6 05LNX00110-REF/NREF ADV +
205 7 05LNX00310-LINE EXTCONTRAC
11,016 8 05LNX00312 - WY IRG LINE EXT
579 9 REVENUE_ACCT ADJ
19,873 10 DSM REVENUE-IRRIGATION
-7 0.1429 -1,000 11 UNBILLED REVENUE
126 1 126,000 0.0748 9,430 12 05APS00040-AG PUMPING SVC
13,106 13 05LNX00110-REF/NREF ADV +
1,218 14 05LNX00310-LINE EXTENSION
1,031 15 05LNX00312 - WY IRG LINE EXT
372 2 186,000 0.0963 35,824 16 09APSNS210-IRR & SOIL DRA -
4,722 91 51,890 0.0864 407,745 17 09APSV0210-IRR & SOIL DRA
4,979 18 DSM REVENUE-IRRIGATION
19
-833 20 LESS MULTIPLE BILLINGS
21
1,539,322 23,487 65,539 0.0970 149,350,706 22 TOTAL IRRIGATION SALES
23
24 PUBLIC STREET & HWY LIGHTING
25 CALIFORNIA
1,205 106 11,368 0.1779 214,415 26 06CUSL053E-SPECIAL CUST O
80 20 4,000 0.2015 16,119 27 06CUSL058F-CUST OWND STR
604 78 7,744 0.3379 204,084 28 06HPSV0051-HI PRESSURE SO
1 1 1,000 0.1430 143 29 06OALT015N-OUTD AR LGT SR
-10,806 30 REVENUE_ACCT ADJ
14,137 31 DSM REVENUE-PUB ST & HWY LT
1,582 32 SOLAR FEED-IN REVENUE
199 0.2161 43,000 33 UNBILLED REVENUE
34
35 IDAHO
140 25 5,600 0.1265 17,716 36 07GNSV023S-IDAHO TRAFFIC
114 52 2,192 0.4690 53,464 37 07SLCO0011-STR LGT CO-OWN
364 31 11,742 0.1129 41,088 38 07SLCU012E-ENGY STR LGT
1,873 190 9,858 0.2017 377,841 39 07SLCU012F-FULL MNT STR
194 16 12,125 0.1474 28,602 40 07SLCU012P-PART MNT STR LGT
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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.
-3,684 1 REVENUE_ACCT ADJ
13,100 2 DSM REVENUE-PUB ST & HWY LT
-22 0.1818 -4,000 3 UNBILLED REVENUE
4
5 OREGON
394 35 11,257 0.1510 59,504 6 01COSL0052-STR LGT SRVC C
658 72 9,139 0.0747 49,158 7 01CUSL0053-CUS-OWNED MTRD
8,690 192 45,260 0.0747 649,284 8 01CUSL053E-STR LGT SVC
121 9 13,444 0.0958 11,596 9 01CUSL053F-STR LGT SRVC C
19,083 747 25,546 0.2120 4,045,780 10 01HPSV0051-HI PRESSURE SO
327 52 6,288 0.3490 114,116 11 01LEDSL051-OR LED PILOT
7,527 233 32,305 0.1332 1,002,381 12 01MVSL0050-MERC VAPSTR LG
13 6 2,167 0.1758 2,285 13 01OALT015N-OUTD AR LGT NR
3 2 1,500 0.1657 497 14 01OALTB15N-OR OUTD AR LGT
-11,107 15 REVENUE_ACCT ADJ
144,453 16 DSM REVENUE-PUB ST & HWY LT
8,752 17 SOLAR FEED-IN REVENUE
752 0.1662 125,000 18 UNBILLED REVENUE
19
20 UTAH
54 21 08CFR00012-STR LGTS (CONV
4,529 22 08CFR00051-MTH FAC SRVCHG
79 23 08CFR00062-STREET LIGHTS
7 6 1,167 -0.5773 -4,041 24 08OALT007N-SECURITY AR LG
1,151 121 9,512 0.0918 105,692 25 08TOSS015F-TRAFFIC SIG NM
14,910 753 19,801 0.3061 4,564,063 26 08SLCO0011-STR LGT CO-OWN
2,955 1,519 1,945 0.1179 348,381 27 08TOSS0015-TRAF & OTHER S
861 76 11,329 0.0799 68,753 28 08MONL0015-MTR OUTDONIGHT
4,725 193 24,482 0.1280 604,850 29 08SLCU012P-STR LGT CUST-O
1,170 79 14,810 0.1407 164,607 30 08SLCU012F-STR LGT CUST-O
50,408 784 64,296 0.0657 3,309,347 31 08SLCU012E-DECOR CUST-OWN
-89,599 32 REVENUE_ACCT ADJ
340,659 33 DSM REVENUE-PUB ST & HWY LT
37,675 34 SOLAR FEED-IN REVENUE
714 0.1261 90,000 35 UNBILLED REVENUE
36
37 WASHINGTON
91 38 02CFR00012-STR LGTS (CONV
159 14 11,357 0.2002 31,834 39 02COSL0052-WA STR LGT SRV
3,440 112 30,714 0.0730 251,209 40 02CUSL053F-WA STR LGT SRV
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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.
1,077 105 10,257 0.0724 77,923 1 02CUSL053M-WA STR LGT SRV
3,843 186 20,661 0.2010 772,543 2 02SLCO0051-WA COMPANY
1,676 40 41,900 0.1281 214,634 3 02MVSL0057-WA MERC VAPSTR
6,173 4 REVENUE ADJ - DEF NPC
-41,006 5 REVENUE_ACCT ADJ
29,134 6 DSM REVENUE-PUB ST & HWY LT
-166 0.1024 -17,000 7 UNBILLED REVENUE
8
9 WYOMING
254 17 14,941 0.1923 48,848 10 05COSL0057-CO-OWND STR LG
76 11 6,909 0.0588 4,466 11 05CUSL0058-CUST OWND STR
1,069 31 34,484 0.0590 63,025 12 05CUSL0E58-CUST OWNED STR
44 3 14,667 0.0715 3,145 13 05CUSL0M58-CUST OWNED STR
5,292 185 28,605 0.1934 1,023,371 14 05HPSV0051-HI PRESSURE SO
3,561 240 14,838 0.1187 422,684 15 05MVS00053-MERCURY VAPOR
30 2 15,000 0.1127 3,381 16 05OALT015N-OUTD AR LGT SR
-2,179 17 REVENUE_ACCT ADJ
17,299 18 DSM REVENUE-PUB ST & HWY LT
232 0.1509 35,000 19 UNBILLED REVENUE
25 1 25,000 0.1034 2,585 20 09MONL0213-WY MTR OUTDOOR
1,491 49 30,429 0.2282 340,316 21 09SLCO0211-STR LGT CO-OWN
34 5 6,800 0.1483 5,043 22 09SLCUP212-CUST OWNED
37 14 2,643 0.0534 1,976 23 09TOSS0213-TRAFFIC & OTHER
3,862 24 DSM REVENUE-PUB ST & HWY LT
96 0.1771 17,000 25 UNBILLED REVENUE
26
-2,943 27 LESS MULTIPLE BILLINGS
28
141,491 3,470 40,776 0.1418 20,068,906 29 TOTAL PUBLIC STREET & HWY LT
30
31 OTHER SALES TO PUBLIC AUTH
32 UTAH
250,041 1 250,041,000 0.0589 14,735,630 33 08GNSV009M-MANL HIGH VOLT
102,842 1 102,842,000 0.0719 7,390,785 34 08PRSV031M-BKUP MNT&SUPPL
-169,167 35 REVENUE_ACCT ADJ
862,515 36 DSM REVENUE-OSPA
54,529 37 SOLAR FEED-IN REVENUE
-15,668 0.0567 -889,000 38 UNBILLED REVENUE
39
337,215 2 168,607,500 0.0652 21,985,292 40 TOTAL OTHER SALES TO PUBLIC
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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 FORFEITED DISCOUNTS
2 CALIFORNIA
194,256 3 06LPAY0300-RES-LATEFEE
49,823 4 06LPAY0300-COM-LATEFEE
59,652 5 06LPAY0300-IND-LATEFEE
-1,666 6 06LPAY0300-OTHER-LATEFEE
7
8 IDAHO
222,191 9 07LPAY0300-RES-LATEFEE
39,149 10 07LPAY0300-COM-LATEFEE
214,798 11 07LPAY0300-IND-LATEFEE
642 12 07LPAY0300-OTHER-LATEFEE
13
14 OREGON
2,897,375 15 01LPAY0300-RES-LATEFEE
611,051 16 01LPAY0300-COM-LATEFEE
200,621 17 01LPAY0300-IND-LATEFEE
3,886 18 01LPAY0300-OTHER-LATEFEE
19
20 UTAH
2,525,640 21 08LPAY0300-RES-LATEFEE
597,985 22 08LPAY0300-COM-LATEFEE
400,992 23 08LPAY0300-IND-LATEFEE
61,323 24 08LPAY0300-OTHER-LATEFEE
1,574 25 OTHER
26
27 WASHINGTON
532,842 28 02LPAY0300-RES-LATEFEE
111,313 29 02LPAY0300-COM-LATEFEE
27,753 30 02LPAY0300-IND-LATEFEE
-12,875 31 02LPAY0300-OTHER-LATEFEE
32
33 WYOMING
409,905 34 05LPAY0300-RES-LATEFEE
98,665 35 05LPAY0300-COM-LATEFEE
46,995 36 05LPAY0300-IND-LATEFEE
2,974 37 05LPAY0300-OTHER-LATEFEE
49,650 38 05LPAY0300-RES-LATEFEE
10,952 39 05LPAY0300-COM-LATEFEE
13,296 40 05LPAY0300-IND-LATEFEE
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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.
1,007 1 05LPAY0300-OTHER-LATEFEE
9,371,769 2 TOTAL FORFEITED DISCOUNTS
3
4 MISCELLANEOUS SERVICE REV
5 CALIFORNIA
1,454 6 06CFR00003-MTH MAINTENANC
24,750 7 06CONN0300-CA RECONNECTIO
24,993 8 06FCBUYOUT
10,680 9 06RCHK0300-CA RET CHK CHR
975 10 06TAMP0300-CA TAMP & UNAU
3,575 11 06TEMP0300-CA TEMP SRVC C
30 12 06TRBL0300-CA TROUBLE CAL
293 13 06XMTRTAMP-TMPRING - UNAU
18 14 HOME COMFORT
15
16 IDAHO
1,682 17 07CFR00001-MTH FAC SRVCHG
14,090 18 07CONN0300-ID RECONNECTIO
76,961 19 07FCBUYOUT - FAC CHG BUYOUT
28,600 20 07RCHK0300-ID RET CHK CHR
150 21 07TAMP0300
29,725 22 07TEMP0014-TEMP SRVC CONN
1,230 23 OTHER
24
25 OREGON
91,338 26 01CFR00001-MTH FACILITY S
25,986 27 01CFR00003-MTH MAINTENANC
25,929 28 01CFR00004-MTH MAINTENANC
37,101 29 01CFR00005-INTERMTNT SRVC
53,234 30 01CFR00013-MTH MISC CHRG
-5 31 01CFR00014-YR MISC CHRG
268,765 32 01CONN0300-RECONNECTION C
9,087 33 01CONTSERV-OR 3RD PARTY
3,096 34 01ESSC0600 - ESS CHARGES
277,357 35 01FCBUYOUT-FAC CHG BUYOUT
266,880 36 01RCHK0300-RETURNED CHECK
16,575 37 01TAMP0300-TAMP & UNAUTH
173,425 38 01TEMP0300-TEMP SRVC CHRG
5,532 39 01XMTRTAMP-TAMPRING - UNAU
-73,248 40 OTHER
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 UTAH
135,561 2 08CFR00013-MTH MISC CHRG
86,174 3 08CFR00051-MTH FAC SRVCHG
424 4 08CFR00052-ANN FAC SVCCHG
12,007 5 08CFR00053-MTHLY MAINTFEE
4,976 6 08CFR00054-NRES EMERGENCY
2,358 7 08CFR00063-MTH MISC CHARG
6,660 8 08CFR00064-ANN MISC CHARG
296,340 9 08CONN0300-RECONN&DISCONN
91,620 10 08CONTSERV-3RD PARTY O/S
298,008 11 08FCBUYOUT-FAC CHG BUYOUT
80 12 08INFO0300-CUST/3RD P REQ
3,830 13 08NCON0300-UT FEE NRES RE
849 14 08NSMTR300-NON STAN MTR
226 15 08PRINT300-SCREEN PRINT FOR
439,620 16 08RCHK0300-UT RET CHK CHR
1,751,511 17 08RCON0001-CONNECT FEE
3,695 18 08RESD0001-RES SRVC
8,025 19 08TAMP0300-TAMPERING&UNAU
627,450 20 08TEMP0014-TEMP SRVC CONN
1,865 21 08XMTRTAMP-TMPRING - UNAU
2,644 22 ENERGY FINANSWER NEW COM
44,390 23 08VISIT300 - UT VISIT, SERVICE
-48,773 24 OTHER
25
26 WASHINGTON
1,320 27 02CFR00003-MTH MAINTENANC
5,892 28 02CFR00004-EMRGNCY ST&BY
4,147 29 02CFR00005-INTERMTNT SRVC
53,525 30 02CONN0300-WA RECONNECTIO
53,067 31 02FCBUYOUT - FAC CHG BUYOUT
49,940 32 02RCHK0300-WA RET CHK CHR
2,775 33 02TAMP0300-WA TAMP & UNAU
20,430 34 02TEMP0300-WA TEMP SRVC C
655 35 02XMTRTAMP-TMPRING - UNAU
-5,809 36 02XTHEFREV-THEFT OF
27 37 HOME COMFORT
-3,056 38 OTHER
39
40
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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 WYOMING
1,768 2 05CFR00003-MTH MAINTENANC
18,474 3 05CFR00004-EMRGNCY ST&BY
10,063 4 05CFR00005-INTERMTNT SRVC
3,186 5 05CFR00013-MTH MISC CHRG
74,688 6 05CONN0300-WY RECONNECTIO
34,574 7 05FCBUYOUT - FAC CHG BUYOUT
370 8 05NSMTR300-NON STANDARD
82,320 9 05RCHK0300-WY RET CHK CHR
825 10 05RESD0002-WY RES SRVC
900 11 05TAMP0300
47,600 12 05TEMP0300-WY TEMP SRVC C
183 13 05XMTRTAMP-TMPRING - UNAU
339 14 09CFR00005-INTERMTNT SRVC
-5,804 15 OTHER
8,710 16 05CONN0300-WY RECONNECTIO
7,260 17 05RCHK0300-WY RET CHK CHR
120 18 05SERV0300-WY SRVC CALLS
75 19 05TAMP0300
510 20 05TEMP0300-WY TEMP SRVC C
17 21 05XMTRTAMP-TAMPERING -
4,726 22 09CFR00001-MTH FAC SRVCHG
3 23 09CFR00014-YR MISC CHRG
24
5,643,618 25 TOTAL MISC SERVICE REV
26
27 SALES OF WATER & WATER PWR
28 IDAHO
3,452 29 WATER & WATER PWR SALES
30
31 UTAH
71,581 32 WATER & WATER PWR SALES
33
75,033 34 TOTAL SALES OF WATER & WTR
35
36 RENT FROM ELEC PROPERTIES
37 CALIFORNIA
1,710 38 06CFR00006-MTH RNTAL CHRG
1,450 39 RENT REVENUE-HYDRO
19,200 40 RENT REVENUE-SUBLEASES
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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.
517,335 1 JOINT USE
2
3 IDAHO
723 4 07CFR00009-YR LSE CHRG-EQ
150 5 07INVCHG00-INVEST MNT CHG
274 6 07POLE0075-STEEL POLES US
73,480 7 RENT REVENUE-HYDRO
9,780 8 RENT REVENUE-TRANSMISSION
550 9 RENT REVENUE-DISTRIBUTION
2,216 10 RENT REVENUE-SUBLEASES
161,597 11 JOINT USE
12
13 OREGON
834,918 14 01CFR00006-MTH RNTAL CHRG
676,677 15 RENTS - COMMON
25 16 RENTS - NON COMMON
3,343,623 17 MCI FOGWIRE REVENUE
45,050 18 RENT REVENUE-SUBLEASES
30,404 19 RENT REVENUE-HYDRO
274,779 20 RENT REVENUE-TRANSMISSION
61,763 21 RENT REVENUE-DISTRIBUTION
61,466 22 RENT REVENUE-GENERAL
2,778,597 23 JOINT USE
24
25 UTAH
33 26 08CFR00056-MTH EQUIP RENT
487,051 27 08CFR00058-MTH EQUIP LEAS
4,392 28 08INVCHG0N-INVEST MNT CHG
230 29 08INVCHG0R-INVEST MNT CHG
54,247 30 08POLE0075-STEEL POLES US
11,903 31 RENTS - NON COMMON
104,460 32 RENT REVENUE-STEAM
167,557 33 RENT REVENUE-HYDRO
1,144,793 34 RENT REVENUE-TRANSMISSION
655,071 35 RENT REVENUE-DISTRIBUTION
23,179 36 RENT REVENUE-GENERAL
2,692,996 37 RENT REVENUE-SUBLEASES
4,341,955 38 JOINT USE
39
40
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 WASHINGTON
2,104 2 02CFR00001-MTH FACILITY S
9,073 3 02CFR00006-MTH RNTAL CHRG
355,923 4 RENT REVENUE-HYDRO
19,600 5 RENT REVENUE-TRANSMISSION
19,662 6 RENT REVENUE-DISTRIBUTION
42,719 7 RENT REVENUE-GENERAL
817,250 8 JOINT USE
9
10 WYOMING
11,524 11 05CFR00001-MTH FACILITY S
2,482 12 05CFR00006-MTH RNTAL CHRG
115,420 13 RENT REVENUE-STEAM
24,974 14 RENT REVENUE-HYDRO
17,506 15 RENT REVENUE-TRANSMISSION
150 16 RENT REVENUE-DISTRIBUTION
59,793 17 RENT REVENUE-GENERAL
31,079 18 RENT REVENUE-SUBLEASES
334,646 19 JOINT USE
18,313 20 09POLE0075-STEEL POLES US
28,336 21 RENT REVENUE-STEAM
22
20,494,188 23 TOTAL RENT FROM ELEC PROP
24
25 OTHER ELECTRIC REVENUE
10,840,910 26 WIND BASED ANCILLARY SVC
-7,093,960 27 FERC TRANSMISSION REFUND
-792,052 28 OTH ELEC ESTIMATE
-7,116,003 29 RENEWABLE ENERGY CREDITS
6,159,270 30 NON-WHEELING SYSTEM
27,790 31 OTHER ELEC (EXCLUDE WHEELIN
32
33 CALIFORNIA
11,196,617 34 CA GHG ALLOW REV AMORT
60,564 35 3RD PARTY TRANS O&M
7,820 36 FISH, WILDLIFE, RECR
-215 37 OTHER ELEC (EXCLUDE WHEELIN
38
39
40
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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
/ /2016/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
-11,099 2 3RD PARTY TRANS O&M
-5 3 OTHER ELEC (EXCLUDE WHEELIN
4 OREGON
25,900 5 EIM REVENUE - FORECASTING
183,519 6 3RD PARTY TRANS O&M
1,707,652 7 OTHER ELEC (EXCLUDE WHEELIN
8
9 UTAH
48,096 10 ELEC INC-OTHR
1,789,010 11 FLYASH SALES
208,255 12 3RD PARTY TRANS O&M
2,720 13 FISH, WILDLIFE, RECR
-42 14 OTHER ELEC (EXCLUDE WHEELIN
1,450,819 15 M&S INVENTORY REVENUE
16
17 WASHINGTON
727,541 18 TIMBER SALES - UTILITY PROP
9,390 19 FISH, WILDLIFE, RECR
-3 20 OTHER ELEC (EXCLUDE WHEELIN
-52,188 21 WASH COLSTRIP 3
22
23 WYOMING
5 24 ELEC INC-OTHR
2,534,354 25 FLYASH SALES
351,447 26 WY REG RECOVERY FEE
83,503 27 3RD PARTY TRANS O&M
17 28 OTHER ELEC (EXCLUDE WHEELIN
29
22,349,632 30 TOTAL OTHER ELEC REV
31
32
33
34
35
36
37
38
39
40
54,317,937 4,924,540,840 1,840,754 29,509 0.0907
190,765 30,521,000 0 0 0.1600
54,127,172 4,894,019,840 1,840,754 29,405 0.0904
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 / /2016/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
Helper City 111T-6RQ 2
Helper City Annex 111T-6RQ 3
Navajo Tribal Utility Authority 233T-12RQ 4
Navajo Tribal Util. Auth. (Mexican Hat)000T-6RQ 5
Navajo Tribal Util. Auth. (Red Mesa)111T-6RQ 6
Portland General Electric Company NANANA147RQ 7
Accrual NANANANARQ 8
9
Nonrequirement Sales: 10
Arizona Electric Power Cooperative NANANAT-12SF 11
Arizona Public Service Company NANANAT-12SF 12
Avangrid Renewables, LLC NANANAT-12AD 13
Avangrid Renewables, LLC 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 / /2016/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
99,944 104,277 204,221 5,652 2
63,519 68,423 131,942 3,593 3
40,736 26,882 67,618 1,267 4
16,005 16,628 32,633 919 5
152,975 134,141 287,116 8,781 6
687,015 687,015 6,558 7
-38,087 -38,087 -1,220 8
9
10
4,251,239 4,251,239 218,559 11
4,009,759 4,009,759 145,346 12
38 38 13
20,711,878 20,711,878 841,613 14
FERC FORM NO. 1 (ED. 12-90) Page 311
1,060,194
302,922,334
303,982,528
25,550
6,615,415
6,640,965
-38,087 1,372,458
-139,121,717
-139,159,804
175,726,002
177,098,460
350,351
11,925,385
12,275,736
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 / /2016/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Avista Corporation NANANAT-12SF 1
Avista Corporation NANANAT-13SF 2
BP Energy Company NANANAT-12SF 3
Basin Electric Power Cooperative NANANAT-12SF 4
Black Hills Power, Inc.NANANA441AD 5
Black Hills Power, Inc.NANANAT-12AD 6
Black Hills Power, Inc.385050441LF 7
Black Hills Power, Inc.NANANAT-12SF 8
Bonneville Power Administration NANANAT-12AD 9
Bonneville Power Administration NANANA519LU 10
Bonneville Power Administration NANANAT-12SF 11
Bonneville Power Administration NANANAT-13SF 12
British Columbia Hydro and Power NANANAT-13SF 13
Brookfield Energy Marketing L.P.NANANAT-12SF 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 / /2016/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.
1,249,538 1,249,538 67,250 1
432 432 17 2
13,195,990 13,195,990 534,363 3
488,246 488,246 22,571 4
41 41 2 5
247 247 51 6
5,034,260 7,529,185 12,563,445 252,506 7
2,752,197 2,752,197 127,044 8
309,498 309,498 9
2,894,286 2,894,286 41,513 10
1,473,632 1,473,632 71,327 11
9,954 9,954 422 12
18 18 1 13
755,168 755,168 33,404 14
FERC FORM NO. 1 (ED. 12-90) Page 311.1
1,060,194
302,922,334
303,982,528
25,550
6,615,415
6,640,965
-38,087 1,372,458
-139,121,717
-139,159,804
175,726,002
177,098,460
350,351
11,925,385
12,275,736
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 / /2016/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.
California Independent System Operator NANANAT-12AD 1
California Independent System Operator NANANAT-12SF 2
Calpine Energy Services, L.P.NANANAT-12SF 3
Cargill Power Markets, LLC NANANAT-12AD 4
Cargill Power Markets, LLC NANANAT-12SF 5
City of Anaheim NANANAT-12SF 6
City of Burbank NANANAT-12SF 7
City of Glendale NANANAT-12SF 8
City of Hurricane NANANAT-12LF 9
City of Redding NANANAT-12SF 10
City of Roseville NANANAT-12SF 11
Clatskanie People's Utility District NANANAT-12SF 12
ConocoPhillips Company NANANAT-12SF 13
EDF Trading North America, LLC NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.2
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2016/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.
-349,648 -349,648 -8,140 1
634,722 634,722 19,655 2
86,590 86,590 7,602 3
61 61 4
18,675,156 18,675,156 675,699 5
1,589,733 1,589,733 90,000 6
1,045,497 1,045,497 45,525 7
15,900 15,900 600 8
15,990 15,990 246 9
914,722 914,722 44,241 10
708,939 708,939 25,768 11
93,077 93,077 4,970 12
32,094 32,094 2,588 13
28,638,423 28,638,423 1,167,035 14
FERC FORM NO. 1 (ED. 12-90) Page 311.2
1,060,194
302,922,334
303,982,528
25,550
6,615,415
6,640,965
-38,087 1,372,458
-139,121,717
-139,159,804
175,726,002
177,098,460
350,351
11,925,385
12,275,736
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 / /2016/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
El Paso Electric Company NANANAT-12SF 1
Energy Keepers, Inc.NANANAT-12SF 2
Eugene Water & Electric Board NANANAT-12SF 3
Exelon Generation Company, LLC NANANAT-12AD 4
Exelon Generation Company, LLC NANANAT-12SF 5
Gridforce Energy Management NANANAT-13SF 6
Guzman Renewables Energy Partners LLC NANANAT-12SF 7
Idaho Power Company NANANAT-12SF 8
Idaho Power Company NANANAT-13SF 9
Idaho Power Company NANANAWSPP - QSF 10
Los Angeles Dept. of Water and Power NANANA301LU 11
Los Angeles Dept. of Water and Power NANANAT-12SF 12
Macquarie Energy LLC NANANAT-12SF 13
Modesto Irrigation District NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.3
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2016/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.
641,744 641,744 23,327 1
5,258 5,258 202 2
380,958 380,958 19,800 3
-25 4
41,338,964 41,338,964 1,719,620 5
2,233 2,233 85 6
2,650,832 2,650,832 93,114 7
210,000 210,000 12,631 8
8,084 8,084 357 9
1,297,772 1,297,772 44,451 10
3,318,535 3,318,535 122,424 11
3,375,428 3,375,428 142,040 12
2,204,148 2,204,148 98,862 13
214,509 214,509 8,553 14
FERC FORM NO. 1 (ED. 12-90) Page 311.3
1,060,194
302,922,334
303,982,528
25,550
6,615,415
6,640,965
-38,087 1,372,458
-139,121,717
-139,159,804
175,726,002
177,098,460
350,351
11,925,385
12,275,736
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 / /2016/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Morgan Stanley Capital Group Inc.NANANAT-12AD 1
Morgan Stanley Capital Group Inc.NANANAT-12OS 2
Morgan Stanley Capital Group Inc.NANANAT-12SF 3
Municipal Energy Agency of Nebraska NANANAT-12AD 4
Municipal Energy Agency of Nebraska NANANAT-12SF 5
NaturEner Power Watch, LLC NANANAT-13SF 6
Nevada Power Company NANANAWSPP - QSF 7
NextEra Energy Power Marketing, LLC NANANAT-12SF 8
NorthWestern Corporation NANANAT-12OS 9
NorthWestern Corporation NANANAT-12SF 10
NorthWestern Corporation NANANAT-13SF 11
NorthWestern Corporation NANANAWSPP - QSF 12
Portland General Electric Company NANANAT-12SF 13
Portland General Electric Company NANANAT-13SF 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 / /2016/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.
181 181 1
-6,720 -6,720 2
15,718,185 15,718,185 653,880 3
-640 -640 -40 4
415,094 415,094 19,789 5
271 271 16 6
499,056 499,056 23,113 7
56,900 56,900 2,800 8
-3,772 -3,772 9
336,501 336,501 14,612 10
4,087 4,087 154 11
798,136 798,136 29,722 12
2,110,760 900 2,111,660 109,963 13
3,115 3,115 123 14
FERC FORM NO. 1 (ED. 12-90) Page 311.4
1,060,194
302,922,334
303,982,528
25,550
6,615,415
6,640,965
-38,087 1,372,458
-139,121,717
-139,159,804
175,726,002
177,098,460
350,351
11,925,385
12,275,736
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 / /2016/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-12AD 2
Public Service Company of Colorado NANANAT-12SF 3
Public Service Company of New Mexico NANANAT-12SF 4
PUD No. 1 of Chelan County NANANAT-13SF 5
PUD No. 1 of Clark County NANANAT-12SF 6
PUD No. 1 of Douglas County NANANAT-13SF 7
PUD No. 1 of Snohomish County NANANAT-12SF 8
Puget Sound Energy, Inc.NANANAT-12SF 9
Puget Sound Energy, Inc.NANANAT-13SF 10
Rainbow Energy Marketing Corporation NANANAT-12SF 11
Rainbow Energy Marketing Corporation NANANAWSPP - QSF 12
Sacramento Municipal Utility District NANANAT-12SF 13
Sacramento Municipal Utility District NANANAT-13SF 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 / /2016/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.
2,031,813 1,550 2,033,363 123,216 1
-24 -24 -1 2
12,449,355 12,449,355 497,622 3
3,751,485 3,751,485 152,271 4
84 84 3 5
439,580 439,580 17,372 6
96 96 5 7
141,049 141,049 5,578 8
1,625,663 1,000 1,626,663 73,871 9
626 626 40 10
1,173,974 1,173,974 51,466 11
104,000 104,000 4,800 12
231,424 231,424 10,998 13
282 282 12 14
FERC FORM NO. 1 (ED. 12-90) Page 311.5
1,060,194
302,922,334
303,982,528
25,550
6,615,415
6,640,965
-38,087 1,372,458
-139,121,717
-139,159,804
175,726,002
177,098,460
350,351
11,925,385
12,275,736
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 / /2016/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.
Salt River Project NANANAT-12AD 1
Salt River Project NANANAT-12SF 2
Seattle City Light NANANAT-12SF 3
Seattle City Light NANANAT-13SF 4
Sempra Generation, LLC NANANAT-12AD 5
Sempra Generation, LLC NANANAT-12SF 6
Shell Energy North America (US), L.P.NANANAT-12AD 7
Shell Energy North America (US), L.P.NANANAT-12SF 8
Sierra Pacific Power Company NANANAT-13SF 9
Southern California Edison Company NANANAT-12SF 10
Tacoma Power NANANAT-12SF 11
Tacoma Power NANANAT-13SF 12
Talen Energy Marketing, LLC NANANAT-12OS 13
Talen Energy Marketing, LLC NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.6
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2016/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.
-1,556 -1,556 -75 1
5,572,610 5,572,610 223,087 2
453,726 453,726 21,894 3
107 107 4 4
879 879 37 5
12,951,573 12,951,573 504,385 6
2,935 2,935 176 7
22,833,026 22,833,026 1,017,507 8
7,953 7,953 405 9
12,980,448 12,980,448 459,659 10
228,872 228,872 13,860 11
108 108 7 12
-85 -85 13
476,486 476,486 21,496 14
FERC FORM NO. 1 (ED. 12-90) Page 311.6
1,060,194
302,922,334
303,982,528
25,550
6,615,415
6,640,965
-38,087 1,372,458
-139,121,717
-139,159,804
175,726,002
177,098,460
350,351
11,925,385
12,275,736
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 / /2016/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Tenaska Power Services Co.NANANAT-12SF 1
Tenaska Power Services Co.NANANAWSPP - QSF 2
The Energy Authority, Inc.NANANAT-12SF 3
TransAlta Energy Marketing (U.S.) Inc.NANANAT-12OS 4
TransAlta Energy Marketing (U.S.) Inc.NANANAT-12AD 5
TransAlta Energy Marketing (U.S.) Inc.NANANAT-12SF 6
TransCanada Energy Sales Ltd.NANANAT-12SF 7
Tri-State Gen. and Trans.NANANAT-12SF 8
Tucson Electric Power Company NANANAT-12OS 9
Tucson Electric Power Company NANANAT-12SF 10
Turlock Irrigation District NANANAT-12SF 11
UNS Electric, Inc.NANANAT-12SF 12
Utah Associated Municipal Power Systems NANANAT-12OS 13
Utah Associated Municipal Power Systems 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 / /2016/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
5,647,281 5,647,281 265,090 1
38,092 38,092 1,497 2
761,626 761,626 34,949 3
-283 -283 4
1,856 1,856 74 5
6,918,860 6,918,860 353,023 6
31,522 31,522 1,177 7
1,438,628 1,438,628 73,869 8
-5,994 -5,994 9
5,014,074 5,014,074 212,477 10
4,498,268 4,498,268 164,101 11
1,358,298 1,358,298 55,608 12
-338 -338 13
60,960 60,960 1,405 14
FERC FORM NO. 1 (ED. 12-90) Page 311.7
1,060,194
302,922,334
303,982,528
25,550
6,615,415
6,640,965
-38,087 1,372,458
-139,121,717
-139,159,804
175,726,002
177,098,460
350,351
11,925,385
12,275,736
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 / /2016/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.
Utah Associated Municipal Power Systems NANANAWSPP - QSF 1
Utah Municipal Power Agency 293434433LF 2
Utah Municipal Power Agency NANANAT-12SF 3
Utah Municipal Power Agency NANANAWSPP - QSF 4
Vitol Inc.NANANAT-12SF 5
Western Area Power Administration NANANAT-12SF 6
Transmission Loss Sales Revenue NANANAT-11AD 7
Transmission Loss Sales Revenue NANANAT-11OS 8
Netting - Bookouts NANANANA 9
Netting - Trading NANANANA 10
Accrual NANANANA 11
12
13
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 / /2016/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
-6 -6 1
4,335,459 4,396,200 8,731,659 195,270 2
11,885 11,885 430 3
287,250 287,250 13,840 4
7,430,839 7,430,839 335,700 5
2,804,398 2,804,398 108,208 6
-1,334,659 -1,334,659 1,876 7
3,980,817 3,980,817 172,005 8
-140,906,003 -140,906,003 -6,130,887 9
-657,255 -657,255 10
-192,193 -192,193 -15,343 11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 311.8
1,060,194
302,922,334
303,982,528
25,550
6,615,415
6,640,965
-38,087 1,372,458
-139,121,717
-139,159,804
175,726,002
177,098,460
350,351
11,925,385
12,275,736
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
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 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 310 Line No.: 13 Column: j
Settlement adjustment.
Schedule Page: 310.1 Line No.: 2 Column: j
Reserve share.
Schedule Page: 310.1 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 5 Column: j
Settlement adjustment.
Schedule Page: 310.1 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 6 Column: j
Settlement adjustment.
Schedule Page: 310.1 Line No.: 7 Column: b
Black Hills Power, Inc. - FERC 441 - Contract termination date: December 31, 2023.
Schedule Page: 310.1 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 9 Column: j
Settlement adjustment.
Schedule Page: 310.1 Line No.: 12 Column: j
Reserve share.
Schedule Page: 310.1 Line No.: 13 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: 310.1 Line No.: 13 Column: j
Reserve share.
Schedule Page: 310.2 Line No.: 1 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.: 1 Column: b
Settlement adjustment.
Schedule Page: 310.2 Line No.: 1 Column: j
Settlement adjustment.
Schedule Page: 310.2 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 310.2 Line No.: 4 Column: j
Settlement adjustment.
Schedule Page: 310.2 Line No.: 9 Column: b
City of Hurricane - FERC T-12 - Contract termination date: August 31, 2017.
Schedule Page: 310.3 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 310.3 Line No.: 6 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Reserve share.
Schedule Page: 310.3 Line No.: 9 Column: j
Reserve share.
Schedule Page: 310.3 Line No.: 11 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: 310.4 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 310.4 Line No.: 1 Column: j
Settlement adjustment.
Schedule Page: 310.4 Line No.: 2 Column: b
Pursuant to FERC Docket No. ER10-2475-006,et al. revoking PacifiCorp's market-based rate
authority.
Schedule Page: 310.4 Line No.: 2 Column: j
Pursuant to FERC Docket No. ER10-2475-006,et al. revoking PacifiCorp's market-based rate
authority.
Schedule Page: 310.4 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 310.4 Line No.: 4 Column: j
Settlement adjustment.
Schedule Page: 310.4 Line No.: 6 Column: j
Reserve share.
Schedule Page: 310.4 Line No.: 7 Column: a
This footnote applies to all occurrences of "Nevada Power Company" on pages 310-311.
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: 310.4 Line No.: 9 Column: b
Pursuant to FERC Docket No. ER10-2475-006,et al. revoking PacifiCorp's market-based rate
authority.
Schedule Page: 310.4 Line No.: 9 Column: j
Pursuant to FERC Docket No. ER10-2475-006,et al. revoking PacifiCorp's market-based rate
authority.
Schedule Page: 310.4 Line No.: 11 Column: j
Reserve share.
Schedule Page: 310.4 Line No.: 13 Column: j
Pond sales.
Schedule Page: 310.4 Line No.: 14 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 1 Column: j
Pond sales.
Schedule Page: 310.5 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 310.5 Line No.: 2 Column: j
Settlement adjustment.
Schedule Page: 310.5 Line No.: 5 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: 310.5 Line No.: 5 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 6 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: 310.5 Line No.: 7 Column: a
This footnote applies to all occurrences of "PUD No. 1 of Douglas County" on pages
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
310-311. Complete name is Public Utility District No. 1 of Douglas County.
Schedule Page: 310.5 Line No.: 7 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 8 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: 310.5 Line No.: 9 Column: j
Pond sales.
Schedule Page: 310.5 Line No.: 10 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 14 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 310.6 Line No.: 1 Column: j
Settlement adjustment.
Schedule Page: 310.6 Line No.: 4 Column: j
Reserve share.
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.: 7 Column: b
Settlement adjustment.
Schedule Page: 310.6 Line No.: 7 Column: j
Settlement adjustment.
Schedule Page: 310.6 Line No.: 9 Column: a
This footnote applies to all occurrences of "Sierra Pacific Power Company" on pages
310-311. 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: 310.6 Line No.: 9 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 12 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 13 Column: b
Pursuant to FERC Docket No. ER10-2475-006,et al. revoking PacifiCorp's market-based rate
authority.
Schedule Page: 310.6 Line No.: 13 Column: j
Pursuant to FERC Docket No. ER10-2475-006,et al. revoking PacifiCorp's market-based rate
authority.
Schedule Page: 310.7 Line No.: 4 Column: b
Pursuant to FERC Docket No. ER10-2475-006,et al. revoking PacifiCorp's market-based rate
authority.
Schedule Page: 310.7 Line No.: 4 Column: j
Pursuant to FERC Docket No. ER10-2475-006,et al. revoking PacifiCorp's market-based rate
authority.
Schedule Page: 310.7 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 310.7 Line No.: 5 Column: j
Settlement adjustment.
Schedule Page: 310.7 Line No.: 8 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 310.7 Line No.: 9 Column: b
Pursuant to FERC Docket No. ER10-2475-006,et al. revoking PacifiCorp's market-based rate
authority.
Schedule Page: 310.7 Line No.: 9 Column: j
Pursuant to FERC Docket No. ER10-2475-006,et al. revoking PacifiCorp's market-based rate
authority.
Schedule Page: 310.7 Line No.: 13 Column: b
Pursuant to FERC Docket No. ER10-2475-006,et al. revoking PacifiCorp's market-based rate
authority.
Schedule Page: 310.7 Line No.: 13 Column: j
Pursuant to FERC Docket No. ER10-2475-006,et al. revoking PacifiCorp's market-based rate
authority.
Schedule Page: 310.8 Line No.: 2 Column: b
Utah Municipal Power Agency - FERC 433 - Contract termination date: June 30, 2017.
Schedule Page: 310.8 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 310.8 Line No.: 7 Column: j
Settlement adjustment.
Schedule Page: 310.8 Line No.: 8 Column: b
Pursuant to FERC Docket No. ER10-2475-006,et al. revoking PacifiCorp's market-based rate
authority.
Schedule Page: 310.8 Line No.: 8 Column: j
Pursuant to FERC Docket No. ER10-2475-006,et al. revoking PacifiCorp's market-based rate
authority.
Schedule Page: 310.8 Line No.: 9 Column: j
Reflects transactions that did not physically settle.
Schedule Page: 310.8 Line No.: 10 Column: j
Reflects transactions that did not physically settle.
Schedule Page: 310.8 Line No.: 11 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
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
/ /2016/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 15,517,011 19,302,289
(501) Fuel 5 893,792,204 820,850,664
(502) Steam Expenses 6 84,614,045 77,494,812
(503) Steam from Other Sources 7 3,980,975 4,387,771
(Less) (504) Steam Transferred-Cr. 8
(505) Electric Expenses 9 2,351,648 1,357,681
(506) Miscellaneous Steam Power Expenses 10 -15,574,943 18,783,155
(507) Rents 11 394,702 497,552
(509) Allowances 12
TOTAL Operation (Enter Total of Lines 4 thru 12) 13 985,075,642 942,673,924
Maintenance 14
(510) Maintenance Supervision and Engineering 15 8,514,939 8,590,720
(511) Maintenance of Structures 16 30,664,954 29,659,884
(512) Maintenance of Boiler Plant 17 95,031,926 94,238,044
(513) Maintenance of Electric Plant 18 34,835,090 31,617,221
(514) Maintenance of Miscellaneous Steam Plant 19 11,894,236 9,939,070
TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 180,941,145 174,044,939
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 1,166,016,787 1,116,718,863
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 8,836,151 8,994,999
(536) Water for Power 45 121,947 48,260
(537) Hydraulic Expenses 46 4,327,999 4,438,179
(538) Electric Expenses 47
(539) Miscellaneous Hydraulic Power Generation Expenses 48 17,875,790 16,390,065
(540) Rents 49 1,573,497 1,339,115
TOTAL Operation (Enter Total of Lines 44 thru 49) 50 32,735,384 31,210,618
C. Hydraulic Power Generation (Continued) 51
Maintenance 52
(541) Mainentance Supervision and Engineering 53 388 400
(542) Maintenance of Structures 54 907,301 1,157,602
(543) Maintenance of Reservoirs, Dams, and Waterways 55 1,413,192 4,031,155
(544) Maintenance of Electric Plant 56 1,749,826 2,527,278
(545) Maintenance of Miscellaneous Hydraulic Plant 57 3,016,038 3,013,546
TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 7,086,745 10,729,981
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 39,822,129 41,940,599
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
/ /2016/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 62 418,092 315,661
(547) Fuel 63 272,426,195 252,938,388
(548) Generation Expenses 64 18,238,116 16,727,699
(549) Miscellaneous Other Power Generation Expenses 65 7,745,388 5,300,600
(550) Rents 66 3,491,472 4,007,994
TOTAL Operation (Enter Total of lines 62 thru 66) 67 302,319,263 279,290,342
Maintenance 68
(551) Maintenance Supervision and Engineering 69
(552) Maintenance of Structures 70 4,228,009 2,825,560
(553) Maintenance of Generating and Electric Plant 71 26,813,693 17,358,571
(554) Maintenance of Miscellaneous Other Power Generation Plant 72 1,481,768 2,135,375
TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 32,523,470 22,319,506
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 334,842,733 301,609,848
E. Other Power Supply Expenses 75
(555) Purchased Power 76 623,108,136 580,289,645
(556) System Control and Load Dispatching 77 1,426,643 1,686,094
(557) Other Expenses 78 48,032,087 43,257,013
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 672,566,866 625,232,752
TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 2,213,248,515 2,085,502,062
2. TRANSMISSION EXPENSES 81
Operation 82
(560) Operation Supervision and Engineering 83 9,280,674 7,696,616
84
(561.1) Load Dispatch-Reliability 85
(561.2) Load Dispatch-Monitor and Operate Transmission System 86 6,818,716 7,180,746
(561.3) Load Dispatch-Transmission Service and Scheduling 87
(561.4) Scheduling, System Control and Dispatch Services 88 2,106,756 1,818,514
(561.5) Reliability, Planning and Standards Development 89 1,326,587 1,747,640
(561.6) Transmission Service Studies 90 106,311 107,188
(561.7) Generation Interconnection Studies 91 998,299 1,290,346
(561.8) Reliability, Planning and Standards Development Services 92 7,402,436 7,528,820
(562) Station Expenses 93 3,072,973 3,574,521
(563) Overhead Lines Expenses 94 409,509 523,824
(564) Underground Lines Expenses 95
(565) Transmission of Electricity by Others 96 148,425,345 130,788,907
(566) Miscellaneous Transmission Expenses 97 2,400,520 3,701,508
(567) Rents 98 2,248,767 2,406,374
TOTAL Operation (Enter Total of lines 83 thru 98) 99 184,596,893 168,365,004
Maintenance 100
(568) Maintenance Supervision and Engineering 101 1,186,503 967,541
(569) Maintenance of Structures 102 19,905 71,460
(569.1) Maintenance of Computer Hardware 103 105,911 163,187
(569.2) Maintenance of Computer Software 104 406,743 290,354
(569.3) Maintenance of Communication Equipment 105 3,624,514 4,163,332
(569.4) Maintenance of Miscellaneous Regional Transmission Plant 106
(570) Maintenance of Station Equipment 107 8,037,307 11,581,205
(571) Maintenance of Overhead Lines 108 17,091,353 17,444,207
(572) Maintenance of Underground Lines 109 51,642 98,313
(573) Maintenance of Miscellaneous Transmission Plant 110 543,682 116,402
TOTAL Maintenance (Total of lines 101 thru 110) 111 31,067,560 34,896,001
TOTAL Transmission Expenses (Total of lines 99 and 111) 112 215,664,453 203,261,005
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
/ /2016/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 11,287,882 10,211,712
(581) Load Dispatching 135 11,746,191 11,608,861
(582) Station Expenses 136 4,235,949 4,455,539
(583) Overhead Line Expenses 137 6,808,598 7,582,880
(584) Underground Line Expenses 138 6,628 1,120
(585) Street Lighting and Signal System Expenses 139 223,951 248,347
(586) Meter Expenses 140 6,584,411 6,053,312
(587) Customer Installations Expenses 141 10,551,937 13,509,277
(588) Miscellaneous Expenses 142 4,670,374 4,583,209
(589) Rents 143 3,315,582 3,318,918
TOTAL Operation (Enter Total of lines 134 thru 143) 144 59,431,503 61,573,175
Maintenance 145
(590) Maintenance Supervision and Engineering 146 5,710,663 5,375,453
(591) Maintenance of Structures 147 2,230,204 1,997,387
(592) Maintenance of Station Equipment 148 11,414,124 10,617,895
(593) Maintenance of Overhead Lines 149 91,628,672 80,772,052
(594) Maintenance of Underground Lines 150 22,910,745 25,704,585
(595) Maintenance of Line Transformers 151 922,335 1,075,858
(596) Maintenance of Street Lighting and Signal Systems 152 3,252,544 3,239,309
(597) Maintenance of Meters 153 4,294,012 5,970
(598) Maintenance of Miscellaneous Distribution Plant 154 5,240,622 6,136,247
TOTAL Maintenance (Total of lines 146 thru 154) 155 147,603,921 134,924,756
TOTAL Distribution Expenses (Total of lines 144 and 155) 156 207,035,424 196,497,931
5. CUSTOMER ACCOUNTS EXPENSES 157
Operation 158
(901) Supervision 159 1,739,975 2,334,844
(902) Meter Reading Expenses 160 17,341,069 18,089,729
(903) Customer Records and Collection Expenses 161 52,023,964 48,583,852
(904) Uncollectible Accounts 162 10,227,550 12,228,903
(905) Miscellaneous Customer Accounts Expenses 163 33,442 1,949,683
TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 81,366,000 83,187,011
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
/ /2016/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 167 271,770 278,714
(908) Customer Assistance Expenses 168 132,301,137 143,987,121
(909) Informational and Instructional Expenses 169 3,123,200 3,093,817
(910) Miscellaneous Customer Service and Informational Expenses 170 15,904 54,913
TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 135,712,011 147,414,565
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 78,097,396 72,807,417
(921) Office Supplies and Expenses 182 8,563,778 8,563,731
(Less) (922) Administrative Expenses Transferred-Credit 183 37,773,122 33,233,808
(923) Outside Services Employed 184 16,829,096 14,997,016
(924) Property Insurance 185 15,938,310 14,265,351
(925) Injuries and Damages 186 5,349,612 1,256,342
(926) Employee Pensions and Benefits 187
(927) Franchise Requirements 188
(928) Regulatory Commission Expenses 189 22,275,686 25,261,821
(929) (Less) Duplicate Charges-Cr. 190 5,386,124 3,584,897
(930.1) General Advertising Expenses 191 319 1,818
(930.2) Miscellaneous General Expenses 192 2,386,938 2,346,536
(931) Rents 193 4,960,462 4,735,239
TOTAL Operation (Enter Total of lines 181 thru 193) 194 111,242,351 107,416,566
Maintenance 195
(935) Maintenance of General Plant 196 22,974,990 22,216,334
TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 134,217,341 129,632,900
TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 2,987,243,744 2,845,495,474
FERC FORM NO. 1 (ED. 12-93) Page 323
Schedule Page: 320 Line No.: 10 Column: c
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.: 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, 2016 and 2015, pensions and benefits expense was $113,808,905 and $124,649,217,
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
2016/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 / /2016/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
NANANAApple, Inc. LU 3
NANANAArizona Electric Power Cooperative AD 4
NANANAArizona Electric Power Cooperative SF 5
NANANAArizona Public Service Company LF 6
NANANAArizona Public Service Company SF 7
NANANAAvangrid Renewables, LLC AD 8
NANANAAvangrid Renewables, LLC SF 9
NANANAAvista Corporation SF 10
NANANABC Solar, LLC LU 11
NANANABP Energy Company SF 12
NANANABallard Hog Farms Inc. AD 13
0.030.030.037Ballard Hog Farms Inc. LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2016/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
81,797 81,797 2
560,487 560,487 3 7,493
1,517 1,517 4 74
147,588 147,588 5 4,800
717,362 717,362 6 32,025
2,595,724 154,740 2,750,464 7 129,392
320 320 8
42,916,390 42,916,390 9 1,845,590
2,652,162 7,076 2,659,238 10 145,339
27,024 27,024 11 472
12,736,726 12,736,726 12 587,139
1,145 1,145 13 19
5,784 12,494 18,278 14 278
FERC FORM NO. 1 (ED. 12-90) Page 327
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANABasin Electric Power Cooperative SF 1
NANANABeaver City Corporation LF 2
NANANABell Mountain Hydro, LLC LU 3
0.733Beryl Solar, LLC LU 4
NANANABig Top, LLC LU 5
NANANABiomass One, L.P. LU 6
NANANABirch Power Company, Inc. AD 7
NANANABirch Power Company, Inc. LU 8
NANANABlack Cap Solar, LLC LU 9
NANANABlack Hills Power, Inc. SF 10
NANANABonneville Power Administration LF 11
NANANABonneville Power Administration OS 12
NANANABonneville Power Administration SF 13
NANANABourdet, Peter M. LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.1
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2016/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.
1,580,302 1,580,302 1 68,288
4,409 4,409 2 55
61,809 61,809 3 759
407,685 265,601 673,286 4 5,915
286,480 286,480 5 3,899
11,661,538 2,595,743 14,257,281 6 159,261
20,699 20,699 7 333
712,449 712,449 8 11,317
16,031 16,031 9 660
288,987 288,987 10 8,085
10,198 10,198 11
113,235 113,235 12
9,478,550 45,231 9,523,781 13 640,180
5,298 5,298 14 221
FERC FORM NO. 1 (ED. 12-90) Page 327.1
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
2.54.22.921Box Canyon Limited Partnership LU 1
NANANABrigham City Corporation SF 2
NANANABrigham Young University - Idaho AD 3
NANANABrigham Young University - Idaho IU 4
NANANABrookfield Energy Marketing L.P. SF 5
0.290.540.5Buckhorn Solar, LLC LU 6
NANANAButter Creek Power, LLC LU 7
NANANAC Drop Hydro, LLC LU 8
NANANACDM Hydroelectric Company LU 9
NANANACalifornia Independent System Operator AD 10
NANANACalifornia Independent System Operator SF 11
NANANACalpine Energy Services, L.P. SF 12
NANANACameron A. Curtiss LU 13
NANANACargill Power Markets, LLC SF 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 / /2016/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.
278,289 3,225,688 3,503,977 1 23,912
43,248 43,248 2
165,876 165,876 3
2,041,726 2,041,726 4 39,319
13,000 13,000 5 800
401,593 255,644 657,237 6 5,694
849,453 849,453 7 11,626
191,628 191,628 8 2,539
1,663,034 1,663,034 9 26,490
-431,047 -431,047 10 -8,164
85,435 85,435 11 1,873
1,970,211 1,970,211 12 62,973
6,275 6,275 13 83
12,684,690 12,684,690 14 538,726
FERC FORM NO. 1 (ED. 12-90) Page 327.2
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
0.22.32.4Cedar Valley Solar, LLC LU 1
2.23.43.5Central Oregon Irrigation District LU 2
NANANAChevron U.S.A. Inc. LU 3
NANANAChopin Wind LLC LU 4
NANANACity of Albany LU 5
NANANACity of Astoria LU 6
NANANACity of Buffalo LU 7
NANANACity of Burbank SF 8
NANANACity of Hurricane LF 9
NANANACity of Lehi IF 10
NANANACity of Portland, Water Bureau LU 11
NANANACity of Preston Idaho LU 12
NANANACity of Redding SF 13
NANANAClatskanie People's Utility District 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 / /2016/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.
333,093 153,106 486,199 1 3,410
357,837 3,480,736 3,838,573 2 34,651
576,848 576,848 3 42,051
471,389 471,389 4 9,671
96,027 96,027 5 1,271
967 967 6 29
50,537 50,537 7 1,893
39,500 39,500 8 1,200
126,653 126,653 9 1,949
405 405 10 4
8,435 8,435 11 112
175,521 175,521 12 3,003
6,780 6,780 13 710
48,739 48,739 14 2,655
FERC FORM NO. 1 (ED. 12-90) Page 327.3
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
NANANACommercial Energy Management Inc. LU 1
NANANAConocoPhillips Company SF 2
NANANAConsolidated Irrigation Company LU 3
NANANACottonwood Hydro, LLC IU 4
NANANACrook County Solar 1, LLC LU 5
3.14.15.689Deschutes Valley Water District LU 6
639160Deseret Generation & Transmission Coop LF 7
NANANADorena Hydro, LLC LU 8
0.81.20.7Douglas County LU 9
NANANADouglas County, Inc. LU 10
NANANADraper Irrigation Company IU 11
NANANADry Creek LLC LU 12
NANANAeBay Inc. LU 13
NANANAEDF Trading North America, LLC 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 / /2016/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.
92,697 92,697 1 1,640
182,580 182,580 2 8,000
105,056 105,056 3 2,195
152,582 152,582 4 3,144
29,377 29,377 5 1,235
564,134 3,826,371 4,390,505 6 30,105
16,754,873 5,998,832 4,345,631 27,099,336 7 280,826
839,421 839,421 8 11,121
72,977 1,033,126 1,106,103 9 7,240
100,096 100,096 10 4,974
20,177 20,177 11 325
674,176 674,176 12 11,133
62,255 62,255 13 876
63,543,899 63,543,899 14 2,626,399
FERC FORM NO. 1 (ED. 12-90) Page 327.4
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
NANANAEl Paso Electric Company SF 1
NANANAElement Markets, LLC OS 2
NANANAEnterprise Solar, LLC LU 3
NANANAEugene Water & Electric Board SF 4
NANANAEurus Combine Hills I, LLC LU 5
NANANAEvergreen BioPower, LLC LU 6
NANANAExelon Generation Company, LLC AD 7
NANANAExelon Generation Company, LLC IF 8
NANANAExelon Generation Company, LLC SF 9
NANANAExxonMobil Production Company LU 10
23.22.7Falls Creek H.P. Limited Partnership LU 11
NANANAFarm Power Misty Meadow, LLC LU 12
NANANAFarmers Irrigation District LU 13
NANANAFillmore City Corporation LF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.5
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 / /2016/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.
184,691 937 185,628 1 9,519
29,565 29,565 2
4,497,225 4,497,225 3 140,268
446,004 446,004 4 20,917
5,541,593 5,541,593 5 116,763
3,460,539 3,460,539 6 50,268
3,108 3,108 7 75
4,827,885 4,827,885 8 122,904
12,225,765 12,225,765 9 632,329
11,023 11,023 10 265
228,727 2,288,360 2,517,087 11 17,739
186,344 186,344 12 2,409
1,473,372 1,473,372 13 21,156
19,768 19,768 14 182
FERC FORM NO. 1 (ED. 12-90) Page 327.5
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAFinley BioEnergy, LLC LU 1
NANANAFlathead Electric Cooperative, Inc. LF 2
NANANAFoote Creek II, LLC LU 3
NANANAFoote Creek III, LLC LU 4
NANANAFour Brothers Solar, LLC LU 5
NANANAFour Corners Windfarm, LLC LU 6
NANANAFour Mile Canyon Windfarm, LLC LU 7
0.10.10.11George DeRuyter & Sons Dairy LU 8
NANANAGeorgetown Irrigation Company LU 9
NANANAGrand Valley Power LF 10
NANANAGranite Mountain Holdings LLC LU 11
NANANAGranite Peak Solar, LLC AD 12
0.533Granite Peak Solar, LLC LU 13
0.42.22.3Greenville Solar, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.6
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2016/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.
2,044,395 2,044,395 1 27,114
8,001 8,001 2 422
103,549 103,549 3 5,446
1,631,017 1,631,017 4 75,950
9,344,319 9,344,319 5 277,275
2,053,690 2,053,690 6 28,062
1,851,456 1,851,456 7 25,264
3,420 32,954 36,374 8 979
111,551 111,551 9 1,813
10,116 10,116 10 46
3,439,175 3,439,175 11 81,525
1,030 1,030 12
203,655 177,487 381,142 13 5,529
314,576 158,825 473,401 14 3,537
FERC FORM NO. 1 (ED. 12-90) Page 327.6
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
NANANAGridforce Energy Management SF 1
NANANAGuzman Renewables Energy Partners LLC SF 2
NANANAHarold Foster & Robert Walker LU 3
NANANAHermiston Generating Company, L.P. AD 4
75.711691.2Hermiston Generating Company, L.P. LU 5
NANANAIdaho Falls, City of AD 6
NANANAIdaho Falls, City of LU 7
NANANAIdaho Power Company SF 8
NANANAIntermountain Power Agency LU 9
NANANAIron Springs Solar, LLC LU 10
NANANAJ Bar 9 Ranch, Inc. LU 11
NANANAJake Amy LU 12
NANANAJoseph Community Solar LLC LU 13
NANANAKettle Butte Digester LLC AD 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 / /2016/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.
1,219 1,219 1 44
95,639 95,639 2 2,809
27,843 27,843 3 691
244 244 4 -1
18,964,289 9,527,897 129,784 28,621,970 5 547,251
-43,265 -43,265 6
1,226,190 1,226,190 7 51,838
150,167 836 151,003 8 11,053
3,318,535 3,318,535 9 122,424
4,775,689 4,775,689 10 114,477
3,166 3,166 11 53
80,880 80,880 12 1,356
15,747 15,747 13 685
-3,177 -3,177 14
FERC FORM NO. 1 (ED. 12-90) Page 327.7
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
NANANAKettle Butte Digester LLC LU 1
NANANAKlamath Falls Solar 1 LLC LU 2
NANANALacomb Irrigation District LU 3
0.733Laho Solar, LLC LU 4
NANANALatigo Wind Park, LLC LU 5
NANANALos Angeles Dept. of Water and Power SF 6
NANANALower Valley Energy, Inc. IU 7
NANANALower Valley Energy, Inc. LU 8
NANANALoyd Fery LU 9
NANANAMacquarie Energy LLC SF 10
NANANAMarsh Valley Hydro Electric Company LU 11
NANANAMeadow Creek Project Company LLC LU 12
NANANAMiddle Fork Irrigation District LU 13
NANANAMilford Flat Solar, 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 / /2016/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.
463,201 463,201 1 6,324
37,305 37,305 2 880
101,436 40,015 141,451 3 5,048
203,889 195,244 399,133 4 6,082
6,336,211 6,336,211 5 111,184
361,792 361,792 6 10,663
298,783 298,783 7 5,876
76,878 76,878 8 1,488
10,094 10,094 9 336
3,187,959 3,187,959 10 138,268
297,147 297,147 11 4,729
19,317,496 19,317,496 12 277,877
1,748,796 1,748,796 13 25,453
146,225 146,225 14 6,074
FERC FORM NO. 1 (ED. 12-90) Page 327.8
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
NANANAMink Creek Hydro LLC LU 1
NANANAMonsanto Company AD 2
NANANAMonsanto Company IU 3
NANANAMorgan City Corporation LF 4
NANANAMorgan Stanley Capital Group Inc. SF 5
NANANAMountain Energy, Inc. LU 6
NANANAMountain Wind Power II, LLC LU 7
NANANAMountain Wind Power, LLC LU 8
NANANAMunicipal Energy Agency of Nebraska SF 9
NANANANevada Power Company AD 10
NANANANevada Power Company SF 11
NANANANextEra Energy Power Marketing, LLC AD 12
NANANANextEra Energy Power Marketing, LLC SF 13
0.30.60.4Nichols Gap Limited Partnership 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 / /2016/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.
568,222 568,222 1 9,290
293,365 293,365 2
20,000,000 20,000,000 3
898 898 4 10
8,853,579 8,853,579 5 280,658
6,014 6,014 6 80
13,773,713 13,773,713 7 211,253
9,021,283 9,021,283 8 160,884
131,002 131,002 9 3,944
-795 -795 10
406,715 92,769 499,484 11 17,251
-11,950 -11,950 12
33,620 33,620 13 1,800
42,172 466,259 508,431 14 3,467
FERC FORM NO. 1 (ED. 12-90) Page 327.9
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
NANANANicholson's Sunny Bar Ranch LU 1
NANANANorthWestern Corporation OS 2
NANANANorthWestern Corporation SF 3
NANANANucor Corporation IF 4
NANANAO.J. Power Company LU 5
NANANAOSLH, LLC LU 6
NANANAObsidian Renewables, LLC LU 7
NANANAOld Mill Solar, LLC LU 8
NANANAOregon Environmental Industries, LLC LU 9
NANANAOregon Institute of Technology LU 10
NANANAOregon Solar Incentive LU 11
NANANAOregon State University LU 12
NANANAOregon Trail Windfarm, LLC LU 13
NANANAPacific Canyon Windfarm, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.10
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2016/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.
98,469 98,469 1 1,579
13,582 13,582 2 796
116,354 6,322 122,676 3 7,707
7,129,800 7,129,800 4
20,318 20,318 5 379
35 35 6 1
22,021 22,021 7 910
659,436 659,436 8 9,015
1,477,968 1,477,968 9 21,560
5,852 5,852 10 315
259,618 259,618 11 11,013
67 67 12 4
1,583,947 1,583,947 13 21,616
1,313,339 1,313,339 14 17,859
FERC FORM NO. 1 (ED. 12-90) Page 327.10
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
NANANAPaul Luckey LU 1
NANANAPavant Solar II, LLC LU 2
NANANAPavant Solar III, LLC LU 3
NANANAPavant Solar, LLC LU 4
NANANAPioneer Wind Park LU 5
NANANAPlatte River Power Authority AD 6
NANANAPlatte River Power Authority SF 7
NANANAPortland General Electric Company AD 8
NANANAPortland General Electric Company LF 9
NANANAPortland General Electric Company SF 10
NANANAPower County Wind Park North, LLC LU 11
NANANAPower County Wind Park South, LLC LU 12
NANANAPowerex Corporation OS 13
NANANAPowerex Corporation 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 / /2016/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
11,947 11,947 1 250
176,112 176,112 2 8,509
5,072 5,072 3 96
3,736,048 3,736,048 4 109,951
2,949,562 2,949,562 5 81,794
-2,645 -2,645 6
71,446 71,446 7 3,624
-52,594 -52,594 8
187,000 187,000 9 11,941
1,738,575 10,898 1,749,473 10 81,437
4,544,696 4,544,696 11 63,878
3,878,177 3,878,177 12 54,521
8,515 8,515 13 195
16,236,708 16,236,708 14 564,807
FERC FORM NO. 1 (ED. 12-90) Page 327.11
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
NANANAProvo City Corporation LF 1
NANANAPublic Service Company of Colorado SF 2
NANANAPublic Service Company of New Mexico AD 3
NANANAPublic Service Company of New Mexico SF 4
NANANAPUD No. 1 of Chelan County SF 5
NANANAPUD No. 1 of Clark County SF 6
NANANAPUD No. 1 of Cowlitz County OS 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 326.12
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 / /2016/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.
4,219 4,219 1 48
5,046,406 5,046,406 2 247,748
675 675 3 25
1,519,364 120 1,519,484 4 63,778
1,469,506 1,756 1,471,262 5 72,351
258,080 258,080 6 15,352
-128,733 -128,733 7
2,144,642 2,144,642 8 62,384
3,650,764 3,650,764 9 248,655
455,360 606 455,966 10 26,474
989,520 989,520 11 70,860
-179,661 -179,661 12
765,175 765,175 13 91,474
3,754 3,754 14 149
FERC FORM NO. 1 (ED. 12-90) Page 327.12
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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. AD 1
NANANAPuget Sound Energy, Inc. SF 2
NANANAQuichapa LU 3
NANANARES Ag - Oak Lea LLC LU 4
NANANARainbow Energy Marketing Corporation SF 5
NANANARenewable Power Strategies OS 6
NANANARock River 1, LLC AD 7
NANANARock River 1, LLC LU 8
NANANARoseburg Forest Products Company LU 9
NANANARoseburg LFG Energy, LLC LU 10
NANANARough & Ready Lumber Company LU 11
NANANARoush Hydro Inc. LU 12
NANANASacramento Municipal Utility District AD 13
NANANASacramento Municipal Utility District SF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.13
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2016/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
11,950 11,950 1
3,476,252 11,942 3,488,194 2 212,591
75,911 75,911 3 761
37,674 37,674 4 488
1,266,368 1,266,368 5 38,399
310,166 310,166 6
7 43
5,172,608 5,172,608 8 145,789
3,677,245 3,677,245 9 65,223
927,566 927,566 10 12,303
22,936 22,936 11 302
8,093 8,093 12 271
135,779 135,779 13
70,200 70,200 14 2,400
FERC FORM NO. 1 (ED. 12-90) Page 327.13
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
NANANASalt River Project SF 1
NANANASand Ranch Windfarm, LLC LU 2
0.20.20.2Santiam Water Control District LU 3
NANANASeattle City Light SF 4
NANANASempra Generation, LLC SF 5
NANANAShell Energy North America (US), L.P. AD 6
NANANAShell Energy North America (US), L.P. SF 7
NANANAShiloh Warm Springs Ranch, LLC LU 8
NANANASierra Pacific Power Company SF 9
0.72.21.89Slate Creek Hydro Company, Inc. LU 10
NANANASolwatt LLC LU 11
NANANASouth Utah Valley Electric LF 12
NANANASouthern California Edison Company AD 13
NANANASouthern California Edison Company SF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.14
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 / /2016/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.
8,640,119 2,663 8,642,782 1 342,019
1,558,379 1,558,379 2 21,179
13,426 173,171 186,597 3 1,434
2,047,923 4,736 2,052,659 4 112,990
3,326,132 3,326,132 5 185,350
9,369 9,369 6 271
12,458,136 12,458,136 7 547,514
44,424 44,424 8 712
3,894 6,639 10,533 9 275
173,288 1,291,223 1,464,511 10 10,537
19,109 19,109 11 810
1,456 1,456 12 21
776 776 13 37
2,769 2,769 14 153
FERC FORM NO. 1 (ED. 12-90) Page 327.14
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANASpanish Fork Wind Park 2, LLC AD 1
NANANASpanish Fork Wind Park 2, LLC LU 2
0.30.60.532Sprague Hydro LLC LU 3
NANANASt. Anthony Hydro, LLC AD 4
NANANASt. Anthony Hydro, LLC LU 5
NANANAStahlbush Island Farms, Inc. IU 6
NANA0.962SunE DB 24, LLC AD 7
NANA2.724SunE DB 24, LLC LU 8
4.85.32.8SunE DB18, LLC LU 9
12.82.7SunE Solar XVII Project1, LLC LU 10
1.12.82.8SunE Solar XVII Project2, LLC LU 11
1.22.82.8SunE Solar XVII Project3, LLC LU 12
485350Sunnyside Cogeneration Associates LU 13
NANANASurprise Valley Electrification Corp. LU 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 / /2016/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.
236,271 236,271 1
2,701,645 2,701,645 2 48,248
56,838 482,870 539,708 3 3,636
-1 -1 4
309,130 309,130 5 5,180
18,512 18,512 6 1,051
8,612 8,612 7 173
132,553 224,318 356,871 8 6,988
390,986 326,420 717,406 9 7,270
373,168 313,395 686,563 10 6,980
378,866 325,122 703,988 11 7,241
194,018 228,870 422,888 12 7,130
10,632,743 16,869,047 27,501,790 13 400,996
85,147 85,147 14 1,873
FERC FORM NO. 1 (ED. 12-90) Page 327.15
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
NANANASwalley Irrigation District LU 1
NANANATMF Biofuels, LLC LU 2
NANANATacoma Power SF 3
NANANATalen Energy Marketing, LLC OS 4
NANANATalen Energy Marketing, LLC SF 5
NANANATata Chemicals (Soda Ash) Partners LU 6
NANANATenaska Power Services Co. AD 7
NANANATenaska Power Services Co. SF 8
NANANATesoro Refining & Marketing Co, LLC AD 9
NANANATesoro Refining & Marketing Co, LLC LU 10
NANANAThayn Hydro LLC LU 11
NANANAThe Confederated Tribe of Warm Springs LU 12
NANANAThe Energy Authority, Inc. SF 13
NANANAThree Buttes Windpower, LLC LU 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 / /2016/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.
173,807 173,807 1 2,304
1,101,501 1,101,501 2 15,462
3,961,023 2,110 3,963,133 3 172,108
12,260 12,260 4 400
1,225,812 1,225,812 5 67,941
122,543 122,543 6 3,839
-2,096 -2,096 7 -95
317,252 317,252 8 14,477
338 338 9
476,230 476,230 10 19,573
93,461 93,461 11 2,477
7,589 7,589 12 331
1,581,981 1,581,981 13 74,313
21,250,160 21,250,160 14 333,872
FERC FORM NO. 1 (ED. 12-90) Page 327.16
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
NANANAThree Peaks Power, LLC LU 1
NANANAThree Sisters Irrigation District LU 2
NANANAThreemile Canyon Wind I, LLC LU 3
NANANATooele Army Depot LU 4
NANANATop of The World Wind Energy LLC LU 5
NANANATransAlta Energy Marketing (U.S.) Inc. AD 6
NANANATransAlta Energy Marketing (U.S.) Inc. SF 7
142525Tri-State Generation and Transmission LF 8
NANANATri-State Generation and Transmission SF 9
NANANATucson Electric Power Company SF 10
NANANATurlock Irrigation District SF 11
NANANAU.S. Dept of the Interior LU 12
NANANAUNS Electric, Inc. SF 13
NANANAUS Magnesium LLC LF 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 / /2016/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.
235,041 235,041 1 8,842
131,789 131,789 2 2,601
1,547,751 1,547,751 3 20,700
4,890 4,890 4 176
42,967,632 42,967,632 5 651,049
-10,388 -10,388 6 -375
11,103,278 11,103,278 7 410,510
5,940,000 3,054,013 8,994,013 8 96,250
122,745 4,973 127,718 9 5,693
778,461 1,082 779,543 10 30,559
6,468 6,468 11 580
1,841 1,841 12 29
22,552 22,552 13 984
6,706,025 6,706,025 14
FERC FORM NO. 1 (ED. 12-90) Page 327.17
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
NANANAUnited States Air Force at Hill Base LU 1
NANANAUtah Municipal Power Agency IU 2
NANANAUtah Red Hills Renewable Park, LLC AD 3
NANANAUtah Red Hills Renewable Park, LLC LU 4
NANANAVitol Inc. SF 5
NANANAWagon Trail, LLC LU 6
NANANAWard Butte Windfarm, LLC LU 7
0.1450.50.5Wasatch Integrated Waste Mgmt District LU 8
NANANAWeber County LU 9
NANANAWestern Area Power Administration LF 10
NANANAWestern Area Power Administration SF 11
NANANAWolverine Creek Energy, LLC LU 12
11.20.8Yakima-Tieton Irrigation District LU 13
NANANACA Greenhouse Gas Allowance Purchases 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 / /2016/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.
831,197 831,197 1 16,345
5,240,854 5,240,854 2 87,508
-5,986 -5,986 3
5,013,087 5,013,087 4 208,081
3,508,160 3,508,160 5 161,800
450,665 450,665 6 6,129
1,237,574 1,237,574 7 16,909
69,403 80,804 150,207 8 1,800
142,081 142,081 9 2,691
399,965 399,965 10 14,229
472,572 90,986 563,558 11 26,511
10,243,985 10,243,985 12 174,814
24,126 241,446 265,572 13 7,171
5,857,872 5,857,872 14
FERC FORM NO. 1 (ED. 12-90) Page 327.18
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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.
NANANASettlement/Reserves 1
NANANANetting - Trading 2
NANANARegulatory Energy Cost Deferrals 3
NANANANetting - Bookouts 4
NANANAAccrual 5
6
Power Exchanges: 7
NANANAArizona Public Service Company 307EX 8
NANANAAvista Corporation T-13EX 9
NANANABonneville Power Administration 237AD 10
NANANABonneville Power Administration T-12AD 11
NANANABonneville Power Administration 237EX 12
NANANABonneville Power Administration 519EX 13
NANANABonneville Power Administration T-12EX 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 / /2016/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.
-207,000 -207,000 1
-657,254 -657,254 2
80,815,989 80,815,989 3
-143,519,619 -143,519,619 4 -6,130,887
2,119,910 2,119,910 5 11
6
7
570,837 568,701 35,804 35,804 8
1,617 9
109,709 77,775 -3,329,833 -3,329,833 10
-245 -4,964 -4,964 11
19,696 -49,014 -49,014 12
100,567 102,766 95,026 95,026 13
7,181 244,744 244,744 14
FERC FORM NO. 1 (ED. 12-90) Page 327.19
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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 T-13EX 1
NANANACalifornia Independent System Operator T-11AD 2
NANANACalifornia Independent System Operator T-12AD 3
NANANACalifornia Independent System Operator T-11EX 4
NANANACalifornia Independent System Operator T-12EX 5
NANANAEmerald People's Utility District 351EX 6
NANANAEugene Water & Electric Board T-12EX 7
NANANAIdaho Power Company 380EX 8
NANANALos Angeles Dept. of Water and Power OV-1EX 9
NANANAMilford Wind Corridor Phase I, LLC OV-1EX 10
NANANAMilford Wind Corridor Phase II, LLC OV-1EX 11
NANANANorthWestern Corporation 160EX 12
NANANAPortland General Electric Company T-13EX 13
NANANAPublic Service Company of Colorado 319EX 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 / /2016/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.
9,838 208,026 1
-4,973,694 -4,973,694 2
4,708,910 4,708,910 3
-8,685,215 -8,685,215 4
2,377,735 1,435,283 -35,540,037 -35,540,037 5
811 -20,280 -20,280 6
19,917 20,699 22,420 22,420 7
123,128 154,800 8
4,406 253,691 253,691 9
2,852 -163,534 -163,534 10
1,554 -90,157 -90,157 11
1,635 12
62,388 13
3,612 14
FERC FORM NO. 1 (ED. 12-90) Page 327.20
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 / /2016/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 334EX 1
NANANAPUD No. 1 of Cowlitz County 442EX 2
NANANASeattle City Light T-12EX 3
NANANATri-State Generation and Transmission 319EX 4
NANANAWarm Springs Power Enterprises T-11EX 5
NANANAWestern Area Power Administration LAS-4AD 6
NANANAWestern Area Power Administration LAS-4EX 7
NANANAImbalance Energy Accrual T-11EX 8
NANANASystem Deviation NA 9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 326.21
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2016/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.
1,313,423 1,316,838 5,400,000 5,400,000 1
265,085 242,716 2
373,339 369,067 103,050 103,050 3
3,590 4
2,823 7,619 99,795 99,795 5
10,671 886 -229,511 -229,511 6
16,244 2,003 -294,619 -294,619 7
899,529 1,310,135 6,207,773 6,207,773 8
9 -18,266
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 327.21
11,939,781 5,901,498 6,217,758 57,516,408 566,302,353 -43,529,116 580,289,645
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 renewable portfolio standard
requirements.
Schedule Page: 326 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 326 Line No.: 4 Column: l
Settlement adjustment.
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: b
Settlement adjustment.
Schedule Page: 326 Line No.: 8 Column: l
Settlement adjustment.
Schedule Page: 326 Line No.: 10 Column: l
Reserve share.
Schedule Page: 326 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326 Line No.: 13 Column: l
Settlement adjustment.
Schedule Page: 326.1 Line No.: 2 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.1 Line No.: 6 Column: l
Non-generation agreement.
Schedule Page: 326.1 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.1 Line No.: 7 Column: l
Settlement adjustment.
Schedule Page: 326.1 Line No.: 9 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.: 11 Column: b
Bonneville Power Administration - contract termination date: 30 days written notice.
Schedule Page: 326.1 Line No.: 11 Column: l
Ancillary services.
Schedule Page: 326.1 Line No.: 12 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.1 Line No.: 12 Column: l
Ancillary services.
Schedule Page: 326.1 Line No.: 13 Column: l
Reserve share.
Schedule Page: 326.2 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.2 Line No.: 3 Column: l
Settlement adjustment.
Schedule Page: 326.2 Line No.: 10 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.: 10 Column: b
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Settlement adjustment.
Schedule Page: 326.2 Line No.: 10 Column: l
Settlement adjustment.
Schedule Page: 326.3 Line No.: 9 Column: b
City of Hurricane - contract termination date: August 31, 2017.
Schedule Page: 326.3 Line No.: 11 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: 326.4 Line No.: 7 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.: 7 Column: b
Deseret Generation and Transmission Co-operative - contract termination date: September
30, 2024.
Schedule Page: 326.4 Line No.: 7 Column: l
Reimbursement to counterparty for operation and maintenance costs at coal fired generating
facility located in Vernal, Utah.
Schedule Page: 326.5 Line No.: 1 Column: l
Line loss.
Schedule Page: 326.5 Line No.: 2 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.5 Line No.: 2 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.
Schedule Page: 326.5 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.5 Line No.: 7 Column: l
Settlement adjustment.
Schedule Page: 326.5 Line No.: 14 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.6 Line No.: 2 Column: b
Flathead Electric Cooperative, Inc. - contract termination date: September 30, 2016.
Schedule Page: 326.6 Line No.: 2 Column: l
Line loss.
Schedule Page: 326.6 Line No.: 10 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.6 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.6 Line No.: 12 Column: l
Settlement adjustment.
Schedule Page: 326.7 Line No.: 1 Column: l
Reserve share.
Schedule Page: 326.7 Line No.: 4 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 403.2 in this Form No. 1 for
further information on the Hermiston Generating Plant.
Schedule Page: 326.7 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 326.7 Line No.: 4 Column: l
On peak incentive, supplemental dispatch efficiency expense, start-up charges and
committee settlements.
Schedule Page: 326.7 Line No.: 5 Column: l
On peak incentive, supplemental dispatch efficiency expense, start-up charges and
committee settlements.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 326.7 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.7 Line No.: 6 Column: l
Labor, equipment and administration fees associated with hydro project in Idaho Falls,
Idaho.
Schedule Page: 326.7 Line No.: 7 Column: l
Labor, equipment and administration fees associated with hydro project in Idaho Falls,
Idaho.
Schedule Page: 326.7 Line No.: 8 Column: l
Reserve share.
Schedule Page: 326.7 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.7 Line No.: 14 Column: l
Settlement adjustment.
Schedule Page: 326.8 Line No.: 3 Column: l
Fixed annual payment.
Schedule Page: 326.8 Line No.: 6 Column: a
This footnote applies to all occurrences of "Los Angeles Dept. of Water and Power" on
pages 326-327. Complete name is Los Angeles Department of Water and Power.
Schedule Page: 326.9 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 326.9 Line No.: 2 Column: l
Compensation for interruptible service and operating reserves.
Schedule Page: 326.9 Line No.: 3 Column: l
Compensation for interruptible service and operating reserves.
Schedule Page: 326.9 Line No.: 4 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.9 Line No.: 10 Column: a
This footnote applies to all occurrences of "Nevada Power Company" on pages 326-327.
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: 326.9 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.9 Line No.: 10 Column: l
Settlement adjustment.
Schedule Page: 326.9 Line No.: 11 Column: l
Line loss.
Schedule Page: 326.9 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.9 Line No.: 12 Column: l
Settlement adjustment.
Schedule Page: 326.10 Line No.: 2 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.10 Line No.: 3 Column: l
Reserve share.
Schedule Page: 326.10 Line No.: 4 Column: l
Ancillary services.
Schedule Page: 326.11 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.11 Line No.: 6 Column: l
Line loss.
Schedule Page: 326.11 Line No.: 7 Column: l
Line loss.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 326.11 Line No.: 8 Column: b
Settlement adjustment.
Schedule Page: 326.11 Line No.: 8 Column: l
Operation expense plus amortization of unrecovered costs of Cove Project.
Schedule Page: 326.11 Line No.: 9 Column: b
Portland General Electric Company - contract termination date: Round Butte project no
longer operating for power production purposes.
Schedule Page: 326.11 Line No.: 9 Column: l
Operation expense plus amortization of unrecovered costs of Cove Project.
Schedule Page: 326.11 Line No.: 10 Column: l
Reserve share.
Schedule Page: 326.11 Line No.: 13 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.12 Line No.: 1 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.12 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.12 Line No.: 3 Column: l
Settlement adjustment.
Schedule Page: 326.12 Line No.: 4 Column: l
Line loss.
Schedule Page: 326.12 Line No.: 5 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: 326.12 Line No.: 5 Column: l
Reserve share.
Schedule Page: 326.12 Line No.: 6 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: 326.12 Line No.: 7 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: 326.12 Line No.: 7 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.12 Line No.: 7 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.12 Line No.: 8 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: 326.12 Line No.: 8 Column: b
Public Utility District No. 1 of Douglas County - contract termination date: August 31,
2018.
Schedule Page: 326.12 Line No.: 9 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.12 Line No.: 10 Column: l
Reserve share.
Schedule Page: 326.12 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.
Schedule Page: 326.12 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: 326.12 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 326.12 Line No.: 12 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.12 Line No.: 13 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.12 Line No.: 14 Column: l
Reserve share.
Schedule Page: 326.13 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 326.13 Line No.: 1 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.
Schedule Page: 326.13 Line No.: 2 Column: l
Reserve share.
Schedule Page: 326.13 Line No.: 6 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.13 Line No.: 6 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.
Schedule Page: 326.13 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.13 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.13 Line No.: 13 Column: l
Settlement adjustment.
Schedule Page: 326.14 Line No.: 1 Column: l
Line loss.
Schedule Page: 326.14 Line No.: 4 Column: l
Reserve share.
Schedule Page: 326.14 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.14 Line No.: 6 Column: l
Settlement adjustment.
Schedule Page: 326.14 Line No.: 9 Column: a
This footnote applies to all occurrences of "Sierra Pacific Power Company" on pages
326-327. 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: 326.14 Line No.: 9 Column: l
Reserve share.
Schedule Page: 326.14 Line No.: 12 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: 326.14 Line No.: 12 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.14 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.14 Line No.: 13 Column: l
Settlement adjustment.
Schedule Page: 326.15 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 326.15 Line No.: 1 Column: l
Settlement adjustment.
Schedule Page: 326.15 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Schedule Page: 326.15 Line No.: 4 Column: l
Settlement adjustment.
Schedule Page: 326.15 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.15 Line No.: 7 Column: l
Settlement adjustment.
Schedule Page: 326.16 Line No.: 3 Column: l
Reserve share.
Schedule Page: 326.16 Line No.: 4 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.16 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.16 Line No.: 7 Column: l
Settlement adjustment.
Schedule Page: 326.16 Line No.: 9 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: 326.16 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326.16 Line No.: 9 Column: l
Settlement adjustment.
Schedule Page: 326.16 Line No.: 12 Column: 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: 326.17 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.17 Line No.: 6 Column: l
Settlement adjustment.
Schedule Page: 326.17 Line No.: 8 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: 326.17 Line No.: 8 Column: b
Tri-State Generation and Transmission Association, Inc. - contract termination date:
December 31, 2020.
Schedule Page: 326.17 Line No.: 9 Column: l
Line loss.
Schedule Page: 326.17 Line No.: 10 Column: l
Line loss.
Schedule Page: 326.17 Line No.: 12 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: 326.17 Line No.: 14 Column: b
US Magnesium LLC - contract termination date: December 31, 2017.
Schedule Page: 326.17 Line No.: 14 Column: l
Ancillary services.
Schedule Page: 326.18 Line No.: 1 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: 326.18 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.18 Line No.: 3 Column: l
Settlement adjustment.
Schedule Page: 326.18 Line No.: 8 Column: a
This footnote applies to all occurrences of "Wasatch Integrated Waste Mgmt District" on
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
pages 326-327. Complete name is Wasatch Integrated Waste Management District.
Schedule Page: 326.18 Line No.: 10 Column: b
Western Area Power Administration - contract termination date: May 31, 2022.
Schedule Page: 326.18 Line No.: 10 Column: l
Line loss.
Schedule Page: 326.18 Line No.: 11 Column: l
Reserve share.
Schedule Page: 326.18 Line No.: 14 Column: l
Purchases of greenhouse gas allowances for compliance with the California Air Resources
Board greenhouse gas cap-and-trade program.
Schedule Page: 326.19 Line No.: 1 Column: l
Settlement associated with insufficient line loss compensation in past.
Schedule Page: 326.19 Line No.: 2 Column: l
Reflects transactions that did not physically settle.
Schedule Page: 326.19 Line No.: 3 Column: l
Deferrals and associated amortization under various energy cost adjustment mechanisms.
Schedule Page: 326.19 Line No.: 4 Column: l
Reflects transactions that did not physically settle.
Schedule Page: 326.19 Line No.: 5 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: 326.19 Line No.: 8 Column: l
Exchange energy expense.
Schedule Page: 326.19 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.19 Line No.: 10 Column: l
Storage and exchange charges.
Schedule Page: 326.19 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 326.19 Line No.: 11 Column: l
Storage and exchange charges.
Schedule Page: 326.19 Line No.: 12 Column: l
Storage and exchange charges.
Schedule Page: 326.19 Line No.: 13 Column: l
Storage and exchange charges.
Schedule Page: 326.19 Line No.: 14 Column: l
Storage and exchange charges.
Schedule Page: 326.20 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 326.20 Line No.: 2 Column: l
Energy Imbalance Market ("EIM") entity settlements in EIM.
Schedule Page: 326.20 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.20 Line No.: 3 Column: l
EIM participating resource settlements in EIM.
Schedule Page: 326.20 Line No.: 4 Column: l
EIM entity settlements in EIM.
Schedule Page: 326.20 Line No.: 5 Column: l
EIM participating resource settlements in EIM.
Schedule Page: 326.20 Line No.: 6 Column: l
Storage and exchange charges.
Schedule Page: 326.20 Line No.: 7 Column: l
Exchange energy expense.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
Schedule Page: 326.20 Line No.: 9 Column: l
Station service for third-party wind project.
Schedule Page: 326.20 Line No.: 10 Column: l
Reimbursement for providing station service to third-party wind project.
Schedule Page: 326.20 Line No.: 11 Column: l
Reimbursement for providing station service to third-party wind project.
Schedule Page: 326.21 Line No.: 1 Column: l
Storage and exchange charges.
Schedule Page: 326.21 Line No.: 3 Column: l
Exchange energy expense.
Schedule Page: 326.21 Line No.: 5 Column: l
Imbalance energy.
Schedule Page: 326.21 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.21 Line No.: 6 Column: l
Imbalance energy.
Schedule Page: 326.21 Line No.: 7 Column: l
Imbalance energy.
Schedule Page: 326.21 Line No.: 8 Column: l
Allocations of EIM charge codes to transmission customers.
Schedule Page: 326.21 Line No.: 9 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
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 / /2016/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
Avangrid Renewables, LLC NF 2
Avangrid Renewables, LLC AD 3
Avangrid Renewables, LLC SFP 4
Avangrid Renewables, LLC AD 5
Avangrid Renewables, LLC Avangrid Renewables, LLC OS 6
Avangrid Renewables, LLC Avangrid Renewables, LLC AD 7
Avangrid Renewables, LLC Exxon Mobil Nevada Power Company LFP 8
Avangrid Renewables, LLC Exxon Mobil Nevada Power Company AD 9
Avangrid Renewables, LLC Bonneville Power Administration Oregon Direct Access FNO 10
Avangrid Renewables, LLC Avangrid Renewables, LLC AD 11
Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation FNO 12
Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation AD 13
Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation LFP 14
Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation NF 15
Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation AD 16
Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation SFP 17
Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation AD 18
Black Hills/Colorado Electric Utility Company NF 19
Black Hills/Colorado Electric Utility Company SFP 20
Black Hills Corporation PacifiCorp Montana-Dakota Utilities FNO 21
Black Hills Corporation PacifiCorp Montana-Dakota Utilities AD 22
Black Hills Corporation PacifiCorp Black Hills Corporation LFP 23
Black Hills Corporation PacifiCorp Black Hills Corporation AD 24
Black Hills Corporation NF 25
Black Hills Corporation SFP 26
Black Hills Power, Inc.NF 27
Black Hills Power Marketing AD 28
Black Hills Power, Inc.SFP 29
Black Hills Power Marketing AD 30
Bonneville Power Administration OS 31
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 32
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 33
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration LFP 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 / /2016/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
VariousV11-1-3,8 Various 181,395 181,395 2
VariousV11-1-3,8 Various 21,234 21,234 3
VariousV11-1-3,7 Various 33,311 33,311 4
VariousV11-1-3,7 Various 8,937 8,937 5
V11-5,6 6
V11-5,6 7
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 31 65,938 65,938 8
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 31 8,190 8,190 9
Ponderosa SubstationV11-1-3,5,6 Various 14 124,645 124,645 10
Ponderosa SubstationV11-1-3,5,6 Various 12 8,639 8,639 11
Yellowtail SubV11-1,2,3 Sheridan Substation 10 68,871 68,871 12
Yellowtail SubV11-1,2,3 Sheridan Substation 360 360 13
Dave Johnston SubV11-1,2,3 Yellowtail Sub 85,100 85,100 14
VariousV11-1,2,8 Various 14,682 14,682 15
VariousV11-1,2,8 Various 213 213 16
VariousV11-1,2,7 Various 342 342 17
VariousV11-1,2,7 Various 15,561 15,561 18
VariousV11-1,2,8 Various 79 79 19
VariousV11-1,2,7 Various 75 75 20
VariousV11-1,2 Sheridan Substation 44 21
VariousV11-1,2 Sheridan Substation 45 22
VariousV11-1,2,7 Wyodak Substation 52 134,331 134,331 23
VariousV11-1,2,7 Wyodak Substation 52 3,764 3,764 24
VariousV11-1,2,8 Various 4,778 4,778 25
VariousV11-1,2,7 Various 159 159 26
VariousV11-1,2,8 Various 502 502 27
VariousV11-1,2,8 Various 82 82 28
VariousV11-1,2,7 Various 377 377 29
VariousV11-1,2,7 Various 30
Midpoint SubstationR.S. 369 Summer Lake Sub 31
VariousR.S. 237 Various 383 978,598 978,598 32
VariousR.S. 237 Various 382 93,545 93,545 33
Lost Creek Hydro PltV11-2,7 Alvey Substation 58 209,683 209,683 34
FERC FORM NO. 1 (ED. 12-90) Page 329
4,773 13,233,893 13,121,145
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 / /2016/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
1,731,007 201,310 1,529,697 2
145,214 145,214 3
486,555 56,835 429,720 4
56,507 56,507 5
236,946 236,946 6
29,693 29,693 7
837,116 874,071 36,955 8
87,738 87,738 9
260,183 389,449 129,266 10
35,458 35,458 11
258,766 312,726 53,960 12
1,679 1,679 13
669,693 765,896 96,203 14
76,401 3,241 73,160 15
1,775 1,775 16
1,833 78 1,755 17
62,101 62,101 18
303 76 227 19
169 -3 172 20
1,150,579 1,201,389 50,810 21
124,070 124,070 22
1,391,699 1,453,292 61,593 23
146,229 146,229 24
10,963 473 10,490 25
5,919 3,320 2,599 26
1,854 64 1,790 27
7,555 7,555 28
4,539 3,753 786 29
215 215 30
31
4,072,175 4,140,122 67,947 32
407,528 407,528 33
1,562,618 1,578,427 15,809 34
FERC FORM NO. 1 (ED. 12-90) Page 330
54,874,768 100,653,551 38,096,280 7,682,503
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 / /2016/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying
facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 1
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative FNO 2
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative AD 3
Bonneville Power Administration Bonneville Power Administration Benton REA FNO 4
Bonneville Power Administration Bonneville Power Administration Benton REA AD 5
Bonneville Power Administration Bonneville Power Administration Umatilla Electric and Columbia FNO 6
Bonneville Power Administration Bonneville Power Administration Umatilla Electric and Columbia AD 7
Bonneville Power Administration U. S. Bureau of Reclamation Bonneville Power Administration LFP 8
Bonneville Power Administration U. S. Bureau of Reclamation Bonneville Power Administration AD 9
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 10
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 11
Bonneville Power Administration Bonneville Power Administration Yakama Power FNO 12
Bonneville Power Administration Bonneville Power Administration Yakama Power AD 13
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 14
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 15
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO 16
Bonneville Power Administration NF 17
Bonneville Power Administration FNO 18
Bonneville Power Administration Bonneville Power Administration Clark Public Utilities FNO 19
Bonneville Power Administration Bonneville Power Administration Clark Public Utilities AD 20
Brookfield Energy Marketing LP NF 21
Calpine Energy Solutions LLC Bonneville Power Administration Oregon Direct Access FNO 22
Calpine Energy Solutions LLC Bonneville Power Administration Oregon Direct Access AD 23
Cargill Power Markets, LLC NF 24
Cargill Power Markets, LLC AD 25
City of Anaheim NF 26
City of Anaheim SFP 27
Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration OS 28
Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration AD 29
Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans.OS 30
Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans.AD 31
Deseret Generation & Trans.NF 32
Deseret Generation & Trans.AD 33
Deseret Generation & Trans.SFP 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 / /2016/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.
Lost Creek Hydro PltV11-2,7 Alvey Substation 58 17,535 17,535 1
Bonneville Power AdmV11-1-3,5,6 Gazley Substation 3 22,870 22,870 2
Bonneville Power AdmV11-1-3,5,6 Gazley Substation 3 2,128 2,128 3
Bonneville Power AdmV11-1-3,5,6 Tieton Substation 1 4,830 4,830 4
Bonneville Power AdmV11-1-3,5,6 Tieton Substation 1 762 762 5
McNary SubstationV11-1-3,5,6 Hinkle Substation 1 873 873 6
McNary SubstationV11-1-3,5,6 Hinkle Substation 1 101 101 7
USBR Green SpringsV11-2,7 Bonneville Power Adm 19 49,850 49,850 8
USBR Green SpringsV11-2,7 Bonneville Power Adm 19 9
Malin SubstationR.S. 368 Malin Substation 618,238 618,238 10
Malin SubstationR.S. 368 Malin Substation 59,367 59,367 11
Bonneville Power AdmV11-1-3,5,6 6 36,026 36,026 12
Bonneville Power AdmV11-1-3,5,6 5 3,402 3,402 13
VariousR.S. 299 Various 68 456,782 456,782 14
VariousR.S. 299 Various 156 84,467 84,467 15
GoshenS.A. 746 Various 515,326 515,326 16
VariousV11-1,2,8 Various 82 82 17
GoshenS.A. 747 Various 175,926 175,926 18
Cardwell-MerwinV11-1-3,5,6 18 101,470 101,470 19
Cardwell-MerwinV11-1-3,5,6 25 14,424 14,424 20
VariousV11-1,2,8 Various 11,053 11,053 21
Bonneville Power AdmV11-1-3,5,6 Various 22 159,520 159,520 22
Bonneville Power AdmV11-1-3,5,6 Various 16 11,666 11,666 23
VariousV11-1,2,8 Various 19,764 19,764 24
VariousV11-1,2,8 Various 529 529 25
VariousV11-1,2,8 Various 46,155 46,155 26
VariousV11-1,2,7 Various 17 17 27
Swift Unit No. 2R.S. 234 Woodland Substation 28
Swift Unit No. 2R.S. 234 Woodland Substation 29
VariousR.S. 280 Various 91 599,812 599,812 30
VariousR.S. 280 Various 101 53,416 53,416 31
VariousV11-1,2,8 Various 16,105 16,105 32
VariousV11-1,2,8 Various 66 66 33
VariousV11-1,2,7 Various 213 213 34
FERC FORM NO. 1 (ED. 12-90) Page 329.1
4,773 13,233,893 13,121,145
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 / /2016/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.
161,215 161,215 1
86,963 248,933 161,970 2
23,977 23,977 3
15,974 21,596 5,622 4
4,951 4,951 5
2,536 3,584 1,048 6
1,725 1,725 7
502,269 509,574 7,305 8
50,662 50,662 9
232,452 232,452 10
2,687 2,687 11
153,122 286,589 133,467 12
25,611 25,611 13
432,167 991,025 558,858 14
168,726 168,726 15
2,139,486 2,674,258 534,772 16
97,567 4,092 93,475 17
819,311 1,018,121 198,810 18
431,691 561,551 129,860 19
84,011 84,011 20
67,277 2,844 64,433 21
341,767 508,495 166,728 22
43,773 43,773 23
153,290 6,425 146,865 24
3,576 3,576 25
328,445 13,863 314,582 26
173 7 166 27
152,267 152,267 28
13,795 13,795 29
2,413,640 4,170,265 1,756,625 30
350,907 350,907 31
105,249 4,447 100,802 32
457 457 33
790 34 756 34
FERC FORM NO. 1 (ED. 12-90) Page 330.1
54,874,768 100,653,551 38,096,280 7,682,503
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 / /2016/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.
Eugene Water & Electric Board LFP 1
Eugene Water & Electric Board AD 2
Eugene Water & Electric Board SFP 3
Eugene Water & Electric Board AD 4
Enel Cove Fort, LLC Enel Cove Fort, LLC AD 5
Exelon Generation Company, LLC Bonneville Power Administration Oregon Direct Access FNO 6
Exelon Generation Company, LLC Bonneville Power Administration Oregon Direct Access AD 7
Exelon Generation Company, LLC NF 8
Exelon Generation Company, LLC AD 9
Exelon Generation Company, LLC SFP 10
Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company OS 11
Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company AD 12
Foote Creek III, LLC Foote Creek III, LLC PacifiCorp OS 13
Foote Creek III, LLC Foote Creek III, LLC PacifiCorp AD 14
Idaho Power Company OS 15
Idaho Power Company AD 16
Idaho Power Company NF 17
Los Angeles Department of Water & Power SFP 18
Macquarie Energy, LLC NF 19
Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association OS 20
Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association AD 21
Morgan Stanley Capital Group, Inc.NF 22
Morgan Stanley Capital Group, Inc.AD 23
Morgan Stanley Capital Group, Inc.SFP 24
Municipal Energy Nebraska, Inc.NF 25
Nevada Power Company NF 26
NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD LFP 27
NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD AD 28
NextEra Energy Resources, LLC NF 29
NextEra Energy Resources, LLC AD 30
NextEra Energy Resources, LLC SFP 31
NextEra Energy Resources, LLC AD 32
Olene KBG, LLC Exxon Mobil Nevada Power Company LFP 33
Pacific Gas & Electric Company OS 34
FERC FORM NO. 1 (ED. 12-90) Page 328.2
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2016/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
VariousV11-1,2,7 Various 1
VariousV11-1,2,7 Various 2
VariousV11-1,2,7 Various 3
VariousV11-1,2,7 Various 4
Enel Cove FortV11-1-3,7 Red Butte Substation 5
Bonneville Power AdmV11-1-3,5,6 Various 2 8,558 8,558 6
Bonneville Power AdmV11-1-3,5,6 Various 2 1,682 1,682 7
VariousV11-1-3,5,6,8 Various 9,257 9,257 8
VariousV11-1-3,5,6,8 Various 118 118 9
VariousV11-1-3,7 Various 10
Targhee SubstationR.S. 322 Goshen Substation 11
Targhee SubstationR.S. 322 Goshen Substation 12
Foote Creek SubS.A. 761 Various 13
Foote Creek SubS.A. 761 Various 14
Antelope SubstationR.S. 257 Antelope Substation 7,006 7,006 15
Trona SubstationS.A. 212 Red Butte/Mona Sub 16
VariousV11-1,2,8 Various 17,699 17,699 17
VariousV11-1,2,7 Various 3,624 3,624 18
VariousV11-1,2,8 Various 74 74 19
DuchesneR.S. 302 Duchesne 19,638 19,638 20
DuchesneR.S. 302 Duchesne 1,984 1,984 21
VariousV11-1-3,8 Various 108,657 108,657 22
VariousV11-1-3,8 Various 13,701 13,701 23
VariousV11-1-3,7 Various 366 366 24
VariousV11-1,2,8 Various 156 156 25
VariousV11-1,2,8 Various 4,085 4,085 26
Wallula SubstationV11-1-3,5-7 Wala-MIDC path 103 163,687 163,687 27
Wallula SubstationV11-5-7 Wala-MIDC path 103 19,065 19,065 28
VariousV11-1-3,8 Various 5,563 5,563 29
VariousV11-1,2,8 Various 232 232 30
VariousV11-1-3,7 Various 368 368 31
VariousV11-1,2,7 Various 7 7 32
PGEV11-1,2,7 Olene KBG, LLC 33
R.S. 607 34
FERC FORM NO. 1 (ED. 12-90) Page 329.2
4,773 13,233,893 13,121,145
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 / /2016/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.
595,577 595,577 1
84,417 84,417 2
202,479 202,479 3
64,571 64,571 4
-358 -358 5
28,577 41,129 12,552 6
9,185 9,185 7
233,943 63,777 170,166 8
22,536 22,536 9
1,080 62 1,018 10
138,699 138,699 11
12,609 12,609 12
63,869 63,869 13
8,024 8,024 14
969,535 1,012,383 42,848 15
-15,133 -15,133 16
103,108 4,357 98,751 17
32,210 1,360 30,850 18
374 16 358 19
17,655 17,655 20
1,605 1,605 21
581,971 24,556 557,415 22
79,237 79,237 23
95,093 4,014 91,079 24
2,571 108 2,463 25
31,211 710 30,501 26
1,819,267 2,197,505 378,238 27
259,107 259,107 28
247,823 29,786 218,037 29
24,252 24,252 30
1,601 111 1,490 31
25 25 32
748,841 781,869 33,028 33
13,486,345 13,486,345 34
FERC FORM NO. 1 (ED. 12-90) Page 330.2
54,874,768 100,653,551 38,096,280 7,682,503
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 / /2016/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 AD 1
Pacific Gas & Electric Company NF 2
Pacific Gas & Electric Company AD 3
PGE NF 4
PGE OS 5
Powder River Energy Corporation Western Area Power Administration Sheridan-Johnson Rural Elect.OS 6
Powder River Energy Corporation Western Area Power Administration Sheridan-Johnson Rural Elect.AD 7
Powerex Corporation Bonneville Power Administration CAISO LFP 8
Powerex Corporation Bonneville Power Administration CAISO AD 9
Powerex Corporation Powerex Corporation CAISO LFP 10
Powerex Corporation Powerex Corporation CAISO AD 11
Powerex Corporation Powerex Corporation CAISO LFP 12
Powerex Corporation Powerex Corporation CAISO AD 13
Powerex Corporation Powerex Corporation CAISO LFP 14
Powerex Corporation Powerex Corporation CAISO AD 15
Powerex Corporation Powerex Corporation CAISO LFP 16
Powerex Corporation Powerex Corporation CAISO AD 17
Powerex Corporation Powerex Corporation CAISO LFP 18
Powerex Corporation Powerex Corporation CAISO AD 19
Powerex Corporation NF 20
Powerex Corporation AD 21
Powerex Corporation SFP 22
Powerex Corporation AD 23
Puget Sound Power & Light Company SFP 24
Rainbow Energy Marketing Corporation NF 25
Sacramento Municipal Utility District Sacramento Municipal Utility Dist Sacramento Municipal Utility Dist LFP 26
Sacramento Municipal Utility District Sacramento Municipal Utility Dist Sacramento Municipal Utility Dist AD 27
Salt River Project Salt River Project Salt River Project LFP 28
Salt River Project Salt River Project Salt River Project AD 29
Shell Energy Corporation, Inc. NextEra Energy Resources, LLC Grant County PUD LFP 30
Shell Energy Corporation, Inc. NextEra Energy Resources, LLC Grant County PUD AD 31
Shell Energy Corporation, Inc.NF 32
Shell Energy Corporation, Inc.AD 33
Shell Energy Corporation, Inc.SFP 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 / /2016/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
VariousV11-1,2 Various 1
VariousV11-1,2,8 Various 1,794 1,794 2
VariousV11-1,2,8 Various 594 594 3
VariousV11-1,2,8 Various 90 90 4
VariousR.S. 137 Various 5
VariousR.S. 123 Buffalo Substation 6
VariousR.S. 123 Buffalo Substation 7
Bonneville Power AdmV11-1,2,7 CRAG View Substation 83 561,758 561,758 8
Bonneville Power AdmV11-1,2,7 CRAG View Substation 83 29,486 29,486 9
Malin 500 SubstationV11-1,7 Round Mountain Sub 67 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 66 14
Malin 500 SubstationV11-1,7 Round Mountain Sub 66 15
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 16
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 17
Malin 500 SubstationV11-1,7 Round Mountain Sub 150 18
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 19
VariousV11-1,2,8 Various 144,765 144,765 20
VariousV11-1,2,8 Various 14,192 14,192 21
VariousV11-1-3,7 Various 37,272 37,272 22
VariousV11-1,2,7 Various 330 330 23
VariousV11-1,2,8 Various 24
VariousV11-1,2,8 Various 5,026 5,026 25
Malin SubstationV11-1,2,7 Malin Substation 31 98,564 98,564 26
Malin SubstationV11-1,2,7 Malin Substation 31 16,272 16,272 27
Enel Cove FortV11-1,2,7 Red Butte Substation 26 152,353 152,353 28
Enel Cove FortV11-1,2,7 Red Butte Substation 26 15,221 15,221 29
Wallula SubstationV11-1,2,7 Wala-MIDC path 80,847 80,847 30
Wallula SubstationV11-1,2,7 Wala-MIDC path 11,216 11,216 31
VariousV11-1-3,8 Various 39,854 39,854 32
VariousV11-1,2,8 Various 2,388 2,388 33
VariousV11-1-3,7 Various 7,364 7,364 34
FERC FORM NO. 1 (ED. 12-90) Page 329.3
4,773 13,233,893 13,121,145
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 / /2016/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.
1,208,333 1,208,333 1
12,302 1,039 11,263 2
4,883 4,883 3
671 28 643 4
3,314 3,314 5
373 373 6
33 33 7
2,232,310 2,330,859 98,549 8
231,671 231,671 9
1,789,909 1,835,149 45,240 10
184,568 184,568 11
1,789,909 1,835,149 45,240 12
184,568 184,568 13
1,763,193 1,807,757 44,564 14
181,813 181,813 15
1,335,753 1,369,801 34,048 16
171,853 171,853 17
4,007,259 4,109,402 102,143 18
380,246 380,246 19
967,948 75,746 892,202 20
90,236 90,236 21
225,272 32,339 192,933 22
3,127 3,127 23
16 1 15 24
24,561 1,039 23,522 25
837,117 874,071 36,954 26
87,738 87,738 27
697,610 728,408 30,798 28
73,414 73,414 29
30
31
242,538 10,640 231,898 32
12,702 12,702 33
31,283 1,383 29,900 34
FERC FORM NO. 1 (ED. 12-90) Page 330.3
54,874,768 100,653,551 38,096,280 7,682,503
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 / /2016/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.
Sierra Pacific Power Company OS 1
Sierra Pacific Power Company AD 2
Southern California Edison Company NF 3
Southern California Edison Company AD 4
Southern California Public Power Authority Powerex Corporation Southern California Public Power NF 5
State of South Dakota Western Area Power Administration Black Hills Corporation LFP 6
State of South Dakota Western Area Power Administration Black Hills Corporation AD 7
Talen Energy Marketing, LLC NF 8
Talen Energy Marketing, LLC AD 9
Talen Energy Marketing, LLC SFP 10
Tenaska Power Services Co NF 11
Tenaska Power Services Co AD 12
Tenaska Power Services Co SFP 13
The Energy Authority, Inc.NF 14
The Energy Authority, Inc.SFP 15
Thermo No. 1 BE-01, LLC Thermo Geothermal Project LFP 16
Thermo No. 1 BE-01, LLC Thermo Geothermal Project AD 17
TransAlta Energy Marketing (U.S.) Inc.NF 18
TransAlta Energy Marketing (U.S.) Inc.AD 19
TransAlta Energy Marketing (U.S.) Inc.SFP 20
Tri-State Generation & Trans. Tri-State Generation & Trans.FNO 21
Tri-State Generation & Trans. Tri-State Generation & Trans.AD 22
Tri-State Generation & Trans.NF 23
U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation FNO 24
U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation AD 25
U.S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv.OS 26
U.S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv.AD 27
U.S. Bureau of Reclamation Bonneville Power Administration Crooked River Irrigation District OS 28
Utah Associated Municipal Power Systems Utah Associated Municipal Power Utah Associated Municipal Power OS 29
Utah Associated Municipal Power Systems Utah Associated Municipal Power Utah Associated Municipal Power AD 30
Utah Associated Municipal Power Systems NF 31
Utah Associated Municipal Power Systems SFP 32
Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency OS 33
Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency AD 34
FERC FORM NO. 1 (ED. 12-90) Page 328.4
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2016/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 SubstationR.S. 674 Utah-Nevada Border 1
Sigurd SubstationR.S. 674 Utah-Nevada Border 2
VariousV11-1-3,5,6,11 Various 228,388 228,388 3
VariousV11-1-3,5,6,11 Various 1,681 1,681 4
Tieton SubstationV11-1-3,11 Various 53 53 5
Yellowtail SubV11-1,2,7 Wyodak Substation 4 17,599 17,599 6
Yellowtail SubV11-1,2,7 Wyodak Substation 4 1,681 1,681 7
VariousV11-1,2,8 Various 2,983 2,983 8
VariousV11-1,2,8 Various 20 20 9
VariousV11-1,2,7 Various 24 24 10
VariousV11-1-3,8 Various 5,214 5,214 11
VariousV11-1-3,8 Various 179 179 12
VariousV11-1-3,7 Various 13
VariousV11-1,2,8 Various 3,051 3,051 14
VariousV11-1,2,7 Various 50 50 15
South Milford SubV11-1-3,5-7 Mona Substation 11 56,872 56,872 16
South Milford SubV11-1-3,5-7 Mona Substation 11 6,244 6,244 17
VariousV11-1,2,8 Various 9,276 9,276 18
VariousV11-1,2,8 Various 1,995 1,995 19
VariousV11-1,2,7 Various 25 25 20
Dave Johnston SubV11-1-3,5,6 Thermopolis Sub 14 99,837 99,837 21
Dave Johnston SubV11-1-4 Thermopolis Sub 30 17,167 17,167 22
VariousV11-1,2,8 Various 3,553 3,553 23
Walla Walla SubV11-1-3,5,6 Burbank Pumps 1 2,414 2,414 24
Walla Walla SubV11-1-3,5,6 Burbank Pumps 1 3 3 25
VariousR.S. 286 Various 26,893 26,893 26
VariousR.S. 286 Various 810 810 27
Redmond SubstationR.S. 67 Crooked River Pumps 10,882 10,882 28
VariousR.S. 297 Various 498 2,901,867 2,901,867 29
VariousR.S. 297 Various 442 268,070 268,070 30
VariousV11-1-3,8 Various 21,109 21,109 31
VariousV11-1-3,7 Various 10,270 10,270 32
VariousR.S. 637 Various 96 579,724 579,724 33
VariousR.S. 637 Various 81 48,354 48,354 34
FERC FORM NO. 1 (ED. 12-90) Page 329.4
4,773 13,233,893 13,121,145
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 / /2016/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.
53,256 53,256 1
6,265 6,265 2
2,664,919 703,323 1,961,596 3
332,642 332,642 4
13,883 13,883 5
111,615 116,542 4,927 6
11,714 11,714 7
26,535 1,118 25,417 8
71 71 9
187 8 179 10
28,891 1,220 27,671 11
1,268 1,268 12
3,277 417 2,860 13
19,867 837 19,030 14
186 8 178 15
306,956 392,039 85,083 16
39,922 39,922 17
53,341 2,252 51,089 18
10,861 10,861 19
178 8 170 20
361,583 486,340 124,757 21
114,250 114,250 22
30,749 1,295 29,454 23
9,066 23,072 14,006 24
52 52 25
26,894 26,894 26
810 810 27
10,563 10,563 28
13,556,941 16,114,983 2,558,042 29
1,364,058 1,364,058 30
130,961 16,380 114,581 31
42,680 5,435 37,245 32
2,586,597 2,997,100 410,503 33
230,382 230,382 34
FERC FORM NO. 1 (ED. 12-90) Page 330.4
54,874,768 100,653,551 38,096,280 7,682,503
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 / /2016/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.
Warm Springs Power Enterprises Warm Springs Power Enterprises PGE OS 1
Warm Springs Power Enterprises Warm Springs Power Enterprises PGE AD 2
Westar Energy, Inc.NF 3
Western Area Power Administration Western Area Power Administration OS 4
Western Area Power Administration Western Area Power Administration AD 5
Western Area Power Administration Western Area Power Administration OS 6
Western Area Power Administration Western Area Power Administration AD 7
Western Area Power Administration Western Area Power Administration OS 8
Western Area Power Administration Western Area Power Administration Western Area Power Administration FNO 9
Western Area Power Administration Western Area Power Adm CO River Western Area Power Administration AD 10
Western Area Power Adm CO River Western Area Power Adm CO River NF 11
Western Area Power Adm CO MO Western Area Power Adm CO River NF 12
Western Area Power Adm CO MO Western Area Power Adm CO River AD 13
Western Area Power Adm CO MO Western Area Power Adm CO MO SFP 14
Accrual 15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 328.5
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2016/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.
Pelton ReregulatingR.S. 591 Round Butte Sub 74,899 74,899 1
Pelton ReregulatingR.S. 591 Round Butte Sub 7,578 7,578 2
VariousV11-1,2,8 Various 3
VariousR.S. 262 Various 330 1,672,625 1,572,269 4
VariousR.S. 262 Various 330 172,791 162,424 5
VariousR.S. 263 Various 44,634 41,960 6
VariousR.S. 263 Various 4,111 3,863 7
Dave Johnston SubR.S. 684 Various 8
Wyoming DistributionV11-1,2 Wyoming Distribution 1 10,920 10,920 9
VariousV11-1,2,8 Wyoming Distribution 1 3 3 10
VariousV11-1,2,8 Various 291 291 11
VariousV11-1,2,8 Various 13,257 13,257 12
VariousV11-1,2,8 Various 13
VariousV11-1,2,7 Various 216 216 14
155,201 156,098 15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.5
4,773 13,233,893 13,121,145
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 / /2016/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.
109,725 109,725 1
9,975 9,975 2
7 7 3
2,339,411 2,889,411 550,000 4
266,003 266,003 5
40,266 40,266 6
4,048 4,048 7
8
31,001 66,472 35,471 9
5,570 5,570 10
2,971 125 2,846 11
55,474 2,347 53,127 12
7 7 13
1,121 47 1,074 14
4,775,935 4,775,935 15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.5
54,874,768 100,653,551 38,096,280 7,682,503
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: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 2 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 2 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 2 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328 Line No.: 3 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 3 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 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 Line No.: 3 Column: m
2015 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER11-3646.
Schedule Page: 328 Line No.: 4 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 4 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
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. Generation regulation and frequency response service.
Schedule Page: 328 Line No.: 5 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 5 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 5 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 5 Column: m
2015 transmission and ancillary services.
Schedule Page: 328 Line No.: 6 Column: c
Avangrid Renewables, LLC and Utah Associated Municipal Power Systems
Schedule Page: 328 Line No.: 6 Column: d
Ancillary services under the Open Access Transmission Tariff (1st Revised Service
Agreement 476) in effect until superseded.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 328 Line No.: 6 Column: f
Long Hollow, WY Switching Station
Schedule Page: 328 Line No.: 6 Column: g
Long Hollow, WY Switching Station
Schedule Page: 328 Line No.: 6 Column: m
Operating reserve - spinning reserve service. Operating reserve - supplemental reserve
service.
Schedule Page: 328 Line No.: 7 Column: c
Avangrid Renewables, LLC and Utah Associated Municipal Power Systems
Schedule Page: 328 Line No.: 7 Column: d
Ancillary services under the Open Access Transmission Tariff (1st Revised Service
Agreement 476) in effect until superseded.
Schedule Page: 328 Line No.: 7 Column: f
Long Hollow, WY Switching Station
Schedule Page: 328 Line No.: 7 Column: g
Long Hollow, WY Switching Station
Schedule Page: 328 Line No.: 7 Column: m
2015 transmission and ancillary services. 2015 annual transmission services true-up
refund.
Schedule Page: 328 Line No.: 8 Column: c
This footnote applies to all occurrences of "Nevada Power Company" on pages 328-330.
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: 328 Line No.: 8 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 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
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 279) terminating on April 30, 2019.
Schedule Page: 328 Line No.: 9 Column: m
2015 transmission and ancillary services. 2015 annual transmission services true-up
refund.
Schedule Page: 328 Line No.: 10 Column: d
Network transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 742) terminating no earlier than 12-months from notice by the customer.
Schedule Page: 328 Line No.: 10 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.: 11 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 11 Column: d
Network transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 742) terminating no earlier than 12-months from notice by the customer.
Schedule Page: 328 Line No.: 11 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328 Line No.: 12 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 505) terminating no earlier than 12-months from notice by the customer.
Schedule Page: 328 Line No.: 12 Column: m
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
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.: 13 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.: 13 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328 Line No.: 14 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 818) terminating on December 31, 2016.
Schedule Page: 328 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 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: 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
2015 transmission and ancillary services.
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
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.: 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
2015 transmission and ancillary services.
Schedule Page: 328 Line No.: 19 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.: 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
Transmission resale - purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 328 Line No.: 20 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 20 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 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 Line No.: 20 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 21 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.: 21 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 22 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.: 22 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328 Line No.: 23 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.: 23 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.: 24 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.: 24 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328 Line No.: 25 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 25 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 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 Line No.: 25 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 26 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 26 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 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 Line No.: 26 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 27 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 27 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 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 Line No.: 27 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.: 28 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 28 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 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 Line No.: 28 Column: m
2015 transmission and ancillary services.
Schedule Page: 328 Line No.: 29 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 29 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 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 Line No.: 29 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.: 30 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 30 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 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 Line No.: 30 Column: m
2015 transmission and ancillary services.
Schedule Page: 328 Line No.: 31 Column: b
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of energy.
Schedule Page: 328 Line No.: 31 Column: c
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of energy.
Schedule Page: 328 Line No.: 31 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.: 32 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
deliveries as defined in the agreement.
Schedule Page: 328 Line No.: 32 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. 2013-2015 transmission demand adjustments.
Schedule Page: 328 Line No.: 33 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.: 33 Column: m
2015 transmission and ancillary services.
Schedule Page: 328 Line No.: 34 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised
Service Agreement 656) terminating on August 31, 2030.
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. Reactive supply and voltage control service.
Schedule Page: 328.1 Line No.: 1 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised
Service Agreement 656) terminating on August 31, 2030.
Schedule Page: 328.1 Line No.: 1 Column: m
2015 transmission and ancillary services. 2015 annual transmission services true-up
refund.
Schedule Page: 328.1 Line No.: 2 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: 328.1 Line No.: 2 Column: f
This footnote applies to all occurrences of "Bonneville Power Adm" on pages 328-330.
Complete name is Bonneville Power Administration.
Schedule Page: 328.1 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. Operating reserve - spinning reserve service. Operating
reserve - supplemental reserve service.
Schedule Page: 328.1 Line No.: 3 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: 328.1 Line No.: 3 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.1 Line No.: 4 Column: c
This footnote applies to all occurrences of "Benton REA" on pages 328-330. Complete name
is Benton Rural Electric Association.
Schedule Page: 328.1 Line No.: 4 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: 328.1 Line No.: 4 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.: 5 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
Schedule Page: 328.1 Line No.: 5 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.1 Line No.: 6 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: 328.1 Line No.: 6 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 538) terminating on September 30, 2028.
Schedule Page: 328.1 Line No.: 6 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.: 7 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 538) terminating on September 30, 2028.
Schedule Page: 328.1 Line No.: 7 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.1 Line No.: 8 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: 328.1 Line No.: 8 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: 328.1 Line No.: 8 Column: m
Reactive supply and voltage control service.
Schedule Page: 328.1 Line No.: 9 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: 328.1 Line No.: 9 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.1 Line No.: 10 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: 328.1 Line No.: 10 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.: 11 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: 328.1 Line No.: 11 Column: m
2015 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 12 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (7th Revised Service Agreement 328) terminating on September 30, 2028.
Schedule Page: 328.1 Line No.: 12 Column: g
White Swan/Toppenish Substations
Schedule Page: 328.1 Line No.: 12 Column: m
Distribution voltage service charge. Primary delivery service. Scheduling, system control
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
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.: 13 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.: 13 Column: g
White Swan/Toppenish Substations
Schedule Page: 328.1 Line No.: 13 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.1 Line No.: 14 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.: 14 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.: 15 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.: 15 Column: m
2015 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 16 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (2nd Revised Service Agreement 746) terminating on June 30, 2028.
Schedule Page: 328.1 Line No.: 16 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.: 17 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 17 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 17 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 17 Column: m
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
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (1st Revised Service Agreement 747) terminating on June 30, 2028.
Schedule Page: 328.1 Line No.: 18 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
Schedule Page: 328.1 Line No.: 19 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.: 19 Column: g
Chelatchie/View 115kV
Schedule Page: 328.1 Line No.: 19 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.: 20 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.: 20 Column: g
Chelatchie/View 115kV
Schedule Page: 328.1 Line No.: 20 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.1 Line No.: 21 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 21 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 21 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 21 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 22 Column: d
Transmission service under the Open Access Transmission Tariff (10th Revised Service
Agreement 299). Service provided pursuant to rules and regulations of Oregon Direct
Access. Agreement terminates upon notification pursuant to Oregon Direct Access and Open
Access Transmission Tariff.
Schedule Page: 328.1 Line No.: 22 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.: 23 Column: d
Transmission service under the Open Access Transmission Tariff (10th Revised Service
Agreement 299). Service provided pursuant to rules and regulations of Oregon Direct
Access. Agreement terminates upon notification pursuant to Oregon Direct Access and Open
Access Transmission Tariff.
Schedule Page: 328.1 Line No.: 23 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.1 Line No.: 24 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 24 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 24 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 24 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 25 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 25 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 25 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 25 Column: m
2015 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 26 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 26 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 26 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 26 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 27 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 27 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 27 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 27 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 28 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.: 28 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.: 28 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.
Schedule Page: 328.1 Line No.: 29 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.: 29 Column: m
2015 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 30 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.: 30 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
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.: 30 Column: m
Distribution voltage service charge. Meter interrogation services. 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.: 31 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.: 31 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.1 Line No.: 32 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 32 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 32 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 32 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 33 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 33 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 33 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 33 Column: m
2015 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 34 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 34 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 34 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 34 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 1 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 1 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 1 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 780) terminating no earlier than 12-months from notice by the customer.
Schedule Page: 328.2 Line No.: 1 Column: m
Transmission resale - purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.11
Schedule Page: 328.2 Line No.: 2 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
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
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.: 2 Column: m
2015 transmission and ancillary services. 2015 annual transmission services true-up
refund.
Schedule Page: 328.2 Line No.: 3 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 3 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 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: 328.2 Line No.: 3 Column: m
Transmission resale - purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control service.
Schedule Page: 328.2 Line No.: 4 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 4 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 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: 328.2 Line No.: 4 Column: m
2015 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 5 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 5 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: 328.2 Line No.: 5 Column: m
2015 transmission and ancillary services. 2015 annual transmission services true-up
refund.
Schedule Page: 328.2 Line No.: 6 Column: d
Transmission service under the Open Access Transmission Tariff (1st Revised Service
Agreement 789). Service provided pursuant to rules and regulations of Oregon Direct Access
terminating on December 31, 2016.
Schedule Page: 328.2 Line No.: 6 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.
Schedule Page: 328.2 Line No.: 7 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: 328.2 Line No.: 7 Column: m
2015 transmission and ancillary services. 2015 annual transmission services true-up
refund.
Schedule Page: 328.2 Line No.: 8 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.12
Schedule Page: 328.2 Line No.: 8 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 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: 328.2 Line No.: 8 Column: m
Reactive supply and voltage control service. Generation regulation and frequency response
service. Operating reserve - spinning reserve service. Operating reserve - supplemental
reserve service. Unauthorized use of transmission service. Scheduling, system control and
dispatch service.
Schedule Page: 328.2 Line No.: 9 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 9 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 9 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 9 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.2 Line No.: 10 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 10 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 10 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 10 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.2 Line No.: 11 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: 328.2 Line No.: 11 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.: 12 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: 328.2 Line No.: 12 Column: m
2015 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 13 Column: d
Service Agreement 761 executed between PacifiCorp and Foote Creek III, LLC (d/b/a
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: 328.2 Line No.: 13 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: 328.2 Line No.: 14 Column: d
Service Agreement 761 executed between PacifiCorp and Foote Creek III, LLC (d/b/a
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.13
Schedule Page: 328.2 Line No.: 14 Column: m
2015 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 15 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 15 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 15 Column: d
Legacy Contract (Rate Schedule 257) executed between PacifiCorp and Idaho Power Company
for transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge for the Antelope Substation terminating coterminous with the Idaho Power
Company and United States Department of Education Supply Agreement.
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
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 16 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 16 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.: 16 Column: m
2015 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER11-3646.
Schedule Page: 328.2 Line No.: 17 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 17 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 17 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 17 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 18 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 18 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 18 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 18 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 19 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 19 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 19 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 19 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 20 Column: 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.14
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.: 20 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.
Schedule Page: 328.2 Line No.: 21 Column: d
Legacy Contract (3rd Revised Rate Schedule 302) executed between PacifiCorp and Moon Lake
Electric Association for transmission and interconnection service over agreed-upon
facilities and/or subject to a sole-use or facilities charge. Either party may terminate
the agreement at any time after October 14, 2016, by providing two years written notice.
Schedule Page: 328.2 Line No.: 21 Column: m
2015 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 22 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 22 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 22 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 22 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.2 Line No.: 23 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 23 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 23 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 23 Column: m
2015 transmission and ancillary services.
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. Generation regulation and frequency response 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: 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.15
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 26 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 26 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 26 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 27 Column: 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.: 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
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.: 28 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.: 28 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.2 Line No.: 29 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 29 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 29 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 29 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
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
2015 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER11-3646.
Schedule Page: 328.2 Line No.: 31 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 31 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 31 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 31 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.16
Schedule Page: 328.2 Line No.: 32 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 32 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 32 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 32 Column: m
2015 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 33 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 766) terminating on May 31, 2019.
Schedule Page: 328.2 Line No.: 33 Column: f
This footnote applies to all occurrences of "PGE" on pages 328-330. Complete name is
Portland General Electric Company.
Schedule Page: 328.2 Line No.: 33 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 34 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 34 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 34 Column: d
Legacy Contract (Rate Schedule 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: f
Malin to Indian Springs line segment
Schedule Page: 328.2 Line No.: 34 Column: g
Malin to Indian Springs line segment
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.
Schedule Page: 328.3 Line No.: 1 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 1 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 1 Column: d
Legacy Contract (Rate Schedule 607) executed between PacifiCorp and Pacific Gas & Electric
Company for transmission service over agreed-upon facilities (Malin to Round Mountain)
and/or subject to a sole-use or facilities charge. Terminating on December 31, 2017. See
PacifiCorp, Docket No. ER07-882, et al, Settlement Agreement, Appendix 2 (filed November
20, 2007).
Schedule Page: 328.3 Line No.: 1 Column: m
2015 transmission and ancillary services.
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.17
Schedule Page: 328.3 Line No.: 2 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.3 Line No.: 3 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 3 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 3 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 3 Column: m
2015 transmission and ancillary services.
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
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 5 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 5 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 on
December 2013.
Schedule Page: 328.3 Line No.: 5 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.: 6 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.: 6 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.: 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: 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
2015 transmission and ancillary services.
Schedule Page: 328.3 Line No.: 8 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.: 8 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.18
Service Agreement 169) terminating on October 31, 2020.
Schedule Page: 328.3 Line No.: 8 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 9 Column: 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
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.3 Line No.: 10 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.: 10 Column: m
Scheduling, system control and dispatch service.
Schedule Page: 328.3 Line No.: 11 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.: 11 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.3 Line No.: 12 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.: 12 Column: m
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
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.3 Line No.: 14 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.: 14 Column: m
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
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.3 Line No.: 16 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.: 16 Column: m
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
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.3 Line No.: 18 Column: d
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.19
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.: 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
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.3 Line No.: 20 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 20 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 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: 328.3 Line No.: 20 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
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
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
2015 transmission and ancillary services.
Schedule Page: 328.3 Line No.: 22 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 22 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 22 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 22 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.
Schedule Page: 328.3 Line No.: 23 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 23 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 23 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 23 Column: m
2015 transmission and ancillary services.
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.20
between various parties and points.
Schedule Page: 328.3 Line No.: 24 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.3 Line No.: 25 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 25 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 25 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 25 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 26 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.: 26 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 751) terminating on September 30, 2018.
Schedule Page: 328.3 Line No.: 26 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 27 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 751) terminating on September 30, 2018.
Schedule Page: 328.3 Line No.: 27 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.3 Line No.: 28 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.: 28 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 29 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.: 29 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.3 Line No.: 30 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised
Service Agreement 791) terminating upon written notification.
Schedule Page: 328.3 Line No.: 31 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised
Service Agreement 791) terminating upon written notification.
Schedule Page: 328.3 Line No.: 32 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 32 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 32 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 32 Column: m
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.21
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.3 Line No.: 33 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 33 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 33 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 33 Column: m
2015 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. Generation regulation and frequency response service.
Schedule Page: 328.4 Line No.: 1 Column: a
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: 328.4 Line No.: 1 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.4 Line No.: 1 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.4 Line No.: 1 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.: 1 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.: 2 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.4 Line No.: 2 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.4 Line No.: 2 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.: 2 Column: m
2015 transmission and ancillary services.
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.: 3 Column: m
Unauthorized use of transmission service. Scheduling, system control and dispatch service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.22
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.: 4 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 4 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 4 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.4 Line No.: 5 Column: c
Complete name is Southern California Public Power Authority. Various signatories to the
Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 5 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.: 5 Column: m
Unauthorized use of transmission service.
Schedule Page: 328.4 Line No.: 6 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.: 6 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 7 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.: 7 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 9 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 9 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 9 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 9 Column: m
2015 transmission and ancillary services.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.23
Schedule Page: 328.4 Line No.: 10 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 10 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 10 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 10 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 11 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 11 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 11 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.4 Line No.: 12 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 12 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 12 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 12 Column: m
2015 transmission and ancillary services.
Schedule Page: 328.4 Line No.: 13 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 13 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 13 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 13 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service.
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.
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.24
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 16 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 16 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.: 16 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.: 17 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 17 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.: 17 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.4 Line No.: 18 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 18 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 18 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 19 Column: 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
2015 transmission and ancillary services.
Schedule Page: 328.4 Line No.: 20 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 20 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 20 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 20 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 21 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 21 Column: d
Network transmission service under the Open Access Transmission Tariff (7th 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.25
Service Agreement 628) terminating on June 30, 2021.
Schedule Page: 328.4 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: 328.4 Line No.: 22 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.: 22 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 22 Column: d
Network transmission service under the Open Access Transmission Tariff (7th Revised
Service Agreement 628) terminating on June 30, 2021.
Schedule Page: 328.4 Line No.: 22 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
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.
Schedule Page: 328.4 Line No.: 24 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (2nd Revised Service Agreement 506) terminating upon written
notification.
Schedule Page: 328.4 Line No.: 24 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: 328.4 Line No.: 25 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (2nd Revised Service Agreement 506) terminating upon written
notification.
Schedule Page: 328.4 Line No.: 25 Column: m
2015 transmission and ancillary services. 2015 annual transmission services true-up
refund.
Schedule Page: 328.4 Line No.: 26 Column: c
This footnote applies to all occurrences of "Weber Basin Water Conserv." on pages 328-330.
Complete name is Weber Basin Water Conservancy District.
Schedule Page: 328.4 Line No.: 26 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: 328.4 Line No.: 26 Column: m
Energy consumption charge for deliveries at and below 138kV.
Schedule Page: 328.4 Line No.: 27 Column: d
Legacy Contract (3rd Revised Rate Schedule 286) executed between PacifiCorp and United
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.26
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: 328.4 Line No.: 27 Column: m
2015 transmission and ancillary services.
Schedule Page: 328.4 Line No.: 28 Column: d
Legacy Contract (3rd Amended Rate Schedule 67) executed between PacifiCorp and United
States Department of the Interior, Bureau of Reclamation Crooked River Irrigation District
for transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge. Agreement termination with one year written notice.
Schedule Page: 328.4 Line No.: 29 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: 328.4 Line No.: 29 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, 4th Revised Rate Schedule 297). Agreement
subject to termination upon mutual agreement and replacement agreements are in effect.
Schedule Page: 328.4 Line No.: 29 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: 328.4 Line No.: 30 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: 328.4 Line No.: 30 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
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. Generation regulation and frequency response 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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.4 Line No.: 33 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.27
Restated Transmission Service and Operating Agreement). Subject to termination upon mutual
agreement and replacement agreements are in effect.
Schedule Page: 328.4 Line No.: 33 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: 328.4 Line No.: 34 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: 328.4 Line No.: 34 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.5 Line No.: 1 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.: 1 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.
Schedule Page: 328.5 Line No.: 2 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.: 2 Column: m
2015 transmission and ancillary services.
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.: 4 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.5 Line No.: 4 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.: 4 Column: m
Fixed termination fee associated with a contract cancellation applied for the duration of
this agreement.
Schedule Page: 328.5 Line No.: 5 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.5 Line No.: 5 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.: 5 Column: m
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.28
2015 transmission and ancillary services.
Schedule Page: 328.5 Line No.: 6 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.5 Line No.: 6 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.: 6 Column: m
Charges for low-voltage transmission of power and energy.
Schedule Page: 328.5 Line No.: 7 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.5 Line No.: 7 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.: 7 Column: m
2015 transmission and ancillary services.
Schedule Page: 328.5 Line No.: 8 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 8 Column: d
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.: 9 Column: d
Evergreen network transmission service under the Open Access Transmission Tariff (4th
Revised Service Agreement 175).
Schedule Page: 328.5 Line No.: 9 Column: m
Distribution voltage service charge. Primary delivery service. Scheduling, system control
and dispatch service. Reactive supply and voltage control service.
Schedule Page: 328.5 Line No.: 10 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.: 10 Column: d
Evergreen network transmission service under the Open Access Transmission Tariff (4th
Revised Service Agreement 175).
Schedule Page: 328.5 Line No.: 10 Column: m
2015 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2015 annual transmission services true-up refund.
Schedule Page: 328.5 Line No.: 11 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 11 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.5 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.5 Line No.: 12 Column: 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.29
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.
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
2015 transmission and ancillary services.
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.
Schedule Page: 328.5 Line No.: 15 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.30
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
PacifiCorp X
/ /2016/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 -1,602 -1,602Arizona Public Service 1
LFP 1,835,595 1,835,595 479,252 479,252Arizona Public Service 2
NF 34,142 34,142 18,165 18,165Arizona Public Service 3
OS 14,099 14,099Arizona Public Service 4
SFP 341,441 341,441 53,915 53,915Arizona Public Service 5
FNS 23,573 23,573 2,531 2,531Ashland, City of 6
FNS 217,930 217,930 984,354 982,566Avista Corporation 7
NF 47,043 47,043 8,153 8,153Avista Corporation 8
OLF 161,364 161,364Big Horn Rural Electric 9
NF 17,333 17,333 18,021 18,021Black Hills Power, Inc. 10
OS 21,340 21,340Black Hills Power, Inc. 11
SFP 17,924 17,924 2,788 2,788Black Hills Power, Inc. 12
AD -820 -96 123 -847 -401 -401Bonneville Power Admin 13
FNS 6,700,449 6,700,449Bonneville Power Admin 14
LFP 67,216,014 67,216,014 5,274,941 5,274,941Bonneville Power Admin 15
NF 500,176 500,176 96,955 96,955Bonneville Power Admin 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332
17,233,688 17,651,786 125,377,132 2,366,941 3,044,834 130,788,907TOTAL
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
/ /2016/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification(b)
OLF 22,151,642 97,364 22,054,278 3,951,094 3,690,451Bonneville Power Admin 1
OS 88,854 64,730 24,124 53,628 53,628Bonneville Power Admin 2
SFP 1,808,440 1,808,440 352,629 352,629Bonneville Power Admin 3
AD 336,695 340,750 -4,055CA Ind Sys Operator 4
OS 1,769,502 1,769,502 2,115 2,115CA Ind Sys Operator 5
SFP 22,972 22,972CA Ind Sys Operator 6
LFP 4,480,063 4,480,063 125,602 125,602Deseret Gen & Trans 7
NF 11,069 11,069 1,510 1,510Deseret Gen & Trans 8
OS 2,875 2,875El Paso Electric Co. 9
SFP 16,077 16,077 18,438 18,438El Paso Electric Co. 10
OS 87,049 87,049Flathead Elect Coop Inc 11
OS 194,404 194,404Hermiston Gen Co L.P. 12
AD 146,141 146,141Idaho Power Company 13
FNS 10,789 10,789Idaho Power Company 14
LFP 12,215,826 12,215,826 4,480,350 4,395,980Idaho Power Company 15
NF 525,010 525,010 165,198 165,198Idaho Power Company 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.1
17,233,688 17,651,786 125,377,132 2,366,941 3,044,834 130,788,907TOTAL
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
/ /2016/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 -6,891 2,896 -9,787Idaho Power Company 1
SFP 670,059 670,059 253,520 253,520Idaho Power Company 2
FNS 285,018 285,018Moon Lake Elect. Assoc. 3
LFP 1,375 1,375 11 11Morgan City Corporation 4
AD -5,363 -12,863 7,500Nevada Power Company 5
NF 21,154 21,154 3,843 3,843Nevada Power Company 6
OS 136,649 136,649Nevada Power Company 7
SFP 1,007,300 1,007,300 245,140 245,140Nevada Power Company 8
NF 169,672 169,672 16,144 14,451NorthWestern Corp. 9
OS 11,817 11,817NorthWestern Corp. 10
SFP 69,509 69,509 16,038 16,038NorthWestern Corp. 11
LFP 849,700 849,700 172,581 172,581Platte River Pwr Auth 12
OS 17,437 17,437Platte River Pwr Auth 13
OLF 921 921Portland Gen. Electric 14
OS -62,388Portland Gen. Electric 15
SFP -627,754 -627,754Powerex Corporation 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.2
17,233,688 17,651,786 125,377,132 2,366,941 3,044,834 130,788,907TOTAL
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
/ /2016/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 1,040,781 1,040,781 78,703 75,103Public Service Co of CO 1
NF -7 -7Public Service Co of CO 2
AD 3,447 3,447Public Service Co of NM 3
NF 1,432 1,432 240 240Public Service Co of NM 4
OS 100 100Public Service Co of NM 5
AD 4,950 4,950 4,150 4,150Puget Sound Energy, Inc 6
SFP 314,189 314,189 254,478 254,478Puget Sound Energy, Inc 7
NF 14,944 14,944 5,880 5,880Salt River Project 8
OS 1,898 1,898Salt River Project 9
SFP 3,000 3,000 1,200 1,200Seattle City Light 10
NF 44,188 44,188 7,070 7,070Sierra Pacific Power Co 11
OS 5,939 5,939Sierra Pacific Power Co 12
OLF 7,623 7,623Surprise Valley Electr. 13
SFP -7,640 -7,640The Energy Authority 14
SFP -19,652 -19,652TransAlta Energy 15
LFP 1,040,781 1,040,781 68,016 64,400Tri-State Gen & Transm 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.3
17,233,688 17,651,786 125,377,132 2,366,941 3,044,834 130,788,907TOTAL
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
/ /2016/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 26,783 26,783 6,051 6,051Tri-State Gen & Transm 1
OS 13,844 13,844Tri-State Gen & Transm 2
NF 9,666 9,666 2,135 2,135Tucson Electric Power 3
OS 1,193 1,193Tucson Electric Power 4
SFP 2,600 2,600 600 600Tucson Electric Power 5
AD -5,924 -18,115 12,191Western Area Power Admn 6
FNS 6,226,792 6,226,792Western Area Power Admn 7
LFP 2,016,250 2,016,250 317,177 317,177Western Area Power Admn 8
NF 141,342 141,342 74,587 74,587Western Area Power Admn 9
OS 770,951 770,951Western Area Power Admn 10
SFP 87,348 87,348 34,984 34,984Western Area Power Admn 11
LFP -3,491,927 -3,491,927Westport Field Svc LLC 12
528,800 528,800Reserve 13
-1,608,796 -1,608,796Accrual 14
15
16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.4
17,233,688 17,651,786 125,377,132 2,366,941 3,044,834 130,788,907TOTAL
Schedule Page: 332 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 332 Line No.: 1 Column: e
Settlement adjustment.
Schedule Page: 332 Line No.: 2 Column: b
Arizona Public Service Company - contract termination dates: January 11, 2041 and the date
that all generating plants comprising PacifiCorp resources associated with this agreement
have been retired from service or interests transferred.
Schedule Page: 332 Line No.: 4 Column: b
Arizona Public Service Company - Legacy contract executed between PacifiCorp and Arizona
Public Service Company concerning the exchange of transmission services over agreed-upon
facilities (Restated Transmission Service Agreement between PacifiCorp and Arizona Public
Service Company, Rate Schedule 436). The contract terminates October 31, 2020. See also
page 328, Transmission of electricity for others, in this Form No. 1.
Schedule Page: 332 Line No.: 4 Column: g
Ancillary services.
Schedule Page: 332 Line No.: 9 Column: b
Big Horn Rural Electric Company - contract termination date: March 10, 2018.
Schedule Page: 332 Line No.: 9 Column: g
Use of facilities.
Schedule Page: 332 Line No.: 11 Column: g
Ancillary services.
Schedule Page: 332 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 332 Line No.: 13 Column: e
Settlement adjustment.
Schedule Page: 332 Line No.: 13 Column: g
Settlement adjustment.
Schedule Page: 332 Line No.: 15 Column: b
Bonneville Power Administration - contract termination dates: 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.: 1 Column: b
Bonneville Power Administration - contract termination dates: December 31, 2018; September
30, 2027 and evergreen.
Schedule Page: 332.1 Line No.: 1 Column: g
Use of facilities.
Schedule Page: 332.1 Line No.: 2 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.: 2 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.1 Line No.: 4 Column: a
This footnote applies to all occurrences of "CA Ind Sys Operator" on page 332. Complete
name is California Independent System Operator Corporation.
Schedule Page: 332.1 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 332.1 Line No.: 4 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Settlement adjustment.
Schedule Page: 332.1 Line No.: 4 Column: g
Settlement adjustment.
Schedule Page: 332.1 Line No.: 5 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.1 Line No.: 7 Column: b
Deseret Generation and Transmission Co-operative - contract termination dates: January 1,
2018 and September 1, 2018.
Schedule Page: 332.1 Line No.: 9 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 11 Column: g
Use of facilities.
Schedule Page: 332.1 Line No.: 12 Column: a
Hermiston Generating Company, L.P. operates the Hermiston Generating Plant, which is
jointly owned. PacifiCorp owns 50% of the plant.
Schedule Page: 332.1 Line No.: 12 Column: g
Use of facilities.
Schedule Page: 332.1 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 332.1 Line No.: 13 Column: g
Settlement adjustment.
Schedule Page: 332.1 Line No.: 15 Column: b
Idaho Power Company - contract termination dates: April 1, 2025 and July 1, 2025.
Schedule Page: 332.2 Line No.: 1 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.: 1 Column: f
Settlement adjustment.
Schedule Page: 332.2 Line No.: 1 Column: g
Ancillary services. Use of facilities. PacifiCorp's portion of specified costs of certain
facilities.
Schedule Page: 332.2 Line No.: 3 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 4 Column: b
Morgan City Corporation - contract termination date: Evergreen.
Schedule Page: 332.2 Line No.: 5 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.: 5 Column: b
Settlement adjustment.
Schedule Page: 332.2 Line No.: 5 Column: g
Settlement adjustment.
Schedule Page: 332.2 Line No.: 7 Column: g
Ancillary services.
Schedule Page: 332.2 Line No.: 10 Column: g
Ancillary services.
Schedule Page: 332.2 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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Platte River Power Authority - contract termination date: October 31, 2017.
Schedule Page: 332.2 Line No.: 13 Column: g
Ancillary services.
Schedule Page: 332.2 Line No.: 14 Column: b
Portland General Electric Company - contract termination date: Upon two years written
notice.
Schedule Page: 332.2 Line No.: 14 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 16 Column: e
Reassignment of Bonneville Power Administration transmission.
Schedule Page: 332.3 Line No.: 1 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.: 2 Column: e
Settlement adjustment.
Schedule Page: 332.3 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 332.3 Line No.: 5 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 332.3 Line No.: 9 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 11 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: 332.3 Line No.: 12 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 13 Column: b
Surprise Valley Electrification Corp. - contract termination date: Evergreen.
Schedule Page: 332.3 Line No.: 13 Column: g
Settlement adjustment.
Schedule Page: 332.3 Line No.: 14 Column: e
Reassignment of Bonneville Power Administration transmission.
Schedule Page: 332.3 Line No.: 15 Column: a
This footnote applies to all occurrences of "TransAlta Energy" on page 332. Complete name
is TransAlta Energy Marketing (U.S.) Inc.
Schedule Page: 332.3 Line No.: 15 Column: e
Reassignment of Bonneville Power Administration transmission.
Schedule Page: 332.3 Line No.: 16 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.: 2 Column: g
Settlement adjustment.
Schedule Page: 332.4 Line No.: 4 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 332.4 Line No.: 6 Column: g
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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 332.4 Line No.: 8 Column: b
Western Area Power Administration - contract termination date: May 31, 2022.
Schedule Page: 332.4 Line No.: 10 Column: b
Western Area Power Administration - Legacy contract (Rate Schedule 664) executed between
PacifiCorp and Western Area Power Administration concerning the exchange of transmission
services over agreed-upon facilities. The contract terminates 50 years from execution. See
also page 328, Transmission of electricity for others, in this Form No. 1.
Schedule Page: 332.4 Line No.: 10 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.4 Line No.: 12 Column: b
Westport Field Services, LLC - contract termination date: Evergreen.
Schedule Page: 332.4 Line No.: 12 Column: e
Reimbursement for third party services.
Schedule Page: 332.4 Line No.: 13 Column: g
Reserve for a contingent liability.
Schedule Page: 332.4 Line No.: 14 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
2016/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 / /2016/Q4
Line Description Amount
(b)(a)No.
1,148,762Industry 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
10,000American Wind Energy Association 9
28,840Associated Oregon Industries 10
6,000Clatsop Economic Development Resources 11
7,500Economic Development for Central Oregon 12
5,000Greater Yakima Chamber of Commerce 13
5,000Hollywood Theatre 14
21,875Independent Energy Producers Association, Inc. 15
9,000Intermountain Electrical Association 16
7,500Klamath County Economic Development Association 17
5,000Laramie Chamber of Business Alliance 18
6,035National Safety Council 19
6,000Ogden-Weber Chamber of Commerce 20
14,595Oregon Business Association 21
17,953Oregon Business Council 22
7,500Oregon Economic Development Association 23
5,000Oregon Sports Authority 24
15,000Oregon State University Utility Pole Research Coop 25
78,674Pacific Northwest Utilities Conference Committee 26
7,000Redmond Economic Development, Inc. 27
18,000Rocky Mountain Electrical League 28
5,000Rural Development Initiatives, Inc. 29
28,350Salt Lake Area Chamber of Commerce 30
5,500South Coast Development Council, Inc. 31
6,400Strategic Economic Development Corporation 32
25,000University of Utah 33
18,700Utah Taxpayers Association 34
12,000Utah Technology Council 35
7,500Yakima County Development Association 36
153,302Other (Individually < $5,000) 37
38
14,534Directors' Fees - Regional Advisory Board 39
40
Rating Agency and Trustee Fees: 41
129,848The Bank of New York Mellon 42
17,172Computershare Shareowner Services, LLC 43
595CUSIP Global Services 44
39,323Fitch, Inc. 45
2,346,536
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 / /2016/Q4
Line Description Amount
(b)(a)No.
96,525Moody's Investor Services, Inc. 6
260,038Standard and Poor's Financial Services, LLC 7
10,944U.S. Bancorp 8
9
Regulatory Asset Amortization: 10
35,000Generating Plant Liquidated Damages - UT 11
54,288Generating Plan Liquidated Damages - WY 12
13
General: 14
-3,717Other 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
2,346,536
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
/ /2016/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)
36,791,866 36,791,866 1 Intangible Plant
259,494,969 259,494,969 2 Steam Production Plant
3 Nuclear Production Plant
34,406,205 34,101,659 304,546 4 Hydraulic Production Plant-Conventional
5 Hydraulic Production Plant-Pumped Storage
126,906,136 126,906,136 6 Other Production Plant
104,655,006 104,655,006 7 Transmission Plant
144,013,757 144,013,757 8 Distribution Plant
9 Regional Transmission and Market Operation
41,404,035 39,923,447 1,480,588 10 General Plant
11 Common Plant-Electric
747,671,974 709,094,974 38,577,000 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
/ /2016/Q4
Line
No.Account No.
(c)(b)(a)(d) (e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f) (g)(Percent)
STEAM PRODUCTION 12
Blundell Plant 13
46.97 2.09 24.00310.20 UT 40,982 14
42.30 -4.00 2.51 23.30311.00 UT 8,296 15
34.11 -3.00 2.98 22.20312.00 UT 57,519 16
32.76 -5.00 3.30 21.50314.00 UT 34,086 17
39.15 -3.00 2.70 23.10315.00 UT 8,575 18
29.19 -5.00 3.76 19.30316.00 UT 1,386 19
Cholla Plant 20
34.48 2.89 29.00310.20 AZ 1,368 21
45.93 -6.00 2.34 28.00311.00 AZ 65,183 22
37.41 -5.00 2.89 26.20312.00 AZ 339,497 23
38.37 -7.00 2.85 24.80314.00 AZ 67,634 24
46.05 -5.00 2.32 27.30315.00 AZ 68,727 25
33.53 -7.00 3.31 21.40316.00 AZ 4,094 26
Colstrip Plant 27
55.79 -6.00 1.88 31.50311.00 MT 61,428 28
47.52 -6.00 2.24 28.10312.00 MT 119,477 29
41.60 -8.00 2.61 27.30314.00 MT 38,426 30
56.37 -5.00 1.83 30.00315.00 MT 9,224 31
36.94 -7.00 2.90 22.90316.00 MT 397 32
Craig Plant 33
48.45 -6.00 2.11 20.40311.00 CO 38,324 34
34.51 -5.00 3.00 19.40312.00 CO 96,437 35
31.03 -7.00 3.50 19.10314.00 CO 28,715 36
49.53 -5.00 2.04 19.80315.00 CO 17,066 37
34.18 -7.00 3.11 16.50316.00 CO 1,240 38
Dave Johnston Plant 39
53.86 2.30 14.00310.20 WY 100 40
20.39 -4.00 5.56 13.80311.00 WY 158,156 41
19.99 -4.00 5.69 13.60312.00 WY 689,845 42
24.19 -5.00 4.82 13.20314.00 WY 96,287 43
20.04 -3.00 5.67 13.80315.00 WY 62,765 44
18.11 -4.00 6.03 12.60316.00 WY 8,418 45
Gadsby Plant 46
43.40 -15.00 2.02 18.60311.00 UT 15,108 47
39.12 -13.00 2.22 17.50312.00 UT 38,900 48
37.19 -15.00 2.43 16.80314.00 UT 19,917 49
34.93 -14.00 2.87 18.30315.00 UT 8,420 50
FERC FORM NO. 1 (REV. 12-03) Page 337
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2016/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)
29.04 -13.00 3.17 15.80316.00 UT 458 12
Hayden Plant 13
23.54 -5.00 4.62 16.70311.00 CO 17,688 14
30.98 -5.00 3.14 16.00312.00 CO 82,794 15
27.79 -6.00 3.69 15.80314.00 CO 9,633 16
48.38 -5.00 1.74 16.10315.00 CO 2,555 17
30.28 -6.00 3.22 14.20316.00 CO 637 18
Hunter Plant 19
60.93 1.61 29.00310.20 UT 246 20
55.00 -7.00 1.93 27.80311.00 UT 209,648 21
38.55 -6.00 2.79 26.10312.00 UT 758,565 22
34.57 -8.00 3.17 25.60314.00 UT 200,440 23
53.28 -6.00 1.97 26.70315.00 UT 107,848 24
35.58 -8.00 3.08 20.80316.00 UT 3,691 25
Huntington Plant 26
45.56 -7.00 2.39 22.30311.00 UT 124,429 27
29.78 -6.00 3.64 21.60312.00 UT 563,304 28
31.75 -7.00 3.43 20.80314.00 UT 123,318 29
39.00 -6.00 2.78 22.00315.00 UT 47,559 30
27.99 -7.00 3.96 18.70316.00 UT 2,890 31
Jim Bridger Plant 32
61.28 1.36 24.00310.20 WY 281 33
51.14 -8.00 1.87 23.20311.00 WY 145,500 34
35.97 -7.00 2.86 22.00312.00 WY 957,963 35
31.25 -8.00 3.36 21.70314.00 WY 204,971 36
49.15 -7.00 1.93 22.40315.00 WY 60,997 37
33.02 -8.00 3.12 18.50316.00 WY 4,187 38
Naughton Plant 39
66.74 1.45 16.00310.20 WY 15 40
24.81 -5.00 4.34 15.80311.00 WY 119,098 41
22.44 -4.00 4.81 15.40312.00 WY 512,916 42
25.92 -6.00 4.17 15.00314.00 WY 82,508 43
21.19 -4.00 5.13 15.80315.00 WY 65,202 44
21.86 -6.00 5.15 13.90316.00 WY 2,331 45
Wyodak Plant 46
57.58 1.65 26.00310.20 WY 165 47
51.08 -5.00 2.01 25.10311.00 WY 51,567 48
34.28 -4.00 3.09 23.90312.00 WY 312,349 49
34.60 -6.00 3.12 22.90314.00 WY 66,458 50
FERC FORM NO. 1 (REV. 12-03) Page 337.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2016/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)
42.62 -4.00 2.44 24.60315.00 WY 28,640 12
26.65 -6.00 4.07 21.10316.00 WY 1,237 13
14
HYDRAULIC 15
Ashton 16
40.48 2.79 14.00330.20 ID 328 17
34.65 -2.00 3.33 13.80331.00 ID 2,020 18
17.43 -1.00 6.19 13.90332.00 ID 28,108 19
35.43 -2.00 3.21 13.60333.00 ID 1,958 20
30.80 -3.00 3.77 13.00334.00 ID 1,326 21
41.77 -1.00 2.82 13.20335.00 ID 8 22
96.08 -5.00 1.64 13.50336.00 ID 6 23
Bear River 24
115.28 1.38 19.80330.20 ID 6 25
38.54 -3.00 3.09 19.30331.00 ID 4,869 26
34.60 -2.00 3.31 19.60332.00 ID 28,257 27
33.28 -4.00 3.50 19.20333.00 ID 11,711 28
30.59 -4.00 3.79 18.20334.00 ID 5,113 29
42.57 -1.00 2.73 18.50335.00 ID 82 30
40.28 -3.00 2.94 19.40336.00 ID 844 31
Bend 32
32.00 2.09 3.00331.00 OR 57 33
8.74 17.64 3.00332.00 OR 1,161 34
18.04 -1.00 6.79 3.00333.00 OR 107 35
25.63 3.53 3.00334.00 OR 628 36
15.79 3.38 3.00335.00 OR 15 37
86.23336.00 OR 38
Big Fork 39
52.37 -5.00 1.41 38.30331.00 MT 606 40
53.78 -4.00 1.29 38.70332.00 MT 4,855 41
50.44 -8.00 1.46 37.20333.00 MT 1,496 42
46.04 -8.00 1.52 33.00334.00 MT 404 43
45.15 -4.00 2.13 38.40336.00 MT 234 44
Cutler 45
8.34330.20 UT 1 46
96.37 3.11 11.00330.30 UT 5 47
74.44 3.33 11.00330.40 UT 91 48
28.62 -1.00 5.06 10.80331.00 UT 3,987 49
30.30 -1.00 5.01 10.80332.00 UT 9,178 50
FERC FORM NO. 1 (REV. 12-03) Page 337.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2016/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)
17.15 -1.00 7.18 10.90333.00 UT 12,000 12
17.22 -2.00 7.29 10.60334.00 UT 2,691 13
36.34 -1.00 4.52 10.60335.00 UT 11 14
35.14 -1.00 4.54 10.80336.00 UT 572 15
Eagle Point 16
68.49330.20 OR 12 17
33.98 -1.00 1.31 11.90331.00 OR 141 18
33.88 -1.00 1.25 11.90332.00 OR 1,233 19
42.71 -4.00 0.31 11.80333.00 OR 252 20
25.76 -2.00 2.68 11.50334.00 OR 135 21
24.29 -1.00 2.96 11.90336.00 OR 179 22
Granite 23
25.43 -2.00 4.42 16.70331.00 UT 535 24
30.19 -1.00 3.60 16.80332.00 UT 3,768 25
38.99 -4.00 3.06 16.30333.00 UT 721 26
31.63 -3.00 3.63 15.60334.00 UT 215 27
48.73 -2.00 2.45 16.00335.00 UT 1 28
Klamath River 29
24.88 7.02 7.00330.20 CA/OR 639 30
48.84 5.27 7.00330.40 CA/OR 253 31
21.42 -1.00 7.87 6.90331.00 CA/OR 914 32
40.24 -1.00 5.79 6.90332.00 CA/OR 11,773 33
43.09 -3.00 5.84 6.70333.00 CA/OR 315 34
19.24 -1.00 8.32 6.80334.00 CA/OR 874 35
29.11 -1.00 6.92 6.80335.00 CA/OR 62 36
23.60 -1.00 7.41 6.90336.00 CA/OR 241 37
Klamath River Accel 38
1.87 3.00330.20 CA/OR 41 39
1.37 3.00330.40 CA/OR 1 40
9.35 3.00331.00 CA/OR 15,590 41
8.57 3.00332.00 CA/OR 36,860 42
7.31 3.00333.00 CA/OR 17,983 43
8.66 3.00334.00 CA/OR 16,057 44
5.73 3.00335.00 CA/OR 183 45
7.39 3.00336.00 CA/OR 2,595 46
Last Chance 47
35.19 -1.00 3.45 11.80331.00 ID 448 48
29.40 -1.00 4.03 11.90332.00 ID 958 49
36.38 -2.00 3.35 11.70333.00 ID 1,068 50
FERC FORM NO. 1 (REV. 12-03) Page 337.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2016/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)
22.78 -2.00 5.03 11.40334.00 ID 266 12
40.81 -1.00 3.07 11.80336.00 ID 65 13
Lifton 14
99.80 1.87 20.00330.20 ID 21 15
92.81 1.93 20.00330.30 ID 24 16
51.97 -4.00 2.80 19.10331.00 ID 1,230 17
40.45 -3.00 3.17 19.50332.00 ID 8,270 18
26.40 -2.00 4.13 19.70333.00 ID 7,875 19
36.10 -4.00 3.53 18.00334.00 ID 377 20
46.32 -2.00 2.97 18.30335.00 ID 12 21
29.39 -2.00 3.83 19.60336.00 ID 187 22
Merwin 23
121.57 0.50 45.00330.20 WA 301 24
125.02 0.48 45.00330.50 WA 212 25
48.18 -4.00 2.11 42.90331.00 WA 91,202 26
54.60 -6.00 1.83 43.10332.00 WA 30,141 27
65.82 -16.00 1.44 37.20333.00 WA 8,205 28
44.36 -8.00 2.34 36.30334.00 WA 9,847 29
48.09 -3.00 2.07 38.40335.00 WA 169 30
59.30 -5.00 1.62 42.40336.00 WA 3,963 31
North Umpqua 32
27.53 -2.00 3.82 24.40331.00 OR 33,546 33
38.59 -2.00 2.90 24.40332.00 OR 199,120 34
34.44 -4.00 3.27 24.00333.00 OR 25,615 35
29.42 -4.00 3.75 22.60334.00 OR 19,204 36
36.23 -2.00 3.05 22.90335.00 OR 722 37
41.97 -3.00 2.73 24.20336.00 OR 9,570 38
Paris 39
10.31 10.16 4.00331.00 ID 110 40
46.25 -1.00332.00 ID 102 41
31.74 -1.00333.00 ID 73 42
14.62 -1.00 4.90 4.00334.00 ID 162 43
34.25335.00 ID 44
Pioneer 45
134.02 1.09 17.00330.20 UT 9 46
133.34 1.09 17.00330.30 UT 111 47
32.02 -2.00 3.54 16.60331.00 UT 508 48
37.80 -2.00 2.97 16.70332.00 UT 8,185 49
25.26 -2.00 4.31 16.70333.00 UT 1,616 50
FERC FORM NO. 1 (REV. 12-03) Page 337.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2016/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)
30.51 -3.00 3.67 15.60334.00 UT 944 12
39.03 -1.00 2.85 16.00335.00 UT 10 13
21.11 -1.00 5.17 16.70336.00 UT 61 14
Prospect No. 1, 2 & 4 15
56.24 2.02 25.30330.20 OR 4 16
102.16 1.36 24.90330.40 OR 3 17
40.66 -3.00 2.77 24.20331.00 OR 3,906 18
32.55 -2.00 3.27 24.60332.00 OR 34,179 19
35.11 -4.00 3.18 24.00333.00 OR 3,898 20
33.85 -5.00 3.34 22.20334.00 OR 6,791 21
35.19 -2.00 3.05 23.10335.00 OR 19 22
39.57 -3.00 2.84 24.20336.00 OR 339 23
Prospect No. 3 24
21.27 5.46 5.00331.00 OR 644 25
25.67 4.15 5.00332.00 OR 4,333 26
21.89 4.76 5.00333.00 OR 1,812 27
21.02 -1.00 5.25 4.90334.00 OR 1,887 28
25.01 4.22 4.90335.00 OR 63 29
36.09 -1.00 3.29 5.00336.00 OR 117 30
Santa Clara 31
23.79 -1.00 5.05 6.90331.00 UT 180 32
24.52 -1.00 4.92 7.00332.00 UT 1,139 33
26.11 -1.00 4.44 6.90333.00 UT 464 34
20.82 -1.00 5.46 6.80334.00 UT 702 35
32.24 -1.00 3.62 6.80335.00 UT 8 36
80.51 -2.00 1.79 6.80336.00 UT 22 37
Stairs 38
39.40 -3.00 2.38 16.60331.00 UT 181 39
28.73 -2.00 3.56 16.80332.00 UT 811 40
36.73 -3.00 2.52 16.50333.00 UT 518 41
33.10 -3.00 2.83 15.60334.00 UT 176 42
19.20 -1.00 5.08 16.80336.00 UT 33 43
Swift No. 1 44
99.73 0.86 45.00330.20 WA 6,277 45
98.01 0.88 45.00330.50 WA 97 46
46.22 -4.00 2.26 43.00331.00 WA 72,455 47
70.57 -7.00 1.40 42.00332.00 WA 47,056 48
65.49 -16.00 1.63 37.00333.00 WA 16,406 49
45.90 -8.00 2.29 35.90334.00 WA 7,905 50
FERC FORM NO. 1 (REV. 12-03) Page 337.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2016/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)
64.91 -5.00 1.46 34.20335.00 WA 411 12
52.23 -5.00 1.98 42.70336.00 WA 1,133 13
Viva Naughton 14
49.70 -3.00 2.15 26.10331.00 WY 403 15
51.79 -2.00 2.04 26.30332.00 WY 104 16
49.03 -7.00 2.26 25.10333.00 WY 497 17
42.11 -6.00 2.63 23.20334.00 WY 207 18
46.04 -2.00 2.29 24.30335.00 WY 21 19
Wallowa Falls 20
23.24 4.41 3.00331.00 OR 168 21
23.14 4.39 3.00332.00 OR 918 22
15.16 9.10 3.00333.00 OR 807 23
18.38 4.99 3.00334.00 OR 741 24
20.11 4.76 3.00336.00 OR 649 25
Weber 26
34.24 -1.00 3.55 6.90331.00 UT 368 27
32.11 -1.00 3.90 6.90332.00 UT 1,999 28
28.58 -1.00 4.14 6.90333.00 UT 943 29
12.47 -1.00 9.75 6.80334.00 UT 258 30
28.45 3.97 6.80335.00 UT 22 31
25.64 -1.00 4.36 6.90336.00 UT 40 32
Yale 33
103.77 0.82 45.00330.20 WA 762 34
62.83 -6.00 1.60 42.10331.00 WA 16,289 35
70.68 -8.00 1.40 41.80332.00 WA 32,330 36
63.81 -15.00 1.68 37.70333.00 WA 12,573 37
48.93 -9.00 2.14 35.00334.00 WA 3,512 38
66.44 -5.00 1.40 33.00335.00 WA 547 39
57.33 -5.00 1.76 42.50336.00 WA 2,040 40
41
OTHER PRODUCTION 42
Chehalis 43
39.75 -3.00 2.65 29.50341.00 WA 24,163 44
36.50 -2.00 2.87 26.90342.00 WA 1,597 45
35.70 -4.00 3.04 26.80343.00 WA 212,870 46
36.45 -4.00 2.94 26.90344.00 WA 70,039 47
39.21 -3.00 2.69 29.20345.00 WA 39,304 48
38.83 -1.00 2.66 28.80346.00 WA 3,269 49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.6
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2016/Q4
Line
No.Account No.
(c)(b)(a)(d) (e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f) (g)(Percent)
Currant Creek 12
39.83 -3.00 2.59 31.50341.00 UT 44,165 13
36.50 -2.00 2.80 28.70342.00 UT 3,300 14
35.19 -4.00 3.01 28.80343.00 UT 194,855 15
36.06 -4.00 2.91 28.80344.00 UT 63,110 16
39.03 -3.00 2.64 31.20345.00 UT 42,881 17
39.06 -1.00 2.59 30.70346.00 UT 2,983 18
Hermiston 19
38.73 -3.00 2.90 22.60341.00 OR 12,845 20
36.50 -2.00 3.08 20.70342.00 OR 25 21
33.48 -4.00 3.42 20.80343.00 OR 112,132 22
35.85 -3.00 3.16 20.80344.00 OR 41,650 23
39.23 -3.00 2.88 22.40345.00 OR 9,768 24
39.06 -1.00 2.84 22.00346.00 OR 169 25
Lake Side/Lake Side 2 26
39.96 -4.00 2.77 33.50341.00 UT 88,654 27
36.50 -3.00 3.01 30.60342.00 UT 8,507 28
36.11 -4.00 3.11 30.40343.00 UT 549,525 29
36.40 -4.00 3.05 30.60344.00 UT 222,706 30
39.46 -3.00 2.77 33.10345.00 UT 119,843 31
39.06 -1.00 2.75 32.70346.00 UT 6,122 32
Gadsby Peakers 33
29.80 -1.00 3.43 18.90341.00 UT 4,273 34
28.45 -1.00 3.61 18.00342.00 UT 2,748 35
26.97 -2.00 3.91 18.10343.00 UT 55,199 36
28.61 -2.00 3.64 18.00344.00 UT 17,487 37
28.31 -1.00 3.62 18.80345.00 UT 2,901 38
39
WIND GENERATION 40
Dunlap Ranch 1 41
28.47 -1.00 3.49 25.30341.00 WY 7,804 42
29.58 -1.00 3.34 26.20343.00 WY 207,507 43
29.59 -1.00 3.34 26.20344.00 WY 6,565 44
29.93 3.26 26.50345.00 WY 12,311 45
29.94 3.25 26.50346.00 WY 149 46
Foote Creek 47
29.33 -1.00 3.49 15.30341.00 WY 113 48
30.37 -1.00 2.84 15.50343.00 WY 32,100 49
30.49 -1.00 2.83 15.50344.00 WY 1,684 50
FERC FORM NO. 1 (REV. 12-03) Page 337.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2016/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)
30.96 -1.00 2.78 15.70345.00 WY 2,927 12
Glenrock/Glenrock III 13
27.88 -1.00 3.53 23.50341.00 WY 10,574 14
29.01 -1.00 3.37 24.30343.00 WY 440,675 15
29.01 -1.00 3.37 24.30344.00 WY 13,688 16
29.33 3.30 24.60345.00 WY 29,538 17
29.44 3.28 24.60346.00 WY 1,663 18
Goodnoe Hills 19
28.49 -1.00 3.44 23.50341.00 WA 5,477 20
29.53 -1.00 3.30 24.30343.00 WA 163,281 21
29.46 -1.00 3.31 24.30344.00 WA 4,403 22
29.73 3.24 24.50345.00 WA 10,272 23
29.94 3.21 24.50346.00 WA 172 24
High Plains/McFadden 25
28.46 -1.00 3.47 24.40341.00 WY 7,815 26
29.57 -1.00 3.32 25.20343.00 WY 245,982 27
29.59 -1.00 3.32 25.20344.00 WY 7,008 28
29.92 3.23 25.50345.00 WY 14,750 29
29.94 3.23 25.50346.00 WY 114 30
Leaning Juniper 1 31
28.49 -1.00 3.39 21.70341.00 OR 4,965 32
29.47 -1.00 3.25 22.30343.00 OR 158,232 33
29.36 -1.00 3.28 22.30344.00 OR 5,378 34
29.70 -1.00 3.23 22.60345.00 OR 9,175 35
29.94 3.16 22.60346.00 OR 81 36
Marengo/Marengo II 37
28.15 -1.00 3.47 22.60341.00 WA 10,220 38
29.23 -1.00 3.32 23.30343.00 WA 328,664 39
29.22 -1.00 3.32 23.30344.00 WA 11,036 40
29.57 -1.00 3.27 23.60345.00 WA 19,742 41
29.48 3.25 23.60346.00 WA 337 42
Seven Mile Hill 43
28.38 -1.00 3.45 23.50341.00 WY 6,355 44
29.56 -1.00 3.29 24.30343.00 WY 216,059 45
29.59 -1.00 3.29 24.30344.00 WY 6,606 46
29.86 3.22 24.50345.00 WY 13,346 47
29.78 3.23 24.50346.00 WY 802 48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.8
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2016/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)
SOLAR GENERATING 12
19.88344.00 OR 56 13
20.49344.00 UT 36 14
20.46 4.11 14.00344.00 WY 6 15
20.42344.00 WY 55 16
17
MOBILE GENERATOR 18
East Side 19
50.00 -5.00 1.60 42.50R2344.00 UT 840 20
West Side 21
50.00 -5.00 1.80 46.00R2344.00 OR 849 22
23
TRANSMISSION PLANT 24
75.00 1.27 63.50R4350.20 199,737 25
75.00 -10.00 1.42 66.40R2.5352.00 242,604 26
58.00 -5.00 1.74 48.90S0353.00 2,031,695 27
68.00 -10.00 1.53 55.70R4354.00 1,290,262 28
60.00 -40.00 2.18 46.10R2355.00 915,984 29
63.00 -30.00 1.88 46.00R3356.00 1,209,045 30
60.00 1.60 48.50R2357.00 3,519 31
60.00 -5.00 1.66 48.20R2358.00 8,035 32
70.00 1.32 49.40R5359.00 11,937 33
34
DISTRIBUTION PLANT 35
55.00 1.21 36.80S3360.20 OR 4,761 36
60.00 -10.00 1.79 49.80R1.5361.00 OR 29,390 37
55.00 -15.00 1.94 43.50R1362.00 OR 239,713 38
55.00 -100.00 3.29 42.00R1.5364.00 OR 370,703 39
60.00 -70.00 2.63 47.40R0.5365.00 OR 257,650 40
70.00 -50.00 1.97 54.60R2.5366.00 OR 92,669 41
58.00 -35.00 2.11 43.70R2.5367.00 OR 177,017 42
42.00 -20.00 2.44 29.00R1.5368.00 OR 435,234 43
55.00 -35.00 2.28 42.50R1369.10 OR 88,752 44
55.00 -40.00 2.34 41.30R4369.20 OR 179,268 45
27.00 -4.00 3.60 17.90R1370.00 OR 63,499 46
25.00 -50.00 4.79 14.30L0371.00 OR 2,614 47
44.00 -40.00 2.91 33.80R0.5373.00 OR 23,386 48
50.00 1.63 24.50R3360.20 WA 458 49
60.00 -5.00 1.64 42.10R2361.00 WA 4,174 50
FERC FORM NO. 1 (REV. 12-03) Page 337.9
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2016/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)
53.00 -20.00 2.14 38.90R1362.00 WA 61,975 12
52.00 -100.00 3.64 39.40R1.5364.00 WA 103,865 13
60.00 -60.00 2.51 45.10R1365.00 WA 68,926 14
50.00 -50.00 2.84 35.40R3366.00 WA 17,818 15
50.00 -35.00 2.56 36.80R3367.00 WA 26,735 16
43.00 -25.00 2.64 28.90R2368.00 WA 110,091 17
55.00 -30.00 2.27 41.90R1369.10 WA 22,170 18
55.00 -50.00 2.63 41.30R4369.20 WA 38,806 19
25.00 -1.00 3.93 21.20S5370.00 WA 12,336 20
30.00 -25.00 3.48 15.50L0371.00 WA 508 21
45.00 -30.00 2.64 31.70R1373.00 WA 4,454 22
50.00 1.99 33.50R4360.20 WY 5,866 23
60.00 -10.00 1.83 49.90R2.5361.00 WY 16,949 24
55.00 -10.00 1.99 42.20R1362.00 WY 134,615 25
50.00 -100.00 3.99 39.10R1364.00 WY 151,693 26
57.00 -40.00 2.45 44.20R0.5365.00 WY 108,745 27
42.00 -40.00 3.32 30.60R3366.00 WY 26,374 28
40.00 -35.00 3.35 26.20R4367.00 WY 60,675 29
39.00 -25.00 3.19 28.90R1368.00 WY 118,277 30
60.00 -25.00 2.08 47.20R1.5369.10 WY 19,103 31
55.00 -50.00 2.72 44.10R4369.20 WY 43,002 32
25.00 -2.00 4.04 20.60S5370.00 WY 15,206 33
25.00 -60.00 6.10 12.20O1371.00 WY 968 34
50.00 -45.00 2.89 38.90R0.5373.00 WY 10,653 35
55.00 2.31 20.10R4360.20 CA 1,087 36
55.00 -5.00 2.05 37.62R4361.00 CA 5,128 37
55.00 -25.00 2.39 41.60R1362.00 CA 28,372 38
20.00 7.06 5.47R5362.70 CA 396 39
50.00 -90.00 3.80 37.94R1.5364.00 CA 64,671 40
65.00 -95.00 3.12 51.70S-.5365.00 CA 35,406 41
50.00 -45.00 2.99 34.58R5366.00 CA 17,546 42
45.00 -40.00 2.43 29.50S6367.00 CA 19,559 43
50.00 -25.00 2.53 32.34R5368.00 CA 52,611 44
55.00 -15.00 1.78 44.37R1369.10 CA 9,701 45
60.00 -20.00 1.81 48.69R4369.20 CA 15,899 46
26.00 -4.00 4.60 13.24R2.5370.00 CA 4,163 47
25.00 -40.00 4.81 13.85L0371.00 CA 275 48
35.00 -26.00 3.03 16.36R3373.00 CA 726 49
60.00 1.66 49.60R4360.20 UT 10,839 50
FERC FORM NO. 1 (REV. 12-03) Page 337.10
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2016/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)
60.00 1.66 50.90S0.5361.00 UT 54,386 12
47.00 -10.00 2.34 39.70R0.5362.00 UT 466,986 13
50.00 -80.00 3.59 39.60R0.5364.00 UT 369,852 14
52.00 -45.00 2.78 40.20R0.5365.00 UT 229,655 15
60.00 -50.00 2.49 49.00R2366.00 UT 194,144 16
50.00 -25.00 2.49 38.80R2367.00 UT 527,458 17
45.00 -5.00 2.33 36.30R0.5368.00 UT 509,612 18
55.00 -25.00 2.27 44.60S5369.00 UT 287,981 19
25.00 -2.00 3.90 16.90S5370.00 UT 82,636 20
25.00 -60.00 6.37 16.80L0371.00 UT 4,303 21
25.00 -20.00 4.78 16.90R0.5373.00 UT 21,965 22
50.00 1.99 34.20R4360.20 ID 1,312 23
60.00 1.66 48.90R2361.00 ID 2,326 24
55.00 -10.00 1.99 41.20R1.5362.00 ID 31,069 25
50.00 -80.00 3.59 39.50R0.5364.00 ID 85,814 26
52.00 -30.00 2.49 36.30R0.5365.00 ID 37,099 27
60.00 -40.00 2.33 48.90R2366.00 ID 9,524 28
50.00 -15.00 2.29 37.80R2367.00 ID 27,071 29
45.00 -5.00 2.33 34.20R0.5368.00 ID 79,606 30
55.00 -25.00 2.27 44.00S5369.00 ID 38,808 31
25.00 -3.00 3.95 13.10S5370.00 ID 15,113 32
25.00 -45.00 5.77 16.80L0371.00 ID 169 33
25.00 -20.00 4.78 16.90R0.5373.00 ID 707 34
35
GENERAL PLANT 36
58.00 -10.00 1.86 47.20R1390.00 OR 83,075 37
12.00 10.00 7.04 6.90L2.5392.01 OR 10,090 38
16.00 10.00 5.48 8.70L3392.05 OR 13,186 39
34.00 15.00 2.44 23.70L2392.09 OR 3,436 40
9.00 15.00 9.23 5.50L3396.03 OR 8,198 41
15.00 20.00 5.14 9.80L1396.07 OR 28,563 42
40.00 -10.00 2.52 24.70R3390.00 WA 12,982 43
13.00 10.00 5.60 8.10L2.5392.01 WA 2,081 44
16.00 10.00 5.07 9.60L2.5392.05 WA 4,989 45
33.00 15.00 2.38 24.10S0.5392.09 WA 756 46
10.00 10.00 5.66 7.30R4396.03 WA 1,845 47
13.00 15.00 6.03 8.00L1.5396.07 WA 6,276 48
50.00 1.98 43.40SQ389.20 WY 74 49
58.00 -15.00 1.95 47.70R1390.00 WY 11,207 50
FERC FORM NO. 1 (REV. 12-03) Page 337.11
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2016/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)
13.00 10.00 5.85 6.10S1.5392.01 WY 4,968 12
15.00 10.00 5.66 9.20L1.5392.05 WY 6,736 13
34.00 5.00 2.68 23.20L2392.09 WY 3,642 14
9.00 15.00 8.47 5.30L3396.03 WY 4,416 15
15.00 25.00 4.86 11.60L0396.07 WY 35,874 16
60.00 -20.00 1.71 46.30R3390.00 CA 3,322 17
10.00 20.00 3.48 6.60S3392.01 CA 825 18
15.00 15.00 4.49 9.10L2392.05 CA 1,238 19
35.00 5.00 2.32 26.20R2392.09 CA 488 20
8.00 15.00 7.20 4.30R4396.03 CA 1,220 21
14.00 15.00 4.98 9.20L1.5396.07 CA 3,038 22
45.00 2.03 36.20S0389.20 UT 85 23
58.00 5.00 1.53 44.60R1390.00 UT 92,677 24
12.00 10.00 5.04 5.50L3392.01 UT 16,552 25
16.00 10.00 4.56 9.20L2392.05 UT 22,739 26
34.00 25.00 1.91 22.40L2392.09 UT 7,780 27
10.00 64.00 2.51 5.30SQ392.30 UT 3,076 28
9.00 10.00 8.10 5.70L3396.03 UT 8,573 29
14.00 15.00 5.36 9.90L0.5396.07 UT 52,571 30
55.00 1.17 25.10R3389.20 ID 5 31
58.00 -5.00 1.65 43.40R1390.00 ID 12,821 32
12.00 10.00 4.28 7.00S2392.01 ID 2,672 33
15.00 15.00 4.34 8.80L2392.05 ID 3,283 34
34.00 10.00 2.28 24.40L2392.09 ID 1,058 35
9.00 10.00 7.67 5.90L3396.03 ID 2,467 36
18.00 25.00 3.73 13.10L0.5396.07 ID 7,112 37
AZ, CO, MT, Etc. 38
45.00 1.51 25.10R2390.00 385 39
16.00 2.53 10.70R2392.01 587 40
19.00 15.00 2.10 13.70R2.5392.05 319 41
25.00 2.18 12.80R1.5392.09 9 42
25.00 5.00 1.86 17.80R2396.07 2,390 43
All States 44
20.00 5.00391.00 27,571 45
5.00 20.00391.20 46,551 46
8.00 12.50391.30 492 47
25.00 4.00393.00 15,364 48
24.00 4.17394.00 63,198 49
20.00 5.00395.00 32,518 50
FERC FORM NO. 1 (REV. 12-03) Page 337.12
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2016/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)
24.00 4.30397.00 423,406 12
11.00 9.09397.20 11,934 13
20.00 5.00398.00 7,995 14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.13
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, 2016, depreciation expense associated with transportation equipment was
$14,483,977.
Schedule Page: 336 Line No.: 12 Column: e
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as
either a regulatory asset or liability.
Schedule Page: 336 Line No.: 12 Column: a
The Oregon Public Utility Commission required modifications related to the depreciable
lives of coal-fired generating facilities. Below are the affected facilities and the lives
and rates required by Oregon.
Account
No.
(a)
Depreciable
Plant Base
(In Thousands)
(b)
Estimated
Avg.
Service
Life
(c)
Net
Salvage
(Percent)
(d)
Applied
Depr.
rates
(Percent)
(e)
Mortality
Curve
Type
(f)
Average
Remaining
Life
(g)
STEAM PRODUCTION PLANT
Cholla Plant
310.20 AZ 1,368 5.72 15.00
311.00 AZ 64,183 -5.00 4.04 14.70
312.00 AZ 339,497 -4.00 4.94 14.20
314.00 AZ 67,634 -5.00 4.67 13.80
315.00 AZ 68,727 -4.00 3.98 14.60
316.00 AZ 4,094 -5.00 4.92 13.00
Colstrip Plant
311.00 MT 61,428 -5.00 2.31 18.40
312.00 MT 119,477 -5.00 2.81 16.80
314.00 MT 38,426 -6.00 3.34 17.00
315.00 MT 9,224 -4.00 2.16 18.20
316.00 MT 397 -6.00 3.24 15.70
Craig Plant
311.00 CO 38,324 -5.00 2.92 12.70
312.00 CO 96,437 -5.00 4.37 12.20
314.00 CO 28,715 -6.00 5.06 12.20
315.00 CO 17,066 -4.00 2.80 12.60
316.00 CO 1,240 -6.00 3.98 11.30
Dave Johnston Plant
310.20 WY 100 3.18 10.00
311.00 WY 158,156 -4.00 7.50 9.90
312.00 WY 689,845 -4.00 7.66 9.80
314.00 WY 96,287 -4.00 6.32 9.60
315.00 WY 62,765 -3.00 7.70 9.90
316.00 WY 8,418 -4.00 7.69 9.30
Hayden Plant
311.00 CO 17,688 -5.00 7.49 9.90
312.00 CO 82,794 -5.00 4.62 9.60
314.00 CO 9,633 -5.00 5.65 9.60
315.00 CO 2,555 -4.00 2.59 9.70
316.00 CO 637 -5.00 4.36 9.00
Hunter Plant
310.20 UT 246 2.43 16.00
311.00 UT 209,648 -6.00 2.84 15.50
312.00 UT 758,565 -5.00 4.36 15.00
314.00 UT 200,440 -6.00 4.84 15.00
315.00 UT 107,848 -5.00 2.88 15.40
316.00 UT 3,691 -6.00 4.00 13.50
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Huntington Plant
311.00 UT 124,429 -7.00 3.06 16.50
312.00 UT 563,304 -6.00 4.70 16.10
314.00 UT 123,318 -7.00 4.37 15.70
315.00 UT 47,559 -5.00 3.51 16.50
316.00 UT 2,890 -6.00 4.77 14.70
Jim Bridger Plant
310.20 WY 281 2.43 12.00
311.00 WY 145,500 -7.00 3.19 11.70
312.00 WY 957,963 -6.00 4.85 11.40
314.00 WY 204,971 -7.00 5.78 11.50
315.00 WY 60,997 -6.00 3.36 11.70
316.00 WY 4,187 -7.00 4.71 10.60
Naughton Plant
310.20 WY 15 1.60 15.00
311.00 WY 119,098 -5.00 4.63 14.80
312.00 WY 512,916 -5.00 5.21 14.40
314.00 WY 82,508 -6.00 4.44 14.00
315.00 WY 65,202 -4.00 5.46 14.80
316.00 WY 2,331 -5.00 5.38 13.10
Wyodak Plant
310.20 WY 165 2.84 13.00
311.00 WY 51,567 -4.00 3.41 12.70
312.00 WY 312,349 -3.00 5.43 12.40
314.00 WY 66,458 -4.00 5.27 12.20
315.00 WY 28,640 -3.00 4.34 12.70
316.00 WY 1,237 -4.00 6.52 11.80
Schedule Page: 336.3 Line No.: 38 Column: a
The depreciation rate changes for the Klamath hydroelectric system’s four mainstem dams
(JC Boyle, Iron Gate, Copco No. 1 and Copco No. 2). For further discussion, refer to Note
13 of Notes to Financial Statements in this Form No. 1.
Schedule Page: 336.8 Line No.: 25 Column: a
High Plains and McFadden Ridge I wind plants
Schedule Page: 336.8 Line No.: 43 Column: a
Seven Mile Hill and Seven Mile Hill II wind plants
Schedule Page: 336.13 Line No.: 16 Column: a
FERC Sub Acct Description
310.20 Land Rights
330.20 Land Rights
330.30 Water Rights
330.40 Flood Rights
330.50 Fish/Wildlife
350.20 Land Rights
360.20 Land Rights
369.10 Overhead Services
369.20 Underground Services
389.20 Land Rights
391.20 Personal Computers and Printers
391.30 Office Equipment
392.01 Transportation Equipment - Light Trucks and Vans
392.05 Transportation Equipment - Medium Trucks
392.09 Transportation Equipment - Trailers
392.30 Aircraft
396.03 Light Power Operated Equipment
396.07 Heavy Power Operated Equipment
397.20 Mobile Radio Equipment
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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
REGULATORY COMMISSION EXPENSES
PacifiCorp X
/ /2016/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 5,883,815 5,883,815 2
Rate Cases and Proceedings 635,251 635,251 3
4
Oregon Public Utility Commission: 5
Annual Fee 3,375,083 3,375,083 6
Rate Cases and Proceedings 1,355,979 1,355,979 7
1,442,958 Deferred Intervenor Funding Grants (1) 1,290,508 1,290,508 8
9
Wyoming Public Service Commission: 10
Annual Fee 1,728,796 1,728,796 11
Rate Cases and Proceedings 241,290 241,290 12
13
Washington Utilities and Transportation 14
Commission: 15
Annual Fee 663,716 663,716 16
Rate Cases and Proceedings 1,062,472 1,062,472 17
18
Idaho Public Utilities Commission: 19
Annual Fee 616,685 616,685 20
Rate Cases and Proceedings 29,228 29,228 21
26,865 Deferred Intervenor Funding Grants 22
23
California Public Utilities Commission: 24
Annual Fee 428 428 25
Rate Cases and Proceedings 206,410 206,410 26
40,406 Deferred Intervenor Funding Grants 27
28
California Environmental Protection Agency: 29
Industry Compliance Fee 8,149 11,688 19,837 30
31
Multi-State: 32
Rate Cases and Proceedings 290,475 290,475 33
Other Regulatory 2,469,236 2,469,236 34
35
Federal Energy Regulatory Commission: 36
Annual Fee 1,913,622 1,913,622 37
Annual Fee - Hydroelectric Plants 2,289,581 2,289,581 38
Transmission Rate Cases 206,206 206,206 39
Other Regulatory 983,203 983,203 40
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96) Page 350
46 TOTAL 16,479,875 8,781,946 25,261,821 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
REGULATORY COMMISSION EXPENSES (Continued)
PacifiCorp X
/ /2016/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 5,883,815928
Electric 3 635,251928
4
5
Electric 6 3,375,083928
Electric 7 1,355,979928
410,913 1,290,508928 258,463Electric 8 1,290,508928
9
10
Electric 11 1,728,796928
Electric 12 241,290928
13
14
15
Electric 16 663,716928
Electric 17 1,062,472928
18
19
Electric 20 616,685928
Electric 21 29,228928
26,865 22
23
24
Electric 25 428928
Electric 26 206,410928
40,605 199 27
28
29
Electric 30 19,837928
31
32
Electric 33 290,475928
Electric 34 2,469,236928
35
36
Electric 37 1,913,622928
Electric 38 2,289,581928
Electric 39 206,206928
Electric 40 983,203928
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96) Page 351
46 25,261,821 258,662 1,290,508 478,383
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
/ /2016/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
/ /2016/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 18,000 557 18,000
4
9,340 5 8,170 17,510
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
Schedule Page: 352 Line No.: 5 Column: e
Account 920, Administrative and general salaries
Account 921, Office supplies and expenses
Account 930.2, Miscellaneous general expenses
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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
DISTRIBUTION OF SALARIES AND WAGES
PacifiCorp X
/ /2016/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
98,112,599Production 3
15,940,794Transmission 4
Regional Market 5
37,509,679Distribution 6
36,465,651Customer Accounts 7
6,453,618Customer Service and Informational 8
Sales 9
36,907,660Administrative and General 10
231,390,001TOTAL Operation (Enter Total of lines 3 thru 10) 11
Maintenance 12
46,060,558Production 13
11,350,883Transmission 14
Regional Market 15
60,919,466Distribution 16
1,803,223Administrative and General 17
120,134,130TOTAL Maintenance (Total of lines 13 thru 17) 18
Total Operation and Maintenance 19
144,173,157Production (Enter Total of lines 3 and 13) 20
27,291,677Transmission (Enter Total of lines 4 and 14) 21
Regional Market (Enter Total of Lines 5 and 15) 22
98,429,145Distribution (Enter Total of lines 6 and 16) 23
36,465,651Customer Accounts (Transcribe from line 7) 24
6,453,618Customer Service and Informational (Transcribe from line 8) 25
Sales (Transcribe from line 9) 26
38,710,883Administrative and General (Enter Total of lines 10 and 17) 27
351,524,131 351,524,131TOTAL 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
/ /2016/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
351,524,131 351,524,131TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65
Utility Plant 66
Construction (By Utility Departments) 67
146,930,576 146,930,576Electric Plant 68
Gas Plant 69
Other (provide details in footnote): 70
146,930,576 146,930,576TOTAL Construction (Total of lines 68 thru 70) 71
Plant Removal (By Utility Departments) 72
9,093,942 9,093,942Electric Plant 73
Gas Plant 74
Other (provide details in footnote): 75
9,093,942 9,093,942TOTAL Plant Removal (Total of lines 73 thru 75) 76
Other Accounts (Specify, provide details in footnote): 77
4,097,632 4,097,632Fuel Stock 78
317,159 317,159Miscellaneous Other Income Deductions 79
671,391 671,391Miscellaneous Non-Operating and Non-Utility 80
2,247,345 2,247,345Charges to Affiliates 81
82
83
84
85
86
87
88
89
90
91
92
93
94
7,333,527 7,333,527TOTAL Other Accounts 95
514,882,176 514,882,176TOTAL 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
/ /2016/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 ( 345,612) 670 ( 348,859)
Net Sales (Account 447) 3 ( 285,074)( 36,876) ( 65,635) ( 5,674)
Transmission Rights 4
Ancillary Services 5
Other Items (list separately) 6
Energy Imbalance Market (Account 555) 7 ( 44,490,036)( 5,579,386) ( 8,396,637) ( 25,701,586)
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
( 45,120,722)( 5,616,262) ( 8,461,602) ( 26,056,119)
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
/ /2016/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
12,368,812MWh140,841,810Scheduling, System Control and Dispatch 1
8,437,982MWh 30,315,023 7,926,328MWh 22,130,990Reactive Supply and Voltage 2
35,383,473MWh104,304,475 31,468,440MWh 94,005,892Regulation and Frequency Response 3
37,549,419MWh 531,534Energy Imbalance 4
48,682,409MWh124,766,043 46,471,174MWh119,156,856Operating Reserve - Spinning 5
41,800,163MWh122,872,091 40,513,331MWh119,156,856Operating Reserve - Supplement 6
Other 7
184,222,258523,630,976126,379,273354,450,594Total (Lines 1 thru 7) 8
FERC FORM NO. 1 (New 2-04) Page 398
PacifiCorp
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 / /2016/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
976 1,535 3,545 141 8,5591800 4 14,756January 1
1,145 1,525 3,545 140 8,290 800 2 14,645February 2
1,141 1,351 3,545 127 7,490 80029 13,654March 3
3,262 4,411 10,635 408 24,339Total for Quarter 1 4
868 1,363 3,545 108 7,096100014 12,980April 5
908 1,521 3,545 111 7,783170031 13,868May 6
2,204 1,873 3,703 137 10,181160028 18,098June 7
3,980 4,757 10,793 356 25,060Total for Quarter 2 8
2,222 1,911 3,650 398 10,402170028 18,583July 9
1,665 1,867 3,650 374 9,997170016 17,553August 10
1,738 1,595 3,650 332 8,8251500 1 16,140September 11
5,625 5,373 10,950 1,104 29,224Total for Quarter 3 12
981 1,258 3,650 360 7,260 80019 13,509October 13
1,188 1,454 3,493 443 8,093180030 14,671November 14
1,074 1,497 3,493 550 8,914180019 15,528December 15
3,243 4,209 10,636 1,353 24,267Total for Quarter 4 16
16,110 18,750 43,014 3,221 102,890
Total Year to
Date/Year
17
FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400
Schedule Page: 400 Line No.: 1 Column: d
Pacific Standard Time.
Schedule Page: 400 Line No.: 2 Column: d
Pacific Standard Time.
Schedule Page: 400 Line No.: 3 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 5 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 6 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 7 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 9 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 10 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 11 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 13 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 14 Column: d
Pacific Standard Time.
Schedule Page: 400 Line No.: 15 Column: d
Pacific Standard Time.
Schedule Page: 400 Line No.: 17 Column: e
Year-to-date 2016 Net System Load information was compiled using metering and/or
scheduling data. Reflects actual peak not 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 2016 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 2016 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 2016 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 2016 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
2016/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
/ /2016/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
40,071,650Steam3
Nuclear4
3,847,042Hydro-Conventional5
Hydro-Pumped Storage6
9,655,266Other7
3,617Less Energy for Pumping8
53,570,341Net Generation (Enter Total of lines 3
through 8)
9
11,939,781Purchases10
Power Exchanges:11
5,901,498Received12
6,217,758Delivered13
-316,260Net Exchanges (Line 12 minus line 13)14
Transmission For Other (Wheeling)15
13,233,893Received16
13,121,145Delivered17
112,748Net Transmission for Other (Line 16 minus
line 17)
18
-355,701Transmission By Others Losses19
64,950,909TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
20
DISPOSITION OF ENERGY21
54,317,937Sales to Ultimate Consumers (Including
Interdepartmental Sales)
22
25,550Requirements Sales for Resale (See
instruction 4, page 311.)
23
6,615,415Non-Requirements Sales for Resale (See
instruction 4, page 311.)
24
Energy Furnished Without Charge25
199,685Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
26
3,792,322Total Energy Losses27
64,950,909TOTAL (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 / /2016/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 4 8,342 852,302 1800 PST 6,094,203
February 30 2 8,068 709,000 0800 PST 5,297,964
March 31 15 7,211 323,345 0800 PDT 4,842,980
April 32 26 6,833 338,775 0800 PDT 4,594,802
May 33 31 7,463 408,120 1700 PDT 4,895,352
June 34 28 9,881 287,797 1600 PDT 5,441,229
July 35 28 10,139 492,881 1700 PDT 6,076,173
August 36 1 9,688 415,688 1700 PDT 5,893,836
September 37 1 8,512 610,867 1500 PDT 5,200,709
October 38 19 6,971 817,586 0800 PDT 5,483,188
November 39 30 7,858 584,824 1800 PST 4,943,360
December 40 14 8,708 774,230 1800 PST 6,187,113
FERC FORM NO. 1 (ED. 12-90) Page 401b
41 TOTAL 64,950,909 6,615,415
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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
ColstripCholla
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2016/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
ConventionalFull Outdoor 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
19841981 3 Year Originally Constructed
19861981 4 Year Last Unit was Installed
155.61414.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
164378 6 Net Peak Demand on Plant - MW (60 minutes)
84836513 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
148395 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
00 11 Average Number of Employees
10356620001740097000 12 Net Generation, Exclusive of Plant Use - KWh
17886442635317 13 Cost of Plant: Land and Land Rights
6135781065162618 14 Structures and Improvements
167304941479923309 15 Equipment Costs
1033405718682010 16 Asset Retirement Costs
240785452566403254 17 Total Cost
1547.36491368.1238 18 Cost per KW of Installed Capacity (line 17/5) Including
397283522859 19 Production Expenses: Oper, Supv, & Engr
1733861743275157 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
10295105702321 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
102060288658 25 Electric Expenses
16445412033796 26 Misc Steam (or Nuclear) Power Expenses
275600 27 Rents
00 28 Allowances
2965442698783 29 Maintenance Supervision and Engineering
4279803378120 30 Maintenance of Structures
30455267088054 31 Maintenance of Boiler (or reactor) Plant
660721732402 32 Maintenance of Electric Plant
4388952248891 33 Maintenance of Misc Steam (or Nuclear) Plant
2505168270969041 34 Total Production Expenses
0.02420.0408 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)
1018837 4409 0 661422 1670 0 38 Quantity (Units) of Fuel Burned
9165 128094 0 8414 140000 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
39.292 82.173 0.000 23.480 77.242 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
42.119 82.173 0.000 26.019 77.242 0.000 41 Average Cost of Fuel per Unit Burned
2.298 15.274 2.314 1.546 13.136 1.556 42 Average Cost of Fuel Burned per Million BTU
0.025 0.000 0.025 0.017 0.000 0.017 43 Average Cost of Fuel Burned per KWh Net Gen
10731.888 13.632 10745.520 10746.890 9.479 10756.369 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.
HaydenDave JohnstonCraig
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
/ /2016/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
SteamSteam Steam 1
Outdoor BoilerOutdoor Boiler Semi-Outdoor 2
19651979 1959 3
19761980 1972 4
81.37172.13 816.77 5
78106 733 6
87848767 8784 7
00 0 8
78165 760 9
00 0 10
00 191 11
4942480001159892000 5088505000 12
683069137086 10449793 13
1764889738313686 157936331 14
95517478143421146 856642283 15
53236335149 15604693 16
114381807181907067 1040633100 17
1405.70001056.8005 1274.0834 18
146701433775 364573 19
1251736521723740 59076306 20
00 0 21
11673161772870 4899813 22
00 0 23
00 0 24
118464831130 0 25
5420101151556 15395646 26
00 140452 27
00 0 28
172799866431 0 29
472020585002 1997073 30
12015283685825 8561766 31
4366991193162 8382540 32
461038955745 1112630 33
1723594033199236 99930799 34
0.03490.0286 0.0196 35
Coal Oil Composite Coal Oil CompositeCoal Oil Composite 36
Tons Barrels Tons BarrelsTons Barrels 37
580610 103 0 240019 281 03533020 14452 0 38
10054 133693 0 11283 137269 08115 138000 0 39
33.982 126.581 0.000 48.039 91.549 0.00016.336 63.737 0.000 40
37.215 126.581 0.000 51.791 91.549 0.00016.460 63.737 0.000 41
1.851 22.554 1.861 2.295 15.878 2.3101.014 10.997 1.029 42
0.019 0.000 0.019 0.025 0.000 0.0250.011 0.000 0.011 43
10065.291 0.500 10065.791 10958.275 3.277 10961.55211268.467 16.461 11284.928 44
FERC FORM NO. 1 (REV. 12-03) Page 403
Hunter Unit No. 2Hunter Unit 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 ofPacifiCorpX
/ /2016/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)
19801978 3 Year Originally Constructed
19801978 4 Year Last Unit was Installed
294.46457.73 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
277427 6 Net Peak Demand on Plant - MW (60 minutes)
82658365 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
269418 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
00 11 Average Number of Employees
18229630002688704000 12 Net Generation, Exclusive of Plant Use - KWh
96882619688261 13 Cost of Plant: Land and Land Rights
5343497564118148 14 Structures and Improvements
245730984379175160 15 Equipment Costs
47728704772870 16 Asset Retirement Costs
313627090457754439 17 Total Cost
1065.09231000.0534 18 Cost per KW of Installed Capacity (line 17/5) Including
00 19 Production Expenses: Oper, Supv, & Engr
3489680153967964 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
57370175847967 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
6580 25 Electric Expenses
-46792881885054 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
24307472562226 30 Maintenance of Structures
43736564524990 31 Maintenance of Boiler (or reactor) Plant
10504481042348 32 Maintenance of Electric Plant
282071503393 33 Maintenance of Misc Steam (or Nuclear) Plant
4409211070333942 34 Total Production Expenses
0.02420.0262 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)
1289443 1897 0 829859 1961 0 38 Quantity (Units) of Fuel Burned
11114 138000 0 11381 138000 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
0.000 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
41.746 0.000 0.000 41.876 0.000 0.000 41 Average Cost of Fuel per Unit Burned
1.878 12.650 1.882 1.840 12.786 1.846 42 Average Cost of Fuel Burned per Million BTU
0.020 0.000 0.020 0.019 0.000 0.019 43 Average Cost of Fuel Burned per KWh Net Gen
10660.410 4.089 10664.499 10362.193 6.235 10368.428 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.
HuntingtonHunter - Total PlantHunter Unit No. 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
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2016/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
SteamSteam Steam 1
Outdoor BoilerOutdoor Boiler Outdoor Boiler 2
19741983 1978 3
19771983 1983 4
996.00495.59 1247.78 5
896490 1380 6
87846987 8784 7
00 0 8
909471 1158 9
00 0 10
1630 215 11
55038900002546078000 7057745000 12
237756410274569 29651091 13
12430575492084593 209637716 14
736891364445391597 1070297741 15
105995604772870 14318610 16
874174242552523629 1323905158 17
877.68501114.8805 1061.0085 18
175950 0 19
12997927350509339 139374104 20
00 0 21
128395795855090 17440074 22
00 0 23
00 0 24
08339 8997 25
47446312824102 29868 26
43810 0 27
00 0 28
21614990 0 29
19152692872565 7865538 30
624973711786609 20685255 31
9822162765405 4858201 32
851235415590 1201054 33
15974541577037039 191463091 34
0.02900.0303 0.0271 35
Coal Oil Composite Coal Oil CompositeCoal Oil Composite 36
Tons Barrels Tons BarrelsTons Barrels 37
1183476 11320 0 2478319 3565 03302778 15178 0 38
11069 138000 0 11386 138000 011165 138000 0 39
0.000 0.000 0.000 51.957 76.637 0.00041.279 75.044 0.000 40
41.957 0.000 0.000 52.336 76.637 0.00041.854 75.044 0.000 41
1.895 13.025 1.923 2.298 13.222 2.3021.874 12.947 1.888 42
0.020 0.000 0.020 0.024 0.000 0.0240.020 0.000 0.020 43
10290.291 25.769 10316.060 10254.034 3.755 10257.78910449.863 12.465 10462.328 44
FERC FORM NO. 1 (REV. 12-03) Page 403.1
NaughtonJim Bridger
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2016/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)
19631974 3 Year Originally Constructed
19711979 4 Year Last Unit was Installed
707.201550.65 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
6571424 6 Net Peak Demand on Plant - MW (60 minutes)
87848782 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
6371415 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
129341 11 Average Number of Employees
48718390008017176000 12 Net Generation, Exclusive of Plant Use - KWh
10437241193761 13 Cost of Plant: Land and Land Rights
119021791145431073 14 Structures and Improvements
6627965811227685417 15 Equipment Costs
4825940219665563 16 Asset Retirement Costs
8311214981393975814 17 Total Cost
1175.2284898.9623 18 Cost per KW of Installed Capacity (line 17/5) Including
39384014293869 19 Production Expenses: Oper, Supv, & Engr
110299322260003235 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
898704918416773 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
83720 25 Electric Expenses
8619089-22603682 26 Misc Steam (or Nuclear) Power Expenses
14350290985 27 Rents
00 28 Allowances
1722723671941 29 Maintenance Supervision and Engineering
21615099398336 30 Maintenance of Structures
1025843525100728 31 Maintenance of Boiler (or reactor) Plant
32204127298168 32 Maintenance of Electric Plant
8771911374619 33 Maintenance of Misc Steam (or Nuclear) Plant
146562292314244972 34 Total Production Expenses
0.03010.0392 35 Expenses per Net KWh
Coal Oil Composite Coal Gas Composite 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
Tons Barrels Tons MCF 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
4573314 12112 0 2637277 20779 0 38 Quantity (Units) of Fuel Burned
9089 138000 0 10060 1045 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
52.340 79.441 0.000 41.773 14.458 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
56.642 79.441 0.000 41.709 14.458 0.000 41 Average Cost of Fuel per Unit Burned
3.116 13.706 3.125 2.073 13.840 2.078 42 Average Cost of Fuel Burned per Million BTU
0.032 0.000 0.032 0.023 0.000 0.023 43 Average Cost of Fuel Burned per KWh Net Gen
10369.428 8.756 10378.184 10891.221 4.455 10895.676 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.
HermistonGadsby SteamWyodak
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
/ /2016/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
Combined CycleSteam Steam 1
OutdoorConventional Outdoor 2
19961978 1951 3
19961978 1955 4
279.56289.66 251.64 5
246274 155 6
34826713 1345 7
00 0 8
231266 238 9
00 0 10
064 35 11
11456560001614214000 63646000 12
842245210526 1252090 13
1284057651512950 15094519 14
163692606408388942 67593009 15
407646652977 1132809 16
177783073460765395 85072427 17
635.93891590.7112 338.0720 18
022952 57329 19
2288725123143888 4109422 20
00 0 21
04198361 113156 22
00 0 23
00 0 24
60055060 0 25
02221871 3252383 26
013157 0 27
00 0 28
00 0 29
01006130 104584 30
06881914 1018008 31
02495800 1090349 32
0208145 138058 33
2889275740192218 9883289 34
0.02520.0249 0.1553 35
Coal Oil Composite GasGas 36
Tons Barrels MCFMCF 37
1229557 2388 0 8370040 0 01095361 0 0 38
8038 138000 0 1033 0 01052 0 0 39
18.544 73.704 0.000 2.734 0.000 0.0003.752 0.000 0.000 40
18.680 73.704 0.000 2.734 0.000 0.0003.752 0.000 0.000 41
1.162 12.717 1.170 2.648 0.000 0.0003.565 0.000 0.000 42
0.014 0.000 0.014 0.020 0.000 0.0000.065 0.000 0.000 43
12245.905 8.576 12254.481 7544.034 0.000 0.00018110.942 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403.2
ChehalisBlundell
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2016/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 CycleSteam - Geothermal 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
OutdoorIndoor 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
20031984 3 Year Originally Constructed
20032007 4 Year Last Unit was Installed
593.3038.10 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
49336 6 Net Peak Demand on Plant - MW (60 minutes)
57768556 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
47732 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
1824 11 Average Number of Employees
1420028000256918000 12 Net Generation, Exclusive of Plant Use - KWh
373052741195596 13 Cost of Plant: Land and Land Rights
241623198293064 14 Structures and Improvements
327045288101535008 15 Equipment Costs
10307772062367 16 Asset Retirement Costs
355968911153086035 17 Total Cost
599.98134018.0062 18 Cost per KW of Installed Capacity (line 17/5) Including
1188114174 19 Production Expenses: Oper, Supv, & Engr
462972390 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
0927990 22 Steam Expenses
04387771 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
19629260 25 Electric Expenses
6887161734057 26 Misc Steam (or Nuclear) Power Expenses
06667 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
33650350635 30 Maintenance of Structures
0461268 31 Maintenance of Boiler (or reactor) Plant
1912719266551 32 Maintenance of Electric Plant
059646 33 Maintenance of Misc Steam (or Nuclear) Plant
510140618198759 34 Total Production Expenses
0.03590.0319 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)
0 0 0 10082022 0 0 38 Quantity (Units) of Fuel Burned
0 0 0 1087 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
0.000 0.000 0.000 4.592 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
0.000 0.000 0.000 4.592 0.000 0.000 41 Average Cost of Fuel per Unit Burned
0.000 0.000 0.000 4.223 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.000 0.000 0.000 0.033 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
0.000 0.000 0.000 7719.488 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.
Lake SideCurrant CreekGadsby Peakers
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
/ /2016/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
Combined CycleGas Turbine Combined Cycle 1
OutdoorOutdoor Outdoor 2
20072002 2005 3
20072002 2006 4
591.30181.05 566.90 5
536127 549 6
86171431 5643 7
00 0 8
546119 524 9
00 0 10
340 20 11
273062200057257000 1474686000 12
145322750 3403277 13
355104944272431 44164698 14
33755119178335474 307118103 15
00 134848 16
38759396082607905 354820926 17
655.4946456.2712 625.8969 18
544270 79526 19
686946713612894 39605139 20
00 0 21
00 0 22
00 0 23
00 0 24
25603421134849 1814398 25
5524640 704055 26
00 0 27
00 0 28
00 0 29
850616235107 782767 30
00 0 31
779374565744 2042672 32
23137243964 64506 33
735150315792558 45093063 34
0.02690.1012 0.0306 35
Gas GasGas 36
MCF MCFMCF 37
741317 0 0 19219074 0 010894332 0 0 38
1047 0 0 1039 0 01037 0 0 39
4.874 0.000 0.000 3.574 0.000 0.0003.635 0.000 0.000 40
4.874 0.000 0.000 3.574 0.000 0.0003.635 0.000 0.000 41
4.653 0.000 0.000 3.440 0.000 0.0003.504 0.000 0.000 42
0.063 0.000 0.000 0.025 0.000 0.0000.027 0.000 0.000 43
13561.573 0.000 0.000 7312.230 0.000 0.0007664.177 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403.3
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 ofPacifiCorpX
/ /2016/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 Cycle 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
Outdoor 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
2014 3 Year Originally Constructed
2014 4 Year Last Unit was Installed
0.00655.20 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
0632 6 Net Peak Demand on Plant - MW (60 minutes)
08509 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
0631 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
00 11 Average Number of Employees
02995420000 12 Net Generation, Exclusive of Plant Use - KWh
016794626 13 Cost of Plant: Land and Land Rights
053126468 14 Structures and Improvements
0569041382 15 Equipment Costs
00 16 Asset Retirement Costs
0638962476 17 Total Cost
0975.2175 18 Cost per KW of Installed Capacity (line 17/5) Including
062897 19 Production Expenses: Oper, Supv, & Engr
071841194 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)
03116374 25 Electric Expenses
0654939 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
0923420 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
0527160 32 Maintenance of Electric Plant
023730 33 Maintenance of Misc Steam (or Nuclear) Plant
077149714 34 Total Production Expenses
0.00000.0258 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)
20181469 0 0 0 0 0 38 Quantity (Units) of Fuel Burned
1039 0 0 0 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
3.560 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
3.560 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned
3.426 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.024 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
7000.074 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 402.4
Schedule Page: 402 Line No.: -1 Column: b
The Cholla Plant is operated by Arizona Public Service Company and is jointly owned.
PacifiCorp owns 100% of Unit No. 4 and 49.53% of common facilities. Data reported on page
402 represents PacifiCorp's share.
Schedule Page: 402 Line No.: -1 Column: c
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 on page 402 represents
PacifiCorp's share.
Schedule Page: 403 Line No.: -1 Column: d
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 reported on page 403 represents PacifiCorp's share.
Schedule Page: 403 Line No.: -1 Column: f
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 on page 403 represents
PacifiCorp's share.
Schedule Page: 402 Line No.: 11 Column: b
PacifiCorp does not have employees at the Cholla Plant.
Schedule Page: 402 Line No.: 11 Column: c
PacifiCorp does not have employees at the Colstrip Plant.
Schedule Page: 403 Line No.: 11 Column: d
PacifiCorp does not have employees at the Craig Plant.
Schedule Page: 403 Line No.: 11 Column: f
PacifiCorp does not have employees at the Hayden Plant.
Schedule Page: 403 Line No.: 20 Column: d
Amount includes intercompany profits.
Schedule Page: 402.1 Line No.: -1 Column: b
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 on page 402.1 represents PacifiCorp's share. Costs that were billed to minority
owners for the operation and maintenance (excluding fuel) of this unit for calendar year
2016 were $1.3 million and were primarily credited to Account 506, Miscellaneous steam
power expenses.
Schedule Page: 402.1 Line No.: -1 Column: c
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 on page
402.1 represents PacifiCorp's share. Costs that were billed to minority owners for the
operation and maintenance (excluding fuel) of this unit for calendar year 2016 were $7.6
million and were primarily credited to Account 506, Miscellaneous steam power expenses.
Schedule Page: 403.1 Line No.: -1 Column: e
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
Refer to Hunter - Total Plant on page 403.1 for the average number of employees.
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: 402.2 Line No.: -1 Column: b
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 on page 402.2 represents PacifiCorp's share. Costs that were billed to minority
owners for the operation and maintenance (excluding fuel) of this plant for calendar year
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
2016 were $27.6 million and were primarily credited to Account 506, Miscellaneous steam
power expenses.
Schedule Page: 402.2 Line No.: -1 Column: c
PacifiCorp currently plans to remove Naughton Unit No. 3 (280 MW) from coal-fueled service
by year-end 2018. The state of Wyoming approved the unit to operate as a coal-fueled unit
until no later than January 30, 2019, and then either close or be converted to natural gas
no later than June 30, 2019.
Schedule Page: 403.2 Line No.: -1 Column: d
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 reported
on page 403.2 represents PacifiCorp's share. Costs that were billed to minority owners for
the operation and maintenance (excluding fuel) of this plant for calendar year 2016 were
$5.1 million and were primarily credited to Account 506, Miscellaneous steam power
expenses.
Schedule Page: 403.2 Line No.: -1 Column: f
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 on page 403.2
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: 403.2 Line No.: 11 Column: f
PacifiCorp does not have employees at the Hermiston Plant.
Schedule Page: 402.2 Line No.: 20 Column: b
Amount includes intercompany profits.
Schedule Page: 402.3 Line No.: -1 Column: b
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.: 11 Column: d
Refer to the Gadsby Steam Plant on page 403.2 for the average number of employees.
Schedule Page: 402.4 Line No.: 11 Column: b
Refer to the Lake Side Plant on page 403.3 for the average number of employees.
Schedule Page: 402 Line No.: 36 Column: b2
Cholla - Fuel oil is used for start-up purposes.
Schedule Page: 402 Line No.: 36 Column: c2
Colstrip - Fuel oil is used for start-up purposes.
Schedule Page: 402 Line No.: 36 Column: d2
Craig - Fuel oil is used for start-up purposes.
Schedule Page: 402 Line No.: 36 Column: e2
Dave Johnston - Fuel oil is used for start-up purposes.
Schedule Page: 402 Line No.: 36 Column: f2
Hayden - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: b2
Hunter Unit No. 1 - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: c2
Hunter Unit No. 2 - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: d2
Hunter Unit No. 3 - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: e2
Hunter - Total Plant - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: f2
Huntington - Fuel oil is used for start-up purposes.
Schedule Page: 402.2 Line No.: 36 Column: b2
Jim Bridger - Fuel oil is used for start-up purposes.
Schedule Page: 402.2 Line No.: 36 Column: c2
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Naughton - Natural gas is used for start-up purposes.
Schedule Page: 402.2 Line No.: 36 Column: d2
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
2016/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
/ /2016/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 26 32
Plant Hours Connect to Load 7 7,136 7,156
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 80,964,000 104,792,000
Cost of Plant 13
Land and Land Rights 14 107,019 20,914
Structures and Improvements 15 1,698,921 2,340,917
Reservoirs, Dams, and Waterways 16 2,935,836 2,953,166
Equipment Costs 17 5,358,060 10,442,760
Roads, Railroads, and Bridges 18 133,348 479,588
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 10,233,184 16,237,345
Cost per KW of Installed Capacity (line 20 / 5) 21 511.6592 601.3831
Production Expenses 22
Operation Supervision and Engineering 23 29,572 41,134
Water for Power 24 0 0
Hydraulic Expenses 25 25,366 34,245
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 1,254,452 1,560,385
Rents 28 30,813 41,597
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 5,332 25,379
Maintenance of Reservoirs, Dams, and Waterways 31 207,498 24,869
Maintenance of Electric Plant 32 91,481 108,125
Maintenance of Misc Hydraulic Plant 33 20,220 26,257
Total Production Expenses (total 23 thru 33) 34 1,664,734 1,861,991
Expenses per net KWh 35 0.0206 0.0178
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
/ /2016/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
19 308 6
8,363 6,4368,770 7
8
31 2918 9
31 2918 10
1 31 11
45,439,000 64,221,00040,459,000 12
13
0 3,511,1050 14
2,373,755 3,985,3181,502,236 15
14,779,679 9,177,6875,183,909 16
2,155,970 14,698,3561,337,839 17
250,151 572,05950,817 18
0 00 19
19,559,555 31,944,5258,074,801 20
752.2906 1,064.8175538.3201 21
22
44,326 141,83323,562 23
1,213 0700 24
73,439 113,41242,368 25
0 00 26
376,661 1,224,554255,058 27
98,156 20,28656,629 28
0 00 29
50,817 1323,982 30
41,569 33,00113,831 31
103,015 26,63413,737 32
62,238 326,27035,812 33
851,434 1,886,003465,679 34
0.0187 0.02940.0115 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
/ /2016/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a
footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Kind of Plant (Run-of-River or Storage) 1 Run-of-River Storage
Plant Construction type (Conventional or Outdoor) 2 Outdoor Conventional
Year Originally Constructed 3 1952 1908
Year Last Unit was Installed 4 1952 1923
Total installed cap (Gen name plate Rating in MW) 5 11.00 33.00
Net Peak Demand on Plant-Megawatts (60 minutes) 6 10 29
Plant Hours Connect to Load 7 4,525 7,883
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 34,839,000 78,074,000
Cost of Plant 13
Land and Land Rights 14 0 62,169
Structures and Improvements 15 1,757,824 2,085,484
Reservoirs, Dams, and Waterways 16 12,368,032 11,336,864
Equipment Costs 17 2,948,919 5,002,425
Roads, Railroads, and Bridges 18 533,015 335,165
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 17,607,790 18,822,107
Cost per KW of Installed Capacity (line 20 / 5) 21 1,600.7082 570.3669
Production Expenses 22
Operation Supervision and Engineering 23 26,268 119,767
Water for Power 24 513 0
Hydraulic Expenses 25 31,070 41,560
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 237,567 1,308,135
Rents 28 41,528 12,321
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 27,957 16,515
Maintenance of Reservoirs, Dams, and Waterways 31 62,948 146,804
Maintenance of Electric Plant 32 47,873 64,424
Maintenance of Misc Hydraulic Plant 33 28,695 114,945
Total Production Expenses (total 23 thru 33) 34 504,419 1,824,471
Expenses per net KWh 35 0.0145 0.0234
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
/ /2016/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
86 2818 6
5,949 8,2768,332 7
8
83 3219 9
83 3219 10
2 11 11
214,776,000 134,067,000100,752,000 12
13
25,845 0341,706 14
3,675,180 2,931,0947,842,418 15
15,655,267 15,717,07015,308,188 16
15,370,749 6,717,8563,035,214 17
886,710 488,8771,095,742 18
0 00 19
35,613,751 25,854,89727,623,268 20
363.4798 808.21811,534.6260 21
22
215,039 51,8661,551,839 23
0 1,4920 24
10,328 90,35823,633 25
0 00 26
605,023 493,1501,060,957 27
46,573 120,77027,731 28
0 00 29
26,379 59,7563,923 30
28,145 55,65915,200 31
69,187 115,530131,212 32
53,310 79,17518,290 33
1,053,984 1,067,7562,832,785 34
0.0049 0.00800.0281 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
/ /2016/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 34 143
Plant Hours Connect to Load 7 6,831 8,784
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 12 146,665,000 560,116,000
Cost of Plant 13
Land and Land Rights 14 0 988,614
Structures and Improvements 15 6,198,165 105,535,586
Reservoirs, Dams, and Waterways 16 32,523,973 30,135,690
Equipment Costs 17 11,839,981 18,212,123
Roads, Railroads, and Bridges 18 1,820,580 3,958,128
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 52,382,699 158,830,141
Cost per KW of Installed Capacity (line 20 / 5) 21 1,360.5896 1,167.8687
Production Expenses 22
Operation Supervision and Engineering 23 61,515 1,504,076
Water for Power 24 1,795 6,354
Hydraulic Expenses 25 108,745 792,916
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 631,228 466,962
Rents 28 145,347 89,475
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 77,338 55,771
Maintenance of Reservoirs, Dams, and Waterways 31 283,946 168,377
Maintenance of Electric Plant 32 95,190 102,972
Maintenance of Misc Hydraulic Plant 33 92,807 342,889
Total Production Expenses (total 23 thru 33) 34 1,497,911 3,529,792
Expenses per net KWh 35 0.0102 0.0063
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
/ /2016/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 3644 6
8,739 8,7808,778 7
8
28 3645 9
28 3645 10
2 11 11
39,854,000 239,892,000232,820,000 12
13
283,870 105,1680 14
1,893,716 3,541,9964,124,365 15
6,316,949 33,191,50512,843,068 16
6,473,188 7,057,0635,556,855 17
503,332 325,034264,441 18
0 00 19
15,471,055 44,220,76622,788,729 20
515.7018 1,381.8989536.2054 21
22
108,696 304,28467,093 23
0 8,1131,982 24
37,782 3,434120,047 25
0 00 26
658,157 493,591699,147 27
10,746 38,440160,515 28
0 2740 29
4,839 94,02969,090 30
1,371 279,16215,348 31
131,803 116,196196,230 32
65,963 244,289102,006 33
1,019,357 1,581,8121,431,458 34
0.0256 0.00660.0061 35
FERC FORM NO. 1 (REV. 12-03) Page 407.2
20
Soda
1927
Slide Creek
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2016/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 9
Plant Hours Connect to Load 7 8,750 7,243
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 75,625,000 17,769,000
Cost of Plant 13
Land and Land Rights 14 0 511,083
Structures and Improvements 15 2,203,571 730,462
Reservoirs, Dams, and Waterways 16 14,877,385 10,596,080
Equipment Costs 17 8,967,103 5,424,548
Roads, Railroads, and Bridges 18 599,269 0
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 26,647,328 17,262,173
Cost per KW of Installed Capacity (line 20 / 5) 21 1,480.4071 1,194.6140
Production Expenses 22
Operation Supervision and Engineering 23 34,426 50,725
Water for Power 24 839 0
Hydraulic Expenses 25 50,842 17,631
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 279,624 406,108
Rents 28 67,954 5,093
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 31,097 35
Maintenance of Reservoirs, Dams, and Waterways 31 3,815 678
Maintenance of Electric Plant 32 21,287 57,164
Maintenance of Misc Hydraulic Plant 33 46,383 20,081
Total Production Expenses (total 23 thru 33) 34 536,267 557,515
Expenses per net KWh 35 0.0071 0.0314
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
/ /2016/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
251 16612 6
6,575 6,7818,719 7
8
264 16412 9
264 16412 10
1 12 11
761,595,000 645,247,00061,093,000 12
13
14,160,894 8,363,0130 14
72,443,760 16,284,5244,238,679 15
47,054,071 32,328,23389,513,753 16
24,720,736 16,623,8582,631,607 17
1,133,091 2,036,6482,089,012 18
0 00 19
159,512,552 75,636,27698,473,051 20
664.6356 564.44988,952.0955 21
22
2,530,560 1,390,62917,279 23
11,212 6,260513 24
1,657,547 781,255272,745 25
0 00 26
282,744 353,834317,094 27
157,897 88,15941,528 28
0 00 29
40,308 36,48115,777 30
306,251 171,80455,661 31
216,802 184,09113,497 32
580,305 330,25626,263 33
5,783,626 3,342,769760,357 34
0.0076 0.00520.0124 35
FERC FORM NO. 1 (REV. 12-03) Page 407.3
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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 / /2016/Q4
Line
No.Name of Plant
Installed Capacity
(c)(b)(a)
Cost of PlantNet PeakDemand
(d)
YearOrig.Const.Name Plate Rating
(In MW)MW(60 min.)
Net GenerationExcludingPlant Use
(e) (f)
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give
project number in footnote.
Hydroelectric : Licensed Proj. No. 1
6.70 7.0 28,779,000 33,880,3971917Ashton 2381 2
1.11 1.0 1,958,000 1,970,0341913Bend 3
4.15 4.6 29,483,000 7,592,4051910Big Fork 2652 4
2.81 2.8 18,526,000 1,948,8441957Eagle Point 5
3.20 1,991,6951924East Side 2082 6
2.20 2.0 10,146,000 1,429,4571903Fall Creek 2082 7
2.00 1.3 6,219,000 5,238,1881896Granite 8
0.75 0.5 856,000 683,0451917Gunlock 9
1.73 0.4 1,162,000 2,804,6291983Last Chance 10
0.72 0.7 2,417,000 448,9461910Paris 11
5.00 3.4 11,369,000 11,442,4691897Pioneer 2722 12
3.76 2,590,6601912Prospect No. 1 2630 13
7.20 7.7 32,997,000 8,896,8431932Prospect No. 3 2337 14
1.00 2,409,7921944Prospect No. 4 2630 15
0.80 0.5 702,000 939,2021926Sand Cove 16
1.00 1.0 4,544,000 1,721,7381895Stairs 597 17
0.50 0.2 249,000 897,7841920Veyo 18
0.74 0.2 641,000 1,232,1151986Viva Naughton 19
1.10 1.1 4,340,000 3,277,3171921Wallowa Falls 308 20
3.85 2.0 13,611,000 3,638,1491911Weber 1744 21
0.60 0.6 -16,000 468,5741908West Side 2082 22
7,519,318Keno Regulating Dam 2082 23
3,847,587Upper Klamath Lake 2082 24
16,329,447North Umpqua 1927 25
26
Pumping Plant: 27
-2.80 -1.0 -3,617,000 19,494,6061917Lifton 28
29
Wind: 30
111.00 111.0 388,498,000 240,971,6452010Dunlap Ranch 1 31
32.15 32.2 108,681,000 38,389,2661999Foote Creek 32
99.00 99.0 311,607,000 203,182,7902008Glenrock 33
39.00 39.0 118,738,000 88,428,9822009Glenrock III 34
99.00 99.0 284,156,000 205,070,7612009Rolling Hills 35
94.00 93.0 223,899,000 184,559,9012008Goodnoe Hills 36
100.00 100.5 202,605,000 179,176,3322006Leaning Juniper 1 37
140.40 136.0 356,053,000 242,241,5852007Marengo 38
70.20 69.0 170,369,000 130,052,2842008Marengo II 39
99.00 99.0 348,841,000 202,089,6712008Seven Mile Hill 40
19.50 19.5 69,847,000 42,464,8722008Seven Mile Hill II 41
99.00 99.0 316,175,000 220,356,6692009High Plains 42
28.50 28.5 95,925,000 57,089,3612009McFadden Ridge I 43
44
Solar: 45
2.00 2.0 4,021,000 74,3802012Black Cap 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 / /2016/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
143,982 5,056,776 2Water 517,860
24,622 1,774,805 3Water 64,572
112,559 1,829,495 4Water 399,815
114,279 693,539 5Water 298,431
2,306 622,405 6Water 36,370
65,543 649,753 7Water 149,315
13,558 2,619,094 8Water 200,589
75,639 910,727 9Water 31,480
9,507 1,621,173 10Water 118,865
17,920 623,536 11Water 75,834
154,215 2,288,494 12Water 534,144
1,991,650 689,005 13Water 112,936
240,168 1,235,673 14Water 285,054
19,185 2,409,792 15Water 28,160
34,745 1,174,003 16Water 69,930
14,050 1,721,738 17Water 182,004
220,279 1,795,568 18Water 35,324
203,044 1,665,020 19Water 144,352
28,945 2,979,379 20Water 118,302
24,994 944,974 21Water 335,076
1,851 780,957 22Water 5,213
1,595 23 24,738
46,832 24 249,116
25
26
27
64,580 -6,962,359 28Water 242,951
29
30
1,197,451 2,170,916 31Wind 242,442
1,300,724 1,194,067 32Wind 452,885
1,371,291 2,052,351 33Wind 221,362
403,639 2,267,410 34Wind 89,729
1,021,585 2,071,422 35Wind 173,853
1,630,110 1,963,403 36Wind 593,516
1,171,752 1,791,763 37Wind 728,462
1,383,131 1,725,367 38Wind 1,180,562
688,622 1,852,597 39Wind 603,480
1,218,502 2,041,310 40Wind 513,885
240,008 2,177,686 41Wind 109,628
1,267,002 2,225,825 42Wind 925,000
417,123 2,003,135 43Wind 264,349
44
45
37,190 46Solar 498,523
FERC FORM NO. 1 (REV. 12-03) Page 411
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.: 22 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.: 23 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.: 24 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.: 25 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.: 28 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.: 30 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.: 32 Column: a
Foote Creek
The Foote Creek wind-powered generating facility is operated by PacifiCorp 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 32 represents PacifiCorp's share.
Schedule Page: 410 Line No.: 46 Column: a
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
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2016/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 500kV costs and expenses
14
1,212.00 12 15 Subtotal 500kV
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 16,964.00 654.00 284
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
/ /2016/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
246,788,115 233,448,416 13,339,699 1,997,700 295,737 1,701,963 13
14
246,788,115 233,448,416 13,339,699 1,997,700 295,737 1,701,963 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
36 234,140,526 3,437,321,298 3,671,461,824 523,824 17,542,520 2,406,374 20,472,718
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
/ /2016/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 82.00 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 2,755.00 41 25 Subtotal 345kV
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 9.00 1 30 ARROWHEAD, WY FIREHOLE, WY
Wood - H 230.00 230.00 1.00 1 31 ATLANTIC CITY, WY COLUMBIA GENEVA, WY
Wood - H 230.00 230.00 88.00 1 32 BEN LOMOND, UT NAUGHTON #1, WY
Wood - H 230.00 230.00 88.00 1 33 BEN LOMOND, UT NAUGHTON #2, WY
Wood - H 230.00 230.00 19.00 1 34 BIRCH CREEK, UT RAILROAD, WY
Wood - H 230.00 230.00 3.00 1 35 BITTER CREEK, WY MONELL, WY
FERC FORM NO. 1 (ED. 12-87) Page 422.1
36 TOTAL 16,964.00 654.00 284
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
/ /2016/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 54/7 18
1272 ACSR 36/1 19
1272 ACSR 45/7 20
1272 ACSR 45/7 21
1272 ACSR 45/7 22
1,808,750,841 1,656,245,596 152,505,245 2,398,107 718,689 1,466,262 213,156 23
24
1,808,750,841 1,656,245,596 152,505,245 2,398,107 718,689 1,466,262 213,156 25
26
1272 ACSR 36/1 27
1272 ACSR 45/7 28
795 ACSR 45/7 29
795 ACSR 26/7 30
1272 ACSR 36/1 31
795 ACSR 26/7 32
795 ACSR 26/7 33
954 ACSR 54/7 34
795 ACSR 26/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.1
36 234,140,526 3,437,321,298 3,671,461,824 523,824 17,542,520 2,406,374 20,472,718
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
/ /2016/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 1.00 1 1 BRIDGER PUMP, WY MANS FACE, WY
Wood - H 230.00 230.00 107.00 1 2 BUFFALO, WY CASPER, WY
Wood - H 230.00 230.00 36.00 1 3 CASPER, WY DAVE JOHNSTON, WY
Wood - H 230.00 230.00 110.00 1 4 CASPER, WY RIVERTON, WY
Steel - SP 230.00 230.00 30.00 1 5 CHAPPEL CREEK, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 32.00 1 6 CHAPPEL CREEK, WY JONAH GAS, WY
Wood - H 230.00 230.00 6.00 29.00 1 7 CHAPPEL CREEK, WY RILEY RIDGE, WY
Wood - H 230.00 230.00 2.00 1 8 CRAVEN CREEK, WY PIONEER, WY
Wood - H 230.00 230.00 31.00 1 9 DAVE JOHNSTON, WY SPENCE, WY
Wood - H 230.00 230.00 69.00 1 10 DAVE JOHNSTON, WY WYODAK, WY
Wood - H 230.00 230.00 1.00 1 11 DIXONVILLE 500kV, OR DIXONVILLE 230kV, OR
Wood - H 230.00 230.00 17.00 1 12 DIXONVILLE, OR RESTON (BPA), OR
Wood - H 230.00 230.00 12.00 1 13 FAIRVIEW (BPA), OR ISTHMUS, OR
Wood - H 230.00 230.00 49.00 1 14 FIREHOLE, WY MONUMENT, WY
Wood - H 230.00 230.00 26.00 1 15 FRY, OR BETHEL, OR
Wood - H 230.00 230.00 45.00 1 16 FRY, OR ALVEY, OR
Wood - H 230.00 230.00 159.00 1 17 GLEN CANYON, AZ SIGURD, UT
Wood - H 230.00 230.00 98.00 1 18 GONDER, UT - NV STATE PAVANT, UT
Wood - H 230.00 230.00 40.00 1 19 BUFFALO, WY SHERIDAN (MDU), WY
Wood - H 230.00 230.00 62.00 1 20 DIXONVILLE, OR GRANTS PASS, OR
Wood - H 230.00 230.00 78.00 1 21 HURRICANE, OR WALLA WALLA, WA
Wood - H 230.00 230.00 209.00 1 22 POINT OF ROCKS, WY DAVE JOHNSTON, WY
Wood - H 230.00 230.00 149.00 1 23 JIM BRIDGER, WY SPENCE, WY
Wood - H 230.00 230.00 35.00 1 24 KLAMATH FALLS, OR MALIN, OR
Wood - H 230.00 230.00 2.00 1 25 LIMA, WY ROBERSON, WY
Wood - H 230.00 230.00 76.00 1 26 LONE PINE, OR KLAMATH FALLS, OR
Steel - SP 230.00 230.00 5.00 1 27 LONE PINE, OR MERIDIAN #1, OR
Steel - SP 230.00 230.00 5.00 1 28 LONE PINE, OR MERIDIAN #2, OR
Wood - H 230.00 230.00 56.00 1 29 MCNARY (BPA), WA WALLA WALLA, WA
Wood - H 230.00 230.00 35.00 1 30 MERIDIAN, OR GRANTS PASS, OR
Wood - H 230.00 230.00 38.00 1 31 HIGH PLAINS, WY STANDPIPE, WY
Wood - H 230.00 230.00 13.00 1 32 MONUMENT, WY EXXON, WY
Wood - H 230.00 230.00 20.00 1 33 MONUMENT, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 80.00 1 34 NAUGHTON, WY TREASURETON, ID
Wood - H 230.00 230.00 30.00 1 35 NAUGHTON, WY MONUMENT, WY
FERC FORM NO. 1 (ED. 12-87) Page 422.2
36 TOTAL 16,964.00 654.00 284
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
/ /2016/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
1272 ACSR 36/1 1
1272 ACSR 36/1 2
3
1272 ACSR 36/1 4
954 ACSR 54/7 5
1272 ACSR 45/7 6
1272 ACSR 45/7 7
1272 ACSR 45/7 8
1272 ACSR 45/7 9
1272 ACSR 36/1 10
1272 ACSR 36/1 11
795 ACSR 26/7 12
1272 ACSR 36/1 13
1272 ACSR 45/7 14
1272 ACSR 36/1 15
1272 ACSR 36/1 16
954 ACSR 45/7 17
795 ACSR 45/7 18
795 ACSR 26/7 19
1272 ACSR 36/1 20
1272 ACSR 36/1 21
1272 ACSR 36/1 22
1272 ACSR 36/1 23
1272 ACSR 36/1 24
1272 ACSR 45/7 25
795 ACSR 26/7 26
1272 ACSR 54/19 27
1272 ACSR 36/1 28
1272 ACSR 36/1 29
1272 ACSR 36/1 30
1272 ACSR 45/7 31
1272 ACSR 36/1 32
1272 ACSR 45/7 33
1272 ACSR 45/7 34
1272 ACSR 36/1 35
FERC FORM NO. 1 (ED. 12-87) Page 423.2
36 234,140,526 3,437,321,298 3,671,461,824 523,824 17,542,520 2,406,374 20,472,718
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
/ /2016/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 16.00 1 1 NAUGHTON, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 4.00 1 2 PALISADES SS, WY BLUE RIM, WY
Wood - H 230.00 230.00 94.00 1 3 PAROWAN VALLEY, UT SIGURD, UT
Wood - H 230.00 230.00 26.00 1 4 PAROWAN VALLEY, UT WEST CEDAR, UT
Wood - H 230.00 230.00 43.00 1 5 PAVANT, UT SIGURD, UT
Wood - H 230.00 230.00 35.00 1 6 JIM BRIDGER, WY ROCK SPRINGS, WY
Wood - H 230.00 230.00 8.00 1 7 POMONA, WA UNION GAP, WA
Wood - H 230.00 230.00 118.00 1 8 RIVERTON, WY ROCK SPRINGS, WY
Wood - H 230.00 230.00 51.00 1 9 RIVERTON, WY THERMOPOLIS, WY
Wood - H 230.00 230.00 55.00 1 10 ROCK SPRINGS, WY FLAMING GORGE, UT
Wood - H 230.00 230.00 35.00 1 11 ROCK SPRINGS, WY JIM BRIDGER, WY
Wood - H 230.00 230.00 41.00 1 12 ROCK SPRINGS, WY MONUMENT, WY
Wood - H 230.00 230.00 12.00 1 13 SHIRLEY BASIN, WY DUNLAP RANCH, WY
Wood - H 230.00 230.00 2.00 1 14 SWIFT No. 1, WA SWIFT No. 2, WA
Wood - H 230.00 230.00 23.00 1 15 SWIFT No. 2, WA WOODLAND (BPA) SS, WA
Wood - H 230.00 230.00 7.00 1 16 TALBOT, WA MARENGO II, WA
Wood - H 230.00 230.00 9.00 1 17 TAP TO HANNA, OR NICKEL MOUNTAIN, OR
Wood - H 230.00 230.00 176.00 1 18 THERMOPOLIS, WY YELLOWTAIL, MT
Wood - H 230.00 230.00 66.00 1 19 TREASURETON, ID BRADY, ID
Steel Tower 230.00 230.00 6.00 1 20 TROUTDALE (BPA), OR GRESHAM (PGE), OR
230.00 230.00 7.00 1 21 TROUTDALE (BPA), OR LINNEMAN (PGE), OR
Wood - H 230.00 230.00 39.00 1 22 UNION GAP, WA MIDWAY (BPA), WA
Wood - H 230.00 230.00 45.00 1 23 WALLA WALLA, WA LEWISTON (AVISTA), ID
Wood - H 230.00 230.00 33.00 1 24 WALLA WALLA, WA WANAPUM (GPUD), WA
Wood - H 230.00 230.00 37.00 1 25 WANAPUM (GPUD), WA POMONA, WA
Wood - H 230.00 230.00 13.00 1 26 WINDSTAR, WY GLENROCK, WY
Wood - H 230.00 230.00 69.00 1 27 WYODAK, WY BUFFALO, WY
Wood - H 230.00 230.00 63.00 1 28 YAMSAY (BPA), OR KLAMATH FALLS, OR
Wood - H 230.00 230.00 62.00 1 29 SHERIDAN (MDU), WY YELLOWTAIL, MT
30 230kV costs and expenses
31
13.00 3,338.00 73 32 Subtotal 230kV
33
Wood - H 161.00 161.00 21.00 1 34 BIG GRASSY, ID JEFFERSON, ID
Wood - H 161.00 161.00 45.00 1 35 ANTELOPE, ID GOSHEN, ID
FERC FORM NO. 1 (ED. 12-87) Page 422.3
36 TOTAL 16,964.00 654.00 284
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
/ /2016/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 54/7 1
1272 ACSR 36/1 2
795 ACSR 45/7 3
795 ACSR 45/7 4
795 ACSR 45/7 5
1272 ACSR 45/7 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
1272 ACSR 36/1 12
795 ACSR 26/7 13
954 ACSR 45/7 14
954 ACSR 45/7 15
795 ACSR 26/7 16
795 ACSR 26/7 17
1272 ACSR 36/1 18
795 ACSR 26/7 19
954 ACSR 45/7 20
900 ACSR 54/7 21
954 ACSR 45/7 22
1272 ACSR 36/1 23
1272 ACSR 36/1 24
1272 ACSR 36/1 25
1272 ACSR 45/7 26
1272 ACSR 36/1 27
795 ACSR 26/7 28
795 ACSR 26/7 29
408,846,384 389,392,423 19,453,961 3,861,618 431,233 3,400,325 30,060 30
31
408,846,384 389,392,423 19,453,961 3,861,618 431,233 3,400,325 30,060 32
33
250HH CU /7 34
397.5 ACSR 26/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.3
36 234,140,526 3,437,321,298 3,671,461,824 523,824 17,542,520 2,406,374 20,472,718
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
/ /2016/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Wood - SP 161.00 161.00 9.00 1 1 BONNEVILLE, ID EAGLEROCK, ID
Wood - H 161.00 161.00 57.00 1 2 GOSHEN, ID GRACE, ID
Wood - H 161.00 161.00 31.00 1 3 GOSHEN, ID RIGBY, ID
Wood - SP 161.00 161.00 17.00 1 4 GOSHEN, ID SUGARMILL, ID
Wood - SP 161.00 161.00 17.00 1 5 SUGARMILL, ID RIGBY, ID
Wood - H 161.00 161.00 15.00 1 6 EAGLEROCK, ID GOSHEN, ID
Wood - H 161.00 161.00 46.00 1 7 YELLOWTAIL, MT RIMROCK, MT
Wood - SP 161.00 161.00 18.00 1 8 RIGBY, ID JEFFERSON, ID
Wood - H 161.00 161.00 30.00 1 9 GOSHEN, ID JEFFERSON, ID
10 161kV costs and expenses
11
51.00 255.00 11 12 Subtotal 161kV
13
Steel - SP 138.00 138.00 1.00 1 14 90TH SOUTH, UT SANDY, UT
Wood - H 138.00 138.00 12.00 1 15 90TH SOUTH, UT DUMAS #1, UT
Wood - H 138.00 138.00 6.00 1 16 90TH SOUTH, UT DUMAS #2, UT
Wood - SP 138.00 138.00 10.00 1 17 90TH SOUTH, UT OQUIRRH, UT
Wood - H 138.00 138.00 44.00 1 18 ABAJO, UT PINTO, UT
Wood - SP 138.00 138.00 10.00 1 19 ABAJO, UT RESOLUTE, UT
Wood - H 138.00 138.00 4.00 1 20 AGRIUM, UT THREEMILE KNOLL, ID
Wood - H 138.00 138.00 22.00 1 21 ANSCHTZ CO-GEN, WY EVANSTON, WY
Wood - H 138.00 138.00 1.00 1 22 ANTELOPE, ID SCOVILLE #1, ID
Wood - H 138.00 138.00 1.00 1 23 ANTELOPE, ID SCOVILLE #2, ID
Wood - H 138.00 138.00 26.00 1 24 ASHGROVE, UT CLOVER, UT
Wood - H 138.00 138.00 102.00 1 25 ASHLEY, UT CARBON, UT
Wood - H 138.00 138.00 12.00 1 26 ASHLEY, UT VERNAL, UT
Wood - H 138.00 138.00 6.00 1 27 BANGERTER, UT OQUIRRH, UT
Wood - SP 138.00 138.00 1.00 1 28 BDO, UT BDO TAP, UT
Wood - H 138.00 138.00 14.00 1 29 BEN LOMOND, UT BRIGHAM CITY, UT
Steel - SP 138.00 138.00 14.00 1 30 BEN LOMOND #1, UT EL MONTE, UT
138.00 138.00 13.00 1 31 BEN LOMOND #2, UT EL MONTE, UT
Steel Tower 138.00 138.00 22.00 1 32 BEN LOMOND, UT HONEYVILLE, UT
Steel Tower 230.00 138.00 13.00 7.00 1 33 BEN LOMOND, UT SYRACUSE #1, UT
Steel - SP 138.00 138.00 28.00 1 34 BEN LOMOND, UT ANGEL, UT
Wood - SP 138.00 138.00 14.00 1 35 BEN LOMOND, UT W ZIRCONIUM, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.4
36 TOTAL 16,964.00 654.00 284
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
/ /2016/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
250HH CU /7 2
397.5 ACSR 26/7 3
795 AAC /37 4
397.5 ACSR 26/7 5
1272 ACSR 45/7 6
556.5 ACSR 26/7 7
397.5 ACSR 26/7 8
250HH CU /7 9
26,450,401 25,826,911 623,490 238,740 1,925 236,815 10
11
26,450,401 25,826,911 623,490 238,740 1,925 236,815 12
13
795 AAC /37 14
795 AAC /37 15
795 AAC /37 16
795 ACSR 26/7 17
397.5 ACSR 26/7 18
795 ACSR 26/7 19
397.5 ACSR 26/7 20
795 ACSR 26/7 21
397.5 ACSR 26/7 22
397.5 ACSR 26/7 23
397.5 ACSR 26/7 24
397.5 ACSR 26/7 25
397.5 ACSR 26/7 26
27
397.5 ACSR 26/7 28
1272 ACSR 45/7 29
795 ACSR 45/7 30
795 ACSR 45/7 31
250 CUHD /12 32
795 AAC /37 33
397.5 ACSR 26/7 34
795 AAC /37 35
FERC FORM NO. 1 (ED. 12-87) Page 423.4
36 234,140,526 3,437,321,298 3,671,461,824 523,824 17,542,520 2,406,374 20,472,718
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
/ /2016/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 138.00 138.00 42.00 1 1 BEN LOMOND, UT WHEELON, UT
Steel Tower 138.00 138.00 25.00 1 2 BEN LOMOND, UT SYRACUSE, UT
Wood - H 138.00 138.00 9.00 1 3 BONANZA, UT CHAPITA, UT
Wood - SP 138.00 138.00 16.00 1 4 BRIDGERLAND, UT GREEN CANYON, UT
Wood - H 138.00 138.00 24.00 1 5 BRIGHAM CITY, UT WHEELON, UT
Steel - SP 138.00 138.00 9.00 1 6 BUTLERVILLE, UT 90TH SOUTH, UT
Wood - H 138.00 138.00 35.00 1 7 CAMERON, UT PAROWAN, UT
Wood - H 138.00 138.00 64.00 1 8 CAMERON, UT SIGURD, UT
Wood - H 138.00 138.00 12.00 1 9 CANYON COMP, WY STR 204, WY
Wood - H 138.00 138.00 2.00 1 10 CARBON, UT HELPER #2, UT
Steel Tower 138.00 138.00 54.00 1 11 CARBON, UT SPANISH FORK #1, UT
Steel Tower 138.00 138.00 52.00 1 12 CARBON, UT SPANISH FORK #2, UT
Wood - H 138.00 138.00 120.00 1 13 CARBON, UT MOAB, UT
Wood - SP 138.00 138.00 5.00 1 14 CLEAR CREEK, WY PAINTER, UT
Wood - SP 138.00 138.00 8.00 1 15 CLOVER, UT NEBO, UT
Wood - H 138.00 138.00 2.00 1 16 COLUMBIA, UT SUNNYSIDE, UT
Steel - SP 138.00 138.00 6.00 1 17 COTTONWOOD, UT MCCLELLAND, UT
Wood - SP 138.00 138.00 5.00 1 18 COTTONWOOD, UT HAMMER, UT
Wood - SP 138.00 138.00 29.00 1 19 COTTONWOOD, UT SILVER CREEK, UT
Wood - SP 138.00 138.00 1.00 1 20 CUTLER, UT WHEELON, UT
Steel - SP 138.00 138.00 5.00 1 21 DRY CREEK, UT SPANISH FORK, UT
Wood - SP 138.00 138.00 18.00 1 22 DUMAS, UT WESTFIELD, UT
Steel - SP 138.00 138.00 2.00 1 23 DYNAMO, UT TRI-CITY #1, UT
138.00 138.00 3.00 1 24 DYNAMO, UT TRI-CITY #2, UT
Steel - SP 138.00 138.00 15.00 1 25 EAST LAYTON, UT 105 TAP, UT
Wood - SP 138.00 138.00 1.00 1 26 EBAY TAP, UT OQUIRRH, UT
Steel - SP 138.00 138.00 4.00 1 27 EL MONTE, UT STR 30B, UT
Steel - SP 138.00 138.00 1.00 1 28 EL MONTE, UT PIONEER, UT
Wood - SP 138.00 138.00 3.00 1 29 EVANSTON, WY RAILROAD, UT
Wood - SP 138.00 138.00 10.00 1 30 FRANKLIN, ID TREASURETON, ID
Wood - SP 138.00 138.00 25.00 1 31 FRANKLIN, ID GREEN CANYON, UT
Wood - SP 138.00 138.00 1.00 1 32 GADSBY, UT THIRD WEST, UT
Wood - SP 138.00 138.00 6.00 1 33 GADSBY, UT TERMINAL, UT
Wood - SP 138.00 138.00 1.00 1 34 GADSBY, UT JORDAN, UT
Wood - SP 138.00 138.00 7.00 1 35 GREEN CANYON, UT NIBLEY, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.5
36 TOTAL 16,964.00 654.00 284
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
/ /2016/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
1272 ACSR 45/7 2
795 ACSR 26/7 3
1272 ACSR 45/7 4
795 ACSR 26/7 5
795 AAC /37 6
397.5 ACSR 26/7 7
397.5 ACSR 26/7 8
795 ACSR 26/7 9
556.5 ACSR 26/7 10
795 ACSR 26/7 11
1272 ACSR 45/7 12
954 ACSR 54/7 13
795 ACSR 26/7 14
1272 ACSR 45/7 15
397.5 ACSR 26/7 16
795 AAC /37 17
795 AAC /37 18
397.5 ACSR 26/7 19
250 CUHD /12 20
1272 ACSR 45/7 21
795 ACSR 26/7 22
795 ACSR 26/7 23
795 ACSR 26/7 24
795 ACSR 26/7 25
795 ACSR 26/7 26
1272 ACSR 45/7 27
1272 ACSR 45/7 28
795 ACSR 26/7 29
795 ACSR 26/7 30
397.5 ACSR 26/7 31
1272 AAC /61 32
1272 ACSR 45/7 33
1272 ACSR 45/7 34
1272 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.5
36 234,140,526 3,437,321,298 3,671,461,824 523,824 17,542,520 2,406,374 20,472,718
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
/ /2016/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Wood - SP 138.00 138.00 19.00 1 1 GREEN CANYON, UT WHEELON, UT
Wood - H 138.00 138.00 19.00 1 2 HALE, UT MIDWAY, UT
Wood - H 138.00 138.00 7.00 1 3 HALE, UT TANNER, UT
Wood - H 138.00 138.00 18.00 1 4 HALE, UT SPANISH FORK, UT
138.00 138.00 2.00 1 5 HAMMER, UT BUTLERVILLE, UT
Wood - H 138.00 138.00 25.00 1 6 HONEYVILLE, UT LAMPO, UT
138.00 138.00 14.00 1 7 HONEYVILLE, UT WHEELON, UT
Wood - H 138.00 138.00 7.00 1 8 HUNTINGTON, UT MCFADDEN, UT
Wood - H 138.00 138.00 26.00 1 9 JERUSALEM, UT NEBO, UT
Wood - SP 138.00 138.00 1.00 1 10 JORDAN, UT THIRDWEST, UT
Wood - SP 138.00 138.00 5.00 1 11 JORDAN, UT MCCLELLAND, UT
Wood - SP 138.00 138.00 6.00 1 12 JORDAN, UT TERMINAL, UT
Wood - SP 138.00 138.00 1.00 1 13 BARNEYS, UT GRINDING, UT
Wood - SP 138.00 138.00 3.00 1 14 KEARNS, UT TAYLORSVILLE, UT
Wood - SP 138.00 138.00 2.00 1 15 KEARNS, UT WEST VALLEY, UT
138.00 138.00 8.00 1 16 LONE PEAK, UT CAMP WILLIAMS, UT
Wood - SP 138.00 138.00 6.00 1 17 MCCLELLAND, UT MID VALLEY, UT
Wood - H 138.00 138.00 11.00 1 18 MCFADDEN, UT BLACKHAWK, UT
Wood - SP 138.00 138.00 2.00 4.00 1 19 MID VALLEY, UT TAYLORSVILLE, UT
Wood - SP 138.00 138.00 5.00 1 20 MID VALLEY #2, UT COTTONWOOD, UT
Wood - SP 138.00 138.00 3.00 1 21 MID VALLEY #1, UT COTTONWOOD, UT
Wood - H 138.00 138.00 9.00 1 22 MID VALLEY, UT 90TH SOUTH, UT
Wood - H 138.00 138.00 1.00 1 23 MIDDLETON, UT ST GEORGE, UT
Wood - H 138.00 138.00 68.00 1 24 MOAB, UT PINTO, UT
Wood - H 138.00 138.00 36.00 1 25 NAUGHTON, WY CANYON COMP, WY
Wood - H 138.00 138.00 48.00 1 26 NAUGHTON, WY PAINTER, WY
Wood - H 138.00 138.00 33.00 1 27 NEBO, UT DRY CREEK, UT
Wood - H 138.00 138.00 10.00 1 28 NUCOR STEEL, UT WHEELON, UT
Wood - H 138.00 138.00 23.00 1 29 ONEIDA, ID OVID, UT
Wood - H 138.00 138.00 19.00 1 30 ONIEDA, ID GRACE, ID
Wood - SP 138.00 138.00 7.00 1 31 GRINDING, UT OQUIRRH, UT
Wood - SP 138.00 138.00 14.00 1 32 GRINDING, UT TOOELE, UT
Steel - SP 138.00 138.00 23.00 1 33 OQUIRRH, UT TOOELE, UT
Wood - H 138.00 138.00 5.00 1 34 OQUIRRH, UT BARNEY, UT
Wood - H 138.00 138.00 8.00 1 35 OQUIRRH, UT BINGHAM CANYON, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.6
36 TOTAL 16,964.00 654.00 284
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
/ /2016/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
397.5 ACSR 26/7 1
397.5 ACSR 26/7 2
1272 ACSR 45/7 3
1272 ACSR 45/7 4
795 ACSR 26/7 5
397.5 ACSR 26/7 6
250 CUHD /12 7
397.5 ACSR 26/7 8
397.5 ACSR 26/7 9
1272 AAC /61 10
795 AAC /37 11
1272 AAC /91 12
1272 AAC /61 13
795 ACSR 26/7 14
15
1272 ACSR 45/7 16
795 AAC 26/7 17
795 AAC 26/7 18
1272 ACSR /61 19
20
21
1272 ACSR 45/7 22
397.5 ACSR 26/7 23
397.5 ACSR 26/7 24
795 AAC 26/7 25
795 AAC 26/7 26
795 AAC 26/7 27
397.5 ACSR 26/7 28
336.4 ACSR 26/7 29
250 CUHD /12 30
795 ACSR 45/7 31
795 ACSR 45/7 32
1272 ACSR 45/7 33
795 AAC 26/7 34
1557.4 ACSR/TW 35
FERC FORM NO. 1 (ED. 12-87) Page 423.6
36 234,140,526 3,437,321,298 3,671,461,824 523,824 17,542,520 2,406,374 20,472,718
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
/ /2016/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 PAINTER, UT RAILROAD, UT
Wood - H 138.00 138.00 21.00 1 2 PAROWAN, UT WEST CEDAR, UT
Steel - SP 138.00 138.00 16.00 1 3 PARRISH, UT TERMINAL #1, UT
138.00 138.00 14.00 1 4 PARRISH, UT TERMINAL #2, UT
Steel - SP 138.00 138.00 14.00 1 5 PARRISH #105, UT TERMINAL, UT
Steel - SP 138.00 138.00 8.00 1 6 PARRISH, UT TAP TO N SALT LAKE, UT
Wood - H 138.00 138.00 17.00 1 7 RAILROAD, UT CANYON COMP, WY
Steel - SP 138.00 138.00 20.00 1 8 CENTRAL (UAMPS) #2, UT SAINT GEORGE, UT
Steel - SP 138.00 138.00 20.00 1 9 CENTRAL (UAMPS) #3, UT SAINT GEORGE, UT
Steel - SP 138.00 138.00 1.00 1 10 RED BUTTE, UT ST GEORGE, UT
Wood - H 138.00 138.00 49.00 1 11 RED BUTTE, UT WEST CEDAR, UT
Steel - SP 138.00 138.00 7.00 1 12 RIVERDALE, UT EAST LAYTON, UT
Wood - H 138.00 138.00 10.00 1 13 SHICK, UT PARRISH, UT
Wood - SP 138.00 138.00 10.00 1 14 SILVER CREEK, UT JORDANELLE, UT
Wood - H 138.00 138.00 10.00 1 15 SPANISH FORK, UT TANNER, UT
Wood - SP 138.00 138.00 2.00 1 16 SUNRISE, UT OQUIRRH, UT
Steel - SP 138.00 138.00 1.00 1 17 SYRACUSE, UT CLEARFIELD SOUTH, UT
Steel Tower 138.00 138.00 15.00 1 18 SYRACUSE, UT PARRISH, UT
138.00 138.00 9.00 1 19 SYRACUSE, UT ANGEL #1, UT
Wood - H 138.00 138.00 13.00 1 20 TAP TO ANGEL NORTH, UT TAP TO PARRISH, UT
Wood - SP 138.00 138.00 2.00 6.00 1 21 TAYLORSVILLE , UT 90TH SOUTH, UT
Steel - SP 138.00 138.00 9.00 1 22 TERMINAL, UT KENNECOTT, UT
Wood - H 138.00 138.00 53.00 1 23 TERMINAL, UT ROWLEY, UT
Wood - H 138.00 138.00 7.00 1 24 TERMINAL, UT MIDVALLEY #1, UT
Wood - H 138.00 138.00 7.00 1 25 TERMINAL, UT MIDVALLEY #2, UT
Wood - H 138.00 138.00 6.00 24.00 1 26 TERMINAL, UT TOOELE, UT
Wood - SP 138.00 138.00 7.00 1 27 TERMINAL, UT WEST VALLEY, UT
Wood - H 138.00 138.00 17.00 1 28 THREEMILE KNOLL, ID GRACE #1, ID
Wood - H 138.00 138.00 17.00 1 29 THREEMILE KNOLL, ID GRACE #2, ID
Wood - H 138.00 138.00 2.00 1 30 THREEMILE KNOLL, ID MONSANTO #1, ID
Steel - SP 138.00 138.00 2.00 1 31 THREEMILE KNOLL, ID MONSANTO #2, ID
Steel - SP 138.00 138.00 2.00 1 32 TIMP #1, UT DYNAMO, UT
138.00 138.00 2.00 1 33 TIMP #2, UT DYNAMO, UT
Steel - SP 138.00 138.00 4.00 1 34 TIMP, UT HALE, UT
Wood - H 138.00 138.00 23.00 1 35 TIMP, UT SPANISH FORK, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.7
36 TOTAL 16,964.00 654.00 284
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
/ /2016/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
397.5 ACSR 26/7 2
795 AAC 45/7 3
795 AAC 26/7 4
795 AAC 45/7 5
795 AAC 26/7 6
795 ACSR 26/7 7
1272 ACSR 45/7 8
1272 ACSR 45/7 9
1272 ACSR 45/7 10
397.5 ACSR 26/7 11
795 AAC 26/7 12
250 CUHD /12 13
795 AAC 26/7 14
1272 ACSR 45/7 15
16
1272 ACSR 45/7 17
1272 ACSR 45/7 18
250 CUHD /12 19
795 AAC /37 20
795 AAC /37 21
795 AAC 26/7 22
795 AAC /37 23
1272 ACSR 45/7 24
1272 AAC /61 25
397.5 ACSR 26/7 26
27
250 CUHD /12 28
1272 ACSR 45/7 29
1272 AAC /61 30
1272 ACSR 45/7 31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 423.7
36 234,140,526 3,437,321,298 3,671,461,824 523,824 17,542,520 2,406,374 20,472,718
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
/ /2016/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Wood - SP 138.00 138.00 2.00 1 TIMP, UT VINEYARD, UT
Steel Tower 138.00 138.00 25.00 1 2 TREASURETON, ID GRACE, ID
138.00 138.00 25.00 1 3 TREASURETON, ID GRACE #2, ID
Wood - H 138.00 138.00 6.00 1 4 TREASURETON, ID ONEIDA, ID
Wood - SP 138.00 138.00 22.00 1 5 TRI-CITY, UT SUNRISE, ID
Wood - SP 138.00 138.00 12.00 6.00 1 6 TRI-CITY, UT BANGERTER, UT
Wood - H 138.00 138.00 15.00 1 7 TRI-CITY, UT WESTFIELD, UT
Wood - SP 138.00 138.00 20.00 1 8 WEST CEDAR, UT THREE PEAKS, UT
Wood - H 138.00 138.00 9.00 1 9 WEST VALLEY, UT OQUIRRH, UT
Wood - H 138.00 138.00 14.00 1 10 WESTFIELD, UT HALE, UT
Wood - H 138.00 138.00 86.00 1 11 WHEELON, UT AMERICAN FALLS, ID
Steel Tower 138.00 138.00 29.00 1 12 WHEELON #1, UT TREASURETON, ID
138.00 138.00 29.00 1 13 WHEELON #2, UT TREASURETON, ID
Wood - H 138.00 138.00 29.00 1 14 WHEELON #3, UT TREASURETON, ID
Wood - SP 138.00 138.00 3.00 1 15 FORT DOUGLAS, UT MCCLELLAND, UT
Wood - SP 138.00 138.00 25.00 1 16 CAMERON, UT MILFORD, UT
Wood - SP 138.00 138.00 10.00 1 17 EAGLE MOUNTAIN, UT PONY EXPRESS, UT
Wood - SP 138.00 138.00 2.00 1 18 CLOVER, UT BURRASTON PONDS
Wood - SP 138.00 138.00 38.00 1 19 CROYDON, UT RAILROAD, WY
Wood - SP 138.00 138.00 1.00 1 20 GRAPHITE, UT MOUNTAIN VIEW, UT
Wood - SP 138.00 138.00 5.00 1 21 HIGHLAND, UT BULL RIVER (LEHI #5), UT
22 138kV costs and expenses
23
207.00 2,163.00 147 24 Subtotal 138kV
25
1,666.00 26 All 115kV Lines
27
2,923.00 28 All 69kV Lines
29
111.00 30 All 57kV Lines
31
2,541.00 32 All 46kV Lines
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 422.8
36 TOTAL 16,964.00 654.00 284
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
/ /2016/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
250 CUHD /12 2
250 CUHD /12 3
250 CUHD /12 4
5
6
1272 ACSR 45/7 7
795 AAC 26/7 8
9
795 AAC 26/7 10
250 CUHD /12 11
250 CUHD /12 12
250 CUHD /12 13
250 CUHD /12 14
15
397.5 ACSR 26/7 16
795 ACSR 26/7 17
397.5 ACSR 26/7 18
1272 ACSR 45/7 19
397.5 ACSR 26/7 20
1272 ACSR 45/7 21
403,955,973 379,880,040 24,075,933 1,919,261 187,509 1,568,566 163,186 22
23
403,955,973 379,880,040 24,075,933 1,919,261 187,509 1,568,566 163,186 24
25
198,342,780 193,141,097 5,201,683 4,113,972 467,033 3,584,058 62,881 26
27
290,221,799 281,925,085 8,296,714 3,448,568 221,169 3,203,969 23,430 28
29
12,131,444 12,078,789 52,655 62,875 1,320 59,219 2,336 30
31
275,974,087 265,382,941 10,591,146 2,431,877 81,759 2,321,343 28,775 32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 423.8
36 234,140,526 3,437,321,298 3,671,461,824 523,824 17,542,520 2,406,374 20,472,718
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. For further discussion, see also page 328, Transmission of
electricity for others, in this Form No. 1.
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 78.0% 22.0%
Midpoint – Hemingway 63.0% 37.0%
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 Company.
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 Company.
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 Company.
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 Company.
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 Company.
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
2016/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 81.7%, Idaho Power Company 18.3%. 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 70.8% 29.2%
Populus – Borah #1 70.8% 29.2%
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 70.8% 29.2%
Populus – Kinport 70.8% 29.2%
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 70.8%, Idaho Power Company 29.2%.
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
35.6%, Idaho Power Company 64.4%. 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
35.6%, Idaho Power Company 64.4%. 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 26.8%, Idaho Power Company 73.2%. Plant
cost and operation and maintenance costs reported for this line reflect PacifiCorp’s
share.
Schedule Page: 422.2 Line No.: 3 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.: 3 Column: i
1557 ACSS/TW 45/7
Schedule Page: 422.2 Line No.: 18 Column: a
Complete name is Gonder (NV Energy), UT - NV State.
Schedule Page: 422.2 Line No.: 21 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 59.2%, Idaho Power Company 40.8%.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
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 Big Grassy - Jefferson 161kV line is jointly owned by PacifiCorp and Idaho Power
company. Ownership of the line is as follows: PacifiCorp 62.2%, Idaho Power Company
37.8%. Plant costs and operation and maintenance costs reported for this line reflect
PacifiCorp's share.
Schedule Page: 422.3 Line No.: 35 Column: a
The Antelope - Goshen 161kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line is as follows: PacifiCorp 78.1%, Idaho Power Company 21.9%. Plant
cost and operation and maintenance costs reported for this line reflect PacifiCorp’s
share.
Schedule Page: 422.4 Line No.: 9 Column: a
The Goshen - Jefferson 161kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line is as follows: PacifiCorp 62.2%, Idaho Power Company 37.8%. Plant
cost and operation and maintenance costs reported for this line reflect PacifiCorp’s
share.
Schedule Page: 422.4 Line No.: 22 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 33.3%, Idaho Power Company 66.7%.
Plant cost and operation and maintenance costs reported for this line reflect PacifiCorp’s
share.
Schedule Page: 422.4 Line No.: 23 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 33.3%, Idaho Power Company 66.7%.
Plant cost and operation and maintenance costs reported for this line reflect PacifiCorp’s
share.
Schedule Page: 422.4 Line No.: 27 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 15 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 20 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 21 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 35 Column: b
Complete name is Bingham Canyon (KCC), UT.
Schedule Page: 422.7 Line No.: 8 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.: 9 Column: a
See footnote on page 422.7, line 8, column (a).
Schedule Page: 422.7 Line No.: 16 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 27 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 32 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 33 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 34 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 35 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
2016/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.: 5 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.: 9 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 11 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 96.4%, Idaho Power Company 3.6%. Plant cost and operation and maintenance costs
reported for this line reflect PacifiCorp’s share.
Schedule Page: 422.8 Line No.: 15 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 18 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
2016/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
/ /2016/Q4
Line
No.
(c)(b)(a) (d) (e)
LINE DESIGNATION
From To
LineLengthinMiles
SUPPORTING STRUCTURE
Type AverageNumber perMiles
CIRCUITS PER STRUCTURE
Present Ultimate
(f) (g)
1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the
8.00Wood - H 1 1 1 ARROWHEAD, WY FIREHOLE, WY 9.00
25.00Wood - SP 1 1 2 TIMP, UT VINEYARD, UT 2.00
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
11.00 33.00 2 2
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
/ /2016/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
ACSR795 328,943 1,003,793 674,850 230 1
-142,591Vertical 5'ACSR1272 1,681,622 3,078,290 1,539,259 138 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
-142,591 2,010,565 2,214,109
FERC FORM NO. 1 (REV. 12-03) Page 425
44 4,082,083
Schedule Page: 424 Line No.: 1 Column: j
Horizontal 9 feet, 7 inches
Schedule Page: 424 Line No.: 2 Column: m
Line costs include structure and line replacement charges to alter the previous single
circuit 46kV transmission line.
Schedule Page: 424 Line No.: 2 Column: n
Refer to footnote on line 2, column (m).
Schedule Page: 424 Line No.: 2 Column:
Refer to footnote on line 2, 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
2016/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 / /2016/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 / /2016/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 / /2016/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
TOTAL 391.00 690.00 12.47 17
Number of Substations-5 18
19
IDAHO 20
ALEXANDER 12.47 46.00DISTRIBUTION-UNATTEN 21
AMMON 12.47 69.00DISTRIBUTION-UNATTEN 22
ANDERSON 12.47 69.00DISTRIBUTION-UNATTEN 23
ARCO 12.47 69.00DISTRIBUTION-UNATTEN 24
ARIMO 12.47 46.00DISTRIBUTION-UNATTEN 25
BANCROFT SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
BELSON SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
BERENICE SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
CAMAS SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
CANYON CREEK SUB 24.90 69.00DISTRIBUTION-UNATTEN 30
CHESTERFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
CLEMENTS SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
CLIFTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
COVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
DOWNEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
DUBOIS SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
EASTMONT SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
EGIN SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
EIGHT MILE SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
GEORGETOWN SUB 12.47 69.00DISTRIBUTION-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 / /2016/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
725 14 17
18
19
20
4 1 21
14 1 22
20 1 23
6 1 24
7 1 25
4 1 26
12 1 27
10 1 28
14 1 29
20 1 30
5 1 31
5 1 32
4 1 33
6 1 34
5 1 35
12 1 36
14 1 37
14 1 38
4 1 39
6 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/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).
GRACE CITY SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
HAMER SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
HAYES SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
HENRY SUB 7.20 46.00DISTRIBUTION-UNATTEN 4
HOLBROOK SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
HOOPES SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
HORSLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
IDAHO FALLS SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
INDIAN CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
JEFFCO SUB 24.90 69.00DISTRIBUTION-UNATTEN 10
KETTLE SUB 24.90 69.00DISTRIBUTION-UNATTEN 11
LAVA SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
LUND SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
MCCAMMON SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
MENAN SUB 12.47 69.00DISTRIBUTION-UNATTEN 15
MERRILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
MILLER SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
MONTPELIER SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
MOODY SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
NEWDALE SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
OSGOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
PRESTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
RAYMOND SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
RENO SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
REXBURG SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
RIRIE SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
ROBERTS SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
RUBY SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
SAND CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
SANDUNE SUB 24.90 67.00DISTRIBUTION-UNATTEN 30
SHELLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
SMITH SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
SOUTH FORK SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
SPUD SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
ST. CHARLES SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
SUGAR CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
SUNNYDELL SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
TANNER SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
TARGHEE SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
THORNTON SUB 12.47 69.00DISTRIBUTION-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 / /2016/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
5 1 1
14 1 2
9 1 3
1 1 4
6 1 5
9 1 6
4 1 7
20 1 8
3 1 9
22 1 10
14 1 11
6 1 12
5 1 13
3 1 14
10 1 15
20 1 16
5 1 17
8 1 18
14 1 19
20 1 20
20 1 21
12 1 22
2 1 23
20 1 24
32 2 25
9 1 26
8 1 27
7 1 28
40 2 29
30 1 30
20 1 31
20 1 32
14 1 33
8 1 34
5 1 35
12 1 36
13 1 37
4 1 38
4 1 39
7 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 / /2016/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).
UCON SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
WATKINS SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
WEBSTER SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
WESTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
WINDSPER SUB 24.90 69.00DISTRIBUTION-UNATTEN 5
TOTAL 867.43 4000.00 6
Number of Substations-65 7
8
CINDER BUTTE SUB 12.47 161.00T/D-UNATTENDED 9
MALAD SUB 46.00 138.00 12.47T/D-UNATTENDED 10
MUD LAKE SUB 12.47 69.00T/D-UNATTENDED 11
RIGBY SUB 12.47 161.00 69.00T/D-UNATTENDED 12
SAINT ANTHONY SUB 46.00 69.00 12.47T/D-UNATTENDED 13
TOTAL 129.41 598.00 93.94 14
Number of Substations-5 15
16
AMPS SUB 69.00 230.00 12.47TRANSMISSION-UNATTEN 17
ANTELOPE SUB 161.00 230.00 13.80TRANSMISSION-UNATTEN 18
ASHTON PLANT 12.47 46.00 2.40TRANSMISSION-UNATTEN 19
BIG GRASSY SUB 69.00 161.00TRANSMISSION-UNATTEN 20
BONNEVILLE SUB 69.00 161.00TRANSMISSION-UNATTEN 21
CONDA SUB 46.00 138.00TRANSMISSION-UNATTEN 22
FISH CREEK SUB 46.00 161.00TRANSMISSION-UNATTEN 23
FRANKLIN SUB 46.00 138.00TRANSMISSION-UNATTEN 24
GOSHEN SUB 161.00 345.00 69.00TRANSMISSION-UNATTEN 25
GRACE SUB 138.00 161.00 12.50TRANSMISSION-UNATTEN 26
JEFFERSON SUB 69.00 161.00TRANSMISSION-UNATTEN 27
MIDPOINT SUB 345.00 500.00TRANSMISSION-UNATTEN 28
OVID SUB 69.00 138.00TRANSMISSION-UNATTEN 29
SCOVILLE SUB 69.00 138.00TRANSMISSION-UNATTEN 30
SUGARMILL SUB 46.00 161.00 69.00TRANSMISSION-UNATTEN 31
THREEMILE KNOLL SUB 138.00 345.00 46.00TRANSMISSION-UNATTEN 32
TREASURETON SUB 138.00 230.00TRANSMISSION-UNATTEN 33
TOTAL 1691.47 3444.00 225.17 34
Number of Substations-17 35
36
MONTANA 37
BROADVIEW SUB 230.00 500.00TRANSMISSION-UNATTEN 38
COLSTRIP SUB 230.00 500.00TRANSMISSION-UNATTEN 39
YELLOWTAIL SUB 161.00 230.00TRANSMISSION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
7 1 1
14 1 2
20 1 3
4 1 4
20 1 5
736 67 6
7
8
30 1 9
71 4 1 10
14 1 11
189 4 12
40 2 13
344 12 1 14
15
16
75 1 17
250 1 18
15 1 19
67 1 20
67 1 21
67 1 22
25 3 23
75 1 24
908 4 25
217 2 26
233 3 27
1500 1 1 28
30 1 29
76 2 30
168 3 31
775 2 32
533 2 33
5081 30 1 34
35
36
37
32 2 38
68 2 39
100 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
TOTAL 621.00 1230.00 1
Number of Substations-3 2
3
OREGON 4
26TH STREET 4.16 20.80DISTRIBUTION-UNATTEN 5
35TH STREET 2.40 20.80DISTRIBUTION-UNATTEN 6
AGNESS AVE 12.47 115.00DISTRIBUTION-UNATTEN 7
ALDERWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
ARLINGTON 12.47 69.00DISTRIBUTION-UNATTEN 9
ATHENA 12.47 69.00DISTRIBUTION-UNATTEN 10
BANDON TIE SUB 12.47 20.80DISTRIBUTION-UNATTEN 11
BEACON SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
BEALL LANE SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
BEATTY SUB 12.47 69.00DISTRIBUTION-UNATTEN 14
BELKNAP SUB 12.47 115.00DISTRIBUTION-UNATTEN 15
BLALOCK SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
BLOSS SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
BLY SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
BOISE CASCADE SUB 11.00 69.00DISTRIBUTION-UNATTEN 19
BONANZA SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
BOND STREET SUB 12.50 69.00DISTRIBUTION-UNATTEN 21
BROOKHURST SUB 12.47 115.00DISTRIBUTION-UNATTEN 22
BROWNSVILLE SUB 20.80 69.00DISTRIBUTION-UNATTEN 23
BRYANT SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
BUCHANAN SUB 20.80 115.00DISTRIBUTION-UNATTEN 25
BUCKAROO SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
CAMPBELL SUB 12.47 115.00DISTRIBUTION-UNATTEN 27
CANNON BEACH SUB 12.47 115.00DISTRIBUTION-UNATTEN 28
CANYONVILLE SUB 12.47 115.00DISTRIBUTION-UNATTEN 29
CARNES SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
CASEBEER SUB 20.80 69.00DISTRIBUTION-UNATTEN 31
CAVEMAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 32
CHERRY LANE SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
CHILOQUIN MARKET SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
CHINA HAT SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
CIRCLE BLVD SUB 20.80 115.00DISTRIBUTION-UNATTEN 36
CLEVELAND AVE SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
CLOAKE SUB 20.80 69.00DISTRIBUTION-UNATTEN 38
COBURG SUB 20.80 69.00DISTRIBUTION-UNATTEN 39
COLISEUM SUB 4.16 20.80DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
200 5 1
2
3
4
5 1 5
30 6 6
25 1 7
45 2 8
5 1 9
9 1 10
8 3 1 11
11 3 12
25 1 13
6 1 14
40 2 15
2 3 16
32 2 17
8 3 18
3 1 19
8 3 20
25 1 21
50 2 22
13 1 23
34 2 24
45 2 25
34 2 26
20 2 27
13 1 28
25 1 29
9 3 30
20 1 31
45 2 32
25 1 33
9 3 34
25 1 35
80 2 36
45 2 37
20 1 38
10 3 39
9 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
COLUMBIA SUB 12.47 115.00 57.00DISTRIBUTION-UNATTEN 1
COOS RIVER SUB 20.80 115.00DISTRIBUTION-UNATTEN 2
COQUILLE SUB 20.80 115.00DISTRIBUTION-UNATTEN 3
CREEK SUB 34.50 69.00DISTRIBUTION-UNATTEN 4
CROOKED RIVER RANCH SUB 20.80 69.00DISTRIBUTION-UNATTEN 5
CROWFOOT SUB 12.47 115.00DISTRIBUTION-UNATTEN 6
CULLY SUB 12.47 115.00DISTRIBUTION-UNATTEN 7
CULVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
DAIRY SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
DALLAS SUB 20.80 115.00DISTRIBUTION-UNATTEN 10
DALREED SUB 34.40 230.00DISTRIBUTION-UNATTEN 11
DESCHUTES SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
DEVILS LAKE SUB 20.80 115.00DISTRIBUTION-UNATTEN 13
DIXON SUB 4.16 115.00DISTRIBUTION-UNATTEN 14
DODGE BRIDGE SUB 20.80 69.00DISTRIBUTION-UNATTEN 15
DOWELL SUB 12.47 115.00DISTRIBUTION-UNATTEN 16
EASY VALLEY SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
EMPIRE SUB 20.80 115.00DISTRIBUTION-UNATTEN 18
ENTERPRISE SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
FERN HILL SUB 12.47 115.00DISTRIBUTION-UNATTEN 20
FIELDER CREEK SUB 20.80 115.00DISTRIBUTION-UNATTEN 21
FOOTHILLS SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
FRALEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
GARDEN VALLEY SUB 20.80 69.00DISTRIBUTION-UNATTEN 24
GAZLEY SUB 12.47 115.00DISTRIBUTION-UNATTEN 25
GLENDALE SUB 12.47 230.00DISTRIBUTION-UNATTEN 26
GLENEDEN SUB 4.16 20.80DISTRIBUTION-UNATTEN 27
GLIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 28
GOLD HILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
GORDON HOLLOW SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
GOSHEN SUB 20.80 115.00DISTRIBUTION-UNATTEN 31
GRANT STREET SUB 20.80 115.00DISTRIBUTION-UNATTEN 32
GRASS VALLEY SUB 4.16 20.80DISTRIBUTION-UNATTEN 33
GREEN SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
GRIFFIN CREEK SUB 12.47 115.00DISTRIBUTION-UNATTEN 35
HAMAKER SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
HARRISBURG SUB 20.80 69.00DISTRIBUTION-UNATTEN 37
HENLEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
HERMISTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
HILLVIEW SUB 20.80 115.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
55 2 1 1
20 1 2
40 2 3
5 1 4
25 2 5
20 1 6
25 1 7
13 1 8
25 1 9
50 2 10
95 4 11
25 1 12
50 2 13
7 1 14
13 1 15
20 1 16
45 2 17
20 1 18
19 2 19
12 1 20
25 1 21
21 4 22
5 3 23
20 1 24
8 4 25
25 2 26
6 1 27
12 1 28
11 3 29
6 1 30
20 1 31
45 2 32
1 4 33
25 1 34
20 1 35
8 3 36
13 1 37
6 3 38
40 1 39
45 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
HINKLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
HOLLADAY SUB 12.47 115.00DISTRIBUTION-UNATTEN 2
HOLLYWOOD SUB 12.47 115.00DISTRIBUTION-UNATTEN 3
HOOD RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
HORNET SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
HUMBUG CREEK SUB 12.50 67.00DISTRIBUTION-UNATTEN 6
HUNTERS CIRCLE TEMP SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
ILLAHEE FLATS SUB 12.47 115.00DISTRIBUTION-UNATTEN 8
INDEPENDENCE SUB 20.80 69.00DISTRIBUTION-UNATTEN 9
JACKSONVILLE SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 10
JEFFERSON SUB 20.80 69.00DISTRIBUTION-UNATTEN 11
JEROME PRAIRIE SUB 12.47 115.00DISTRIBUTION-UNATTEN 12
JORDAN POINT SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
JOSEPH SUB 12.47 20.80DISTRIBUTION-UNATTEN 14
JUNCTION CITY SUB 20.80 69.00DISTRIBUTION-UNATTEN 15
KENWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
KILLINGWORTH SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
KNAPPA SVENSEN SUB 12.47 115.00DISTRIBUTION-UNATTEN 18
LAKEPORT SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
LANCASTER SUB 20.80 69.00DISTRIBUTION-UNATTEN 20
LEBANON SUB 20.80 115.00DISTRIBUTION-UNATTEN 21
LINCOLN SUB 12.47 115.00DISTRIBUTION-UNATTEN 22
LOCKHART SUB 20.80 115.00DISTRIBUTION-UNATTEN 23
LYONS SUB 20.80 69.00DISTRIBUTION-UNATTEN 24
MADRAS SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
MALLORY SUB 12.47 115.00DISTRIBUTION-UNATTEN 26
MARYS RIVER SUB 20.80 115.00DISTRIBUTION-UNATTEN 27
MEDCO SUB 12.47 115.00DISTRIBUTION-UNATTEN 28
MEDFORD 12.47 115.00DISTRIBUTION-UNATTEN 29
MERLIN SUB 12.47 115.00DISTRIBUTION-UNATTEN 30
MERRILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
MINAM SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
MODOC SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
MORO SUB 2.40 20.80DISTRIBUTION-UNATTEN 34
MURDER CREEK SUB 20.80 115.00DISTRIBUTION-UNATTEN 35
MYRTLE CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
MYRTLE POINT SUB 20.80 115.00DISTRIBUTION-UNATTEN 37
NELSCOTT SUB 4.16 20.80DISTRIBUTION-UNATTEN 38
NEW O'BRIEN SUB 12.47 115.00DISTRIBUTION-UNATTEN 39
OAK KNOLL SUB 12.47 115.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.6
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
20 1 1
75 3 2
50 2 3
40 2 4
20 1 5
9 1 6
12 1 7
2 1 8
20 1 9
75 2 10
12 1 11
20 1 12
20 1 13
6 1 1 14
22 2 15
3 3 16
40 2 17
6 1 18
50 2 19
12 3 20
40 2 21
105 3 22
40 2 23
25 2 24
25 2 25
25 1 26
20 1 27
20 1 28
67 8 29
45 2 30
17 6 31
1 32
6 3 33
2 3 34
100 4 35
14 1 36
9 1 37
4 1 38
9 1 39
45 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.6
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
OAKLAND SUB 12.47 115.00DISTRIBUTION-UNATTEN 1
OREMET SUB 12.47 115.00DISTRIBUTION-UNATTEN 2
OVERPASS SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
PALLETTE SUB 20.80 69.00DISTRIBUTION-UNATTEN 4
PARK STREET SUB 12.47 115.00DISTRIBUTION-UNATTEN 5
PARKROSE SUB 12.47 57.00DISTRIBUTION-UNATTEN 6
PENDLETON SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
PILOT ROCK SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
POWELL BUTTE SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
PRINEVILLE SUB 12.47 115.00DISTRIBUTION-UNATTEN 10
PROVOLT SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
QUEEN AVE SUB 20.80 69.00DISTRIBUTION-UNATTEN 12
RED BLANKET SUB 4.16 69.00DISTRIBUTION-UNATTEN 13
REDMOND SUB 12.47 115.00DISTRIBUTION-UNATTEN 14
RIDDLE VENEER SUB 12.47 115.00DISTRIBUTION-UNATTEN 15
ROGUE RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
ROSEBURG SUB 20.80 115.00DISTRIBUTION-UNATTEN 17
ROSS AVE SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
ROXY ANN SUB 12.47 115.00DISTRIBUTION-UNATTEN 19
RUCH SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
RUNNING Y SUB 20.80 69.00DISTRIBUTION-UNATTEN 21
RUSSELLVILLE SUB 12.47 115.00DISTRIBUTION-UNATTEN 22
SCENIC SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 23
SCIO SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
SEASIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 25
SELMA SUB 12.47 115.00DISTRIBUTION-UNATTEN 26
SHASTA WAY SUB 4.16 12.47DISTRIBUTION-UNATTEN 27
SHEVLIN PARK SUB 12.50 69.00DISTRIBUTION-UNATTEN 28
SIMTAG BOOSTER PUMP 4.16 34.50DISTRIBUTION-UNATTEN 29
SOUTH DUNES SUB 12.47 115.00DISTRIBUTION-UNATTEN 30
SOUTHGATE SUB 20.80 69.00DISTRIBUTION-UNATTEN 31
SPRAGUE RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
STATE STREET SUB 20.80 115.00DISTRIBUTION-UNATTEN 33
STAYTON SUB 20.80 69.00DISTRIBUTION-UNATTEN 34
STEAMBOAT SUB 7.20 115.00DISTRIBUTION-UNATTEN 35
STEVENS ROAD SUB 20.80 115.00DISTRIBUTION-UNATTEN 36
SUTHERLIN SUB 12.00 115.00DISTRIBUTION-UNATTEN 37
SWEET HOME SUB 20.80 115.00DISTRIBUTION-UNATTEN 38
TAKELMA SUB 20.80 115.00DISTRIBUTION-UNATTEN 39
TALENT SUB 12.47 115.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
8 1 1
75 2 2
45 2 3
1 1 1 4
40 2 5
39 2 6
46 7 1 7
22 2 8
12 1 9
50 2 10
11 3 11
50 2 12
2 3 13
50 2 14
25 1 15
25 2 16
50 2 17
9 3 18
25 1 19
9 1 20
9 1 21
45 2 22
70 3 23
8 1 24
40 2 25
9 1 26
2 3 27
25 1 28
19 2 29
9 1 30
20 1 31
7 3 32
40 2 33
55 2 34
1 35
50 2 36
25 1 37
42 2 38
12 1 39
50 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
TEXUM SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
TILLER SUB 12.47 115.00DISTRIBUTION-UNATTEN 2
TOLO SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
TURKEY HILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
UMAPINE SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
UMATILLA SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
VERNON SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
VILAS SUB 12.47 115.00DISTRIBUTION-UNATTEN 8
VILLAGE GREEN SUB 20.80 115.00DISTRIBUTION-UNATTEN 9
VINE STREET SUB 20.80 69.00DISTRIBUTION-UNATTEN 10
WALLOWA SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
WARM SPRINGS SUB 20.80 69.00DISTRIBUTION-UNATTEN 12
WARRENTON SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
WASCO SUB 4.16 20.80DISTRIBUTION-UNATTEN 14
WECOMA BEACH SUB 4.16 20.80DISTRIBUTION-UNATTEN 15
WESTERN KRAFT SUB 12.47 115.00DISTRIBUTION-UNATTEN 16
WESTON SUB 13.09 70.60DISTRIBUTION-UNATTEN 17
WESTSIDE HYDRO/SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
WEYERHAUSER SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
WHITE CITY SUB 12.47 115.00DISTRIBUTION-UNATTEN 20
WILLOW COVE SUB 4.16 34.50DISTRIBUTION-UNATTEN 21
WINSTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
YEW AVENUE SUB 12.47 115.00DISTRIBUTION-UNATTEN 23
YOUNGS BAY SUB 12.47 115.00DISTRIBUTION-UNATTEN 24
TOTAL 2512.06 15661.87 195.00 25
Number of Substations-180 26
27
ALBINA SUB 12.47 115.00 69.00T/D-UNATTENDED 28
APPLEGATE SUB 69.00 115.00 12.47T/D-UNATTENDED 29
ASHLAND SUB 12.47 115.00 7.20T/D-UNATTENDED 30
BEND PLANT SUB 13.09 69.00 12.47T/D-UNATTENDED 31
CAVE JUNCTION SUB 12.47 115.00 69.00T/D-UNATTENDED 32
HAZELWOOD SUB 69.00 115.00 12.47T/D-UNATTENDED 33
KNOTT SUB 12.47 115.00 57.00T/D-UNATTENDED 34
MILE HI SUB 69.00 115.00 12.47T/D-UNATTENDED 35
PILOT BUTTE SUB 69.00 230.00 12.47T/D-UNATTENDED 36
RIDDLE SUB 69.00 115.00T/D-UNATTENDED 37
SAGE ROAD SUB 12.47 115.00T/D-UNATTENDED 38
WINCHESTER SUB 12.47 115.00 69.00T/D-UNATTENDED 39
TOTAL 432.91 1449.00 333.55 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 / /2016/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
25 1 1
1 1 2
11 1 3
13 3 4
20 1 5
25 2 6
50 2 7
25 1 8
40 2 9
20 1 10
7 1 11
12 3 12
25 2 13
2 3 14
3 1 15
50 2 16
25 1 17
22 9 18
40 2 19
60 3 20
28 3 21
22 3 22
25 1 23
37 2 24
4615 345 5 25
26
27
177 9 28
65 2 29
20 1 30
31 3 31
70 2 32
106 3 33
162 5 34
39 4 35
400 4 36
75 2 37
40 2 38
75 5 39
1260 42 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 / /2016/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Number of Substations-12 1
2
LEMOLO #1 HYDRO 12.50 11.50TRANSMISSION-ATTENDE 3
CALAPOOYA SUB 69.00 230.00TRANSMISSION-UNATTEN 4
CHILOQUIN SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 5
COLD SPRINGS SUB 69.00 230.00 2.40TRANSMISSION-UNATTEN 6
COVE SUB 69.00 230.00TRANSMISSION-UNATTEN 7
DIAMOND HILL SUB 69.00 230.00TRANSMISSION-UNATTEN 8
DIXONVILLE 115/230 SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 9
DIXONVILLE 500 SUB 230.00 500.00TRANSMISSION-UNATTEN 10
FISH HOLE SUB 69.00 115.00TRANSMISSION-UNATTEN 11
FRY SUB 115.00 230.00TRANSMISSION-UNATTEN 12
GRANTS PASS SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 13
HURRICANE SUB 69.00 230.00 2.40TRANSMISSION-UNATTEN 14
ISTHMUS SUB 115.00 230.00TRANSMISSION-UNATTEN 15
KENNEDY SUB 57.00 69.00TRANSMISSION-UNATTEN 16
KLAMATH FALLS SUB 69.00 230.00TRANSMISSION-UNATTEN 17
LONE PINE SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 18
MALIN SUB 230.00 500.00 69.00TRANSMISSION-UNATTEN 19
MERIDIAN SUB 230.00 500.00TRANSMISSION-UNATTEN 20
MONPAC SUB 69.00 115.00TRANSMISSION-UNATTEN 21
NICKEL MOUNTAIN SUB 115.00 230.00TRANSMISSION-UNATTEN 22
PARRISH GAP SUB 69.00 230.00 12.47TRANSMISSION-UNATTEN 23
PONDEROSA SUB 115.00 230.00TRANSMISSION-UNATTEN 24
PROSPECT CENTRAL SUB 69.00 115.00TRANSMISSION-UNATTEN 25
ROBERTS CREEK SUB 69.00 115.00TRANSMISSION-UNATTEN 26
TROUTDALE SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 27
TUCKER SUB 69.00 115.00TRANSMISSION-UNATTEN 28
WHETSTONE SUB 115.00 230.00 12.47TRANSMISSION-UNATTEN 29
TOTAL 2737.50 6065.50 443.74 30
Number of Substations-27 31
32
UTAH 33
106TH SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 34
118TH SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 35
23RD ST SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
70TH SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 37
ALTAVIEW SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
AMALGA SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
AMERICAN FORK SUB 12.47 138.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.9
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
1
2
2 3 3
75 1 4
119 4 5
66 2 6
67 3 7
75 1 8
343 6 9
650 3 1 10
7 3 11
500 2 12
473 5 13
29 2 14
250 1 15
33 1 16
251 6 1 17
733 10 18
775 4 1 19
1300 6 1 20
50 1 21
114 1 22
150 1 23
500 2 24
30 3 25
50 1 26
500 3 27
100 2 28
250 1 29
7492 78 4 30
31
32
33
30 1 34
30 1 35
12 1 36
30 1 37
45 2 38
11 1 39
30 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.9
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
ARAGONITE 7.20 46.00DISTRIBUTION-UNATTEN 1
AURORA SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
BANGERTER SUB 12.47 138.00DISTRIBUTION-UNATTEN 3
BEAR RIVER SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
BENJAMIN SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
BINGHAM SUB 7.62 46.00DISTRIBUTION-UNATTEN 6
BLUE CREEK 12.47 46.00DISTRIBUTION-UNATTEN 7
BLUFF SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
BLUFFDALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
BOTHWELL SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
BRIAN HEAD SUB 12.47 34.50DISTRIBUTION-UNATTEN 11
BRIGHTON SUB 24.90 46.00DISTRIBUTION-UNATTEN 12
BROOKLAWN SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
BRUNSWICK SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
BURTON SUB 12.47 34.50DISTRIBUTION-UNATTEN 15
BUSH SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
CANNON SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
CANYONLANDS SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
CAPITOL SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
CARBIDE SUB 7.20 69.00DISTRIBUTION-UNATTEN 20
CARBONVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
CARLISLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 22
CASTO SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
CENTERVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
CENTRAL SUB 12.47 43.80DISTRIBUTION-UNATTEN 25
CHAPEL HILL SUB 12.47 138.00DISTRIBUTION-UNATTEN 26
CHERRYWOOD SUB 12.47 138.00DISTRIBUTION-UNATTEN 27
CIRCLEVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
CLEAR CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
CLEAR LAKE SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
CLEARFIELD SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 31
CLINTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 32
CLIVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
COALVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
COLD WATER CANYON SUB 12.47 138.00DISTRIBUTION-UNATTEN 35
COLEMAN SUB 69.00 138.00 12.47DISTRIBUTION-UNATTEN 36
COLTON WELL SUB 2.40 46.00DISTRIBUTION-UNATTEN 37
COMMERCE SUB 12.47 138.00DISTRIBUTION-UNATTEN 38
COPPER HILLS SUB 12.47 138.00DISTRIBUTION-UNATTEN 39
CORINNE SUB 12.47 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 / /2016/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
1 1 1
3 1 2
50 2 3
17 2 4
2 1 5
25 1 6
2 3 7
1 3 8
9 1 9
4 1 10
14 1 11
29 2 12
6 1 13
60 3 14
11 3 15
9 1 16
12 1 17
1 1 18
20 1 19
3 1 20
6 1 21
30 1 22
25 1 23
22 1 24
9 1 25
30 1 26
50 2 27
3 1 28
4 1 29
3 30
60 2 31
50 2 32
4 1 33
6 1 34
30 1 35
106 4 36
1 3 37
30 1 38
30 1 39
3 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.10
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/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).
COVE FORT SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
COZYDALE SUB 12.47 138.00DISTRIBUTION-UNATTEN 2
CROSS HOLLOW SUB 12.47 138.00DISTRIBUTION-UNATTEN 3
CUDAHY SUB 12.47 138.00DISTRIBUTION-UNATTEN 4
DAMMERON VALLEY SUB 12.47 34.50DISTRIBUTION-UNATTEN 5
DECKER LAKE SUB 12.47 138.00DISTRIBUTION-UNATTEN 6
DELLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
DELTA SUB 69.00 46.00DISTRIBUTION-UNATTEN 8
DEWEYVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
DIMPLE DELL SUB 12.47 138.00DISTRIBUTION-UNATTEN 10
DRAPER SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
EAST BENCH SUB 12.47 138.00DISTRIBUTION-UNATTEN 12
EAST HYRUM SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
EAST LAYTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 14
EAST MILLCREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
EDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
ELBERTA SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
ELK MEADOWS SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
ELSINORE SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
EMERY CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
EMIGRATION SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
ENOCH SUB 12.47 138.00DISTRIBUTION-UNATTEN 22
ENTERPRISE VALLEY SUB 12.47 138.00DISTRIBUTION-UNATTEN 23
EUREKA SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
FARMINGTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 25
FAYETTE SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
FERRON SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
FIELDING SUB 12.00 46.00DISTRIBUTION-UNATTEN 28
FIFTH WEST SUB 12.47 138.00DISTRIBUTION-UNATTEN 29
FLUX SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
FOOL CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
FORT DOUGLAS 13.20 138.00DISTRIBUTION-UNATTEN 32
FOUNTAIN GREEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
FREEDOM SUB 7.20 46.00DISTRIBUTION-UNATTEN 34
FRUIT HEIGHTS SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
GARDEN CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
GATEWAY SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
GOLD RUSH SUB 12.47 138.00DISTRIBUTION-UNATTEN 38
GORDON AVENUE SUB 12.47 138.00DISTRIBUTION-UNATTEN 39
GOSHEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.11
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/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
30 1 2
22 1 3
30 1 4
42 1 5
55 2 6
6 1 7
48 3 8
4 1 9
60 2 10
23 2 11
30 1 12
6 1 13
60 2 14
20 1 15
19 2 16
5 1 17
3 1 18
2 1 19
3 3 20
25 1 21
14 1 22
10 1 23
3 1 24
30 1 25
1 2 26
5 1 27
6 1 28
50 2 29
4 1 30
2 1 31
40 1 32
7 1 33
1 34
22 1 35
12 1 36
14 1 2 37
30 1 38
30 1 39
2 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.11
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/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).
GRANGER SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
GRANTSVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
GUNNISON SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
HAMMER SUB 12.47 138.00DISTRIBUTION-UNATTEN 4
HAVASU SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
HELPER CITY SUB 4.16 46.00DISTRIBUTION-UNATTEN 6
HERRIMAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 7
HIGHLAND DIST SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
HOGGARD SUB 12.47 138.00DISTRIBUTION-UNATTEN 9
HOLDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
HOLLADAY SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
HUNTER SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
HUNTINGTON CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
IRON MOUNTAIN SUB 7.20 34.50DISTRIBUTION-UNATTEN 14
IRONTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
IVINS SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
JORDAN NARROWS SUB 2.40 46.00DISTRIBUTION-UNATTEN 17
JORDAN PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 18
JORDANELLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 19
JUAB SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
JUNCTION SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
KAIBAB SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
KAMAS SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
KEARNS SUB 12.47 138.00DISTRIBUTION-UNATTEN 24
KENSINGTON SUB 4.16 46.00DISTRIBUTION-UNATTEN 25
KYUNE SUB 7.20 46.00DISTRIBUTION-UNATTEN 26
LAKE PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 27
LAYTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
LEGRANDE SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
LEWISTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
LINCOLN SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
LINDON SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
LISBON SUB 12.47 70.60DISTRIBUTION-UNATTEN 33
LOAFER SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
LOGAN CANYON SUB 7.20 46.00DISTRIBUTION-UNATTEN 35
LONE TREE SUB 12.47 34.50DISTRIBUTION-UNATTEN 36
LOWER BEAVER SUB 6.60 46.00DISTRIBUTION-UNATTEN 37
LYNNDYL SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
MAESER SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
MAGNA SUB 12.47 138.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.12
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/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
23 1 2
11 2 3
60 2 4
3 1 5
3 3 6
30 1 7
25 1 8
50 2 9
4 1 10
32 2 11
22 1 12
12 2 13
1 1 14
2 1 15
22 1 16
13 2 17
30 1 18
30 1 19
4 1 20
3 1 21
5 1 22
7 1 23
60 2 24
7 1 25
1 26
53 2 27
40 2 28
2 1 29
14 1 30
20 1 31
20 1 32
3 1 33
1 34
1 1 35
20 1 36
1 1 37
4 1 38
12 1 39
30 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 / /2016/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).
MANILA SUB 12.47 138.00DISTRIBUTION-UNATTEN 1
MANTUA SUB 12.47 44.00DISTRIBUTION-UNATTEN 2
MAPLETON SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
MARRIOTT SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
MARYSVALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
MATHIS SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
MCCORNICK SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
MCKAY SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
MEADOWBROOK SUB 12.47 138.00 46.00DISTRIBUTION-UNATTEN 9
MEDICAL SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
MIDLAND SUB 12.47 138.00DISTRIBUTION-UNATTEN 11
MIDVALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
MILFORD SUB 46.00 138.00DISTRIBUTION-UNATTEN 13
MILFORD TV SUB 13.20 46.00DISTRIBUTION-UNATTEN 14
MINERSVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
MOAB CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
MOORE SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
MORGAN SUB 4.16 46.00DISTRIBUTION-UNATTEN 18
MORONI SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
MOUNTAIN DELL SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
MOUNTAIN GREEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
MYTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
NEW HARMONY SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
NEWGATE SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
NEWTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
NIBLEY SUB 24.90 138.00DISTRIBUTION-UNATTEN 26
NORTH BENCH SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
NORTH FIELDS SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
NORTH LOGAN SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
NORTH OGDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
NORTH SALT LAKE SUB 13.20 46.00DISTRIBUTION-UNATTEN 31
NORTHEAST SUB 12.50 46.00DISTRIBUTION-UNATTEN 32
NORTHRIDGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
OAKLAND AVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
OAKLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
OLYMPUS SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
OPHIR SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
ORANGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
ORANGEVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
OREM 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 / /2016/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
22 1 1
2 1 2
14 1 3
20 1 4
3 1 5
9 1 6
6 1 7
20 1 8
42 2 9
57 4 10
30 1 11
25 1 12
89 2 13
1 14
2 1 15
19 2 16
3 1 17
7 2 18
6 1 19
5 1 20
6 1 21
6 1 22
7 1 23
20 1 24
5 1 25
14 1 26
25 1 27
2 1 28
25 1 29
22 1 30
25 1 31
45 2 32
14 1 33
24 2 34
6 1 35
22 1 36
3 1 37
20 1 38
14 1 39
48 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 / /2016/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).
PACK CREEK RESERVOIR 12.47 46.00DISTRIBUTION-UNATTEN 1
PANGUITCH SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
PARIETTE SUB 24.94 69.00DISTRIBUTION-UNATTEN 3
PARK CITY SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
PARKSIDE SUB 12.47 138.00DISTRIBUTION-UNATTEN 5
PARKWAY SUB 12.47 138.00DISTRIBUTION-UNATTEN 6
PARLEYS SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
PELICAN POINT SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
PINE CANYON SUB 12.47 138.00DISTRIBUTION-UNATTEN 9
PINE CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
PINNACLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
PLAIN CITY SUB 12.47 138.00DISTRIBUTION-UNATTEN 12
PLEASANT GROVE SUB 12.47 138.00DISTRIBUTION-UNATTEN 13
PLEASANT VIEW SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
PONY EXPRESS SUB 12.47 138.00DISTRIBUTION-UNATTEN 15
PORTER ROCKWELL SUB 12.47 138.00DISTRIBUTION-UNATTEN 16
PROMONTORY SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
QUAIL CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
QUARRY SUB 12.47 138.00DISTRIBUTION-UNATTEN 19
QUICHAPA SUB 12.47 34.50DISTRIBUTION-UNATTEN 20
RAINS SUB 7.20 46.00DISTRIBUTION-UNATTEN 21
RANDOLPH SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
RASMUSON SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
RATTLESNAKE SUB 24.90 69.00DISTRIBUTION-UNATTEN 24
RED MOUNTAIN SUB 34.50 69.00DISTRIBUTION-UNATTEN 25
REDWOOD SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
RESEARCH PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
RICH SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
RICHFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
RICHMOND SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
RIDGELAND SUB 12.47 138.00DISTRIBUTION-UNATTEN 31
RITER SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
ROCK CANYON SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
ROCKVILLE SUB 12.47 34.50DISTRIBUTION-UNATTEN 34
ROCKY POINT 13.20 138.00DISTRIBUTION-UNATTEN 35
ROSE PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
ROYAL SUB 4.16 46.00DISTRIBUTION-UNATTEN 37
SALINA SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
SANDY SUB 12.47 138.00DISTRIBUTION-UNATTEN 39
SARATOGA SUB 12.47 138.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.14
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/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
5 1 2
14 1 3
42 2 4
60 2 5
50 2 6
16 2 7
6 1 8
55 2 9
2 1 10
14 1 11
22 1 12
25 1 13
14 1 14
60 2 15
30 1 16
2 1 17
4 1 18
60 2 19
4 1 20
15 1 21
2 1 22
1 3 23
14 1 24
12 1 25
45 2 26
45 2 27
5 1 28
22 2 29
11 1 30
40 2 31
20 1 32
5 1 33
4 1 34
30 1 35
24 3 36
3 37
11 1 38
60 2 39
60 2 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 / /2016/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).
SCIPIO SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
SCOFIELD RESERVOIR SUB 7.20 46.00DISTRIBUTION-UNATTEN 2
SCOFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
SECOND STREET SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
SEGO CANYON SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
SEVEN MILE SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
SHARON SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
SHIVWITS SUB 4.16 34.50DISTRIBUTION-UNATTEN 8
SHORELINE SUB 13.20 138.00DISTRIBUTION-UNATTEN 9
SIXTH SOUTH SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
SKULL VALLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
SKYPARK SUB 12.47 138.00 12.47DISTRIBUTION-UNATTEN 12
SNARR SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
SNOWVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 14
SNYDERVILLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 15
SOLDIER SUMMIT SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
SOUTH JORDAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 17
SOUTH MILFORD SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
SOUTH MOUNTAIN SUB 12.47 138.00DISTRIBUTION-UNATTEN 19
SOUTH OGDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
SOUTH PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 21
SOUTH WEBER SUB 12.47 138.00DISTRIBUTION-UNATTEN 22
SOUTHWEST SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
SPANISH VALLEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
SPRINGDALE SUB 12.47 34.50DISTRIBUTION-UNATTEN 25
ST. JOHNS SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
STANSBURY SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
SUMMIT CREEK SUB 12.47 138.00DISTRIBUTION-UNATTEN 28
SUMMIT PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
SUNRISE SUB 12.47 138.00DISTRIBUTION-UNATTEN 30
SUTHERLAND SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
TAMARISK SUB 12.47 138.00DISTRIBUTION-UNATTEN 32
TAYLOR SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
THIEF CREEK SUB 24.90 138.00DISTRIBUTION-UNATTEN 34
THIRD WEST SUB 13.20 138.00DISTRIBUTION-UNATTEN 35
THIRTEENTH SOUTH SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
TOOELE DEPOT SUB 12.50 46.00DISTRIBUTION-UNATTEN 37
TOQUERVILLE SUB 12.47 69.00 34.50DISTRIBUTION-UNATTEN 38
UINTAH SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
UNION SUB 12.47 46.00DISTRIBUTION-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 / /2016/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 3 1
1 1 2
1 3 3
13 2 4
14 1 5
1 6
20 1 7
6 1 8
60 2 9
20 1 10
2 1 11
40 1 12
40 2 13
5 1 14
60 2 15
12 1 16
60 2 17
20 2 18
60 2 19
25 1 20
30 1 21
22 1 22
22 2 23
6 1 24
4 1 25
4 1 26
20 1 27
14 1 28
7 1 29
60 2 30
6 1 31
20 1 32
14 1 33
14 1 34
100 2 35
22 1 36
25 1 37
34 2 38
39 2 39
50 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.15
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/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).
VALLEY CENTER SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
VERMILLION SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
VERNAL SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
VICKERS SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
VINEYARD SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
WALLSBURG SUB 12.47 138.00DISTRIBUTION-UNATTEN 6
WALNUT GROVE SUB 12.47 138.00DISTRIBUTION-UNATTEN 7
WARREN SUB 12.47 138.00DISTRIBUTION-UNATTEN 8
WASATCH STATE PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
WASHAKIE SUB 4.16 138.00DISTRIBUTION-UNATTEN 10
WELBY SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
WELFARE SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
WEST COMMERCIAL SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
WEST JORDAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 14
WEST OGDEN SUB 12.47 138.00DISTRIBUTION-UNATTEN 15
WEST ROY SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
WEST TEMPLE SUB 4.16 46.00DISTRIBUTION-UNATTEN 17
WESTWATER SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
WHITE ROCK SUB 12.47 138.00DISTRIBUTION-UNATTEN 19
WILLOWCREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
WILLOWRIDGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
WINCHESTER HILLS SUB 12.47 34.50DISTRIBUTION-UNATTEN 22
WINKLEMAN SUB 7.20 46.00DISTRIBUTION-UNATTEN 23
WOLF CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
WOOD CROSS SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
WOODRUFF SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
TOTAL 3502.63 19892.40 105.44 27
Number of Substations-273 28
29
90TH SOUTH SUB 138.00 345.00 12.47T/D-UNATTENDED 30
ANGEL SUB 12.47 138.00 46.00T/D-UNATTENDED 31
BDO SUB 12.47 138.00T/D-UNATTENDED 32
BUTLERVILLE SUB 46.00 138.00 12.47T/D-UNATTENDED 33
CENTENNIAL SUB 12.47 138.00T/D-UNATTENDED 34
COTTONWOOD SUB 12.47 138.00 46.00T/D-UNATTENDED 35
DECADE SUB 12.47 138.00T/D-UNATTENDED 36
DUMAS SUB 12.47 138.00T/D-UNATTENDED 37
EMMA PARK SUB 12.47 138.00T/D-UNATTENDED 38
GROW SUB 12.47 138.00 46.00T/D-UNATTENDED 39
HALE SUB 46.00 138.00 12.47T/D-UNATTENDED 40
FERC FORM NO. 1 (ED. 12-96) Page 426.16
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
22 1 1
3 1 2
33 2 3
2 1 4
25 1 5
13 1 6
30 1 7
30 1 8
2 3 9
14 1 10
42 2 11
10 1 12
22 1 13
28 1 14
60 2 15
25 1 16
60 3 17
5 1 18
30 1 19
1 1 20
14 1 21
4 1 22
1 23
6 1 24
20 1 25
2 1 26
5597 373 2 27
28
29
1572 5 30
135 3 31
30 1 32
205 4 33
40 2 34
289 7 35
60 2 36
60 2 37
8 1 38
72 3 39
114 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.16
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/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).
HIGHLAND SUB 12.47 138.00 46.00T/D-UNATTENDED 1
JORDAN SUB 46.00 138.00 12.47T/D-UNATTENDED 2
JUDGE SUB 12.47 46.00T/D-UNATTENDED 3
MCCLELLAND SUB 46.00 138.00 12.47T/D-UNATTENDED 4
MORTON COURT SUB 12.47 138.00T/D-UNATTENDED 5
OQUIRRH SUB 46.00 345.00 138.00T/D-UNATTENDED 6
PARRISH SUB 12.47 138.00 46.00T/D-UNATTENDED 7
PIONEER PLANT 12.47 138.00T/D-UNATTENDED 8
RIVERDALE SUB 46.00 138.00 12.47T/D-UNATTENDED 9
SEVIER SUB 46.00 138.00 12.47T/D-UNATTENDED 10
SILVER CREEK SUB 12.47 138.00 46.00T/D-UNATTENDED 11
SOUTHEAST SUB 12.47 138.00 46.00T/D-UNATTENDED 12
SYRACUSE SUB 46.00 345.00 138.00T/D-UNATTENDED 13
TAYLORSVILLE SUB 46.00 138.00 12.47T/D-UNATTENDED 14
TERMINAL SUB 46.00 345.00 138.00T/D-UNATTENDED 15
TIMP SUB 46.00 138.00 12.47T/D-UNATTENDED 16
TOOELE SUB 46.00 138.00 12.47T/D-UNATTENDED 17
TRI CITY SUB 12.47 138.00T/D-UNATTENDED 18
WEST VALLEY SUB 12.47 138.00T/D-UNATTENDED 19
WESTFIELD SUB 12.47 138.00T/D-UNATTENDED 20
TOTAL 914.46 5014.00 860.70 21
Number of Substations-31 22
23
EMERY SUB 138.00 345.00 69.00TRANSMISSION-ATTENDE 24
GADSBY SUB 46.00 138.00TRANSMISSION-ATTENDE 25
ABAJO SUB 69.00 138.00TRANSMISSION-UNATTEN 26
ASHLEY SUB 46.00 138.00TRANSMISSION-UNATTEN 27
BARNEY SUB 46.00 138.00TRANSMISSION-UNATTEN 28
BEN LOMOND SUB 230.00 345.00 138.00TRANSMISSION-UNATTEN 29
BLACK ROCK SUB 69.00 230.00TRANSMISSION-UNATTEN 30
BLACKHAWK SUB 69.00 138.00 46.00TRANSMISSION-UNATTEN 31
CAMERON SUB 46.00 138.00TRANSMISSION-UNATTEN 32
CAMP WILLIAMS SUB 138.00 345.00 12.47TRANSMISSION-UNATTEN 33
CLOVER SUB 138.00 345.00 14.40TRANSMISSION-UNATTEN 34
COLUMBIA SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 35
CRANER FLAT SUB 12.47 138.00TRANSMISSION-UNATTEN 36
CROYDON SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 37
CUTLER SUB 46.00 138.00TRANSMISSION-UNATTEN 38
EL MONTE SUB 46.00 138.00TRANSMISSION-UNATTEN 39
GARKANE SUB 46.00 69.00TRANSMISSION-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 / /2016/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.
97 2 1
164 2 2
22 1 3
340 3 4
65 2 5
835 4 1 6
97 2 7
30 1 8
180 3 9
34 4 10
100 2 11
50 2 12
600 5 13
358 4 14
1108 6 2 15
130 2 16
249 3 17
30 1 18
30 1 19
20 1 20
7124 83 3 21
22
23
783 13 24
318 2 25
67 1 26
133 2 27
100 1 28
1813 5 29
75 1 30
100 2 31
25 4 32
169 2 33
448 1 34
71 2 35
40 2 36
81 2 37
50 1 38
312 3 39
33 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.17
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/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).
GREEN CANYON SUB 46.00 138.00TRANSMISSION-UNATTEN 1
GRINDING SUB 13.80 138.00TRANSMISSION-UNATTEN 2
HELPER SUB 46.00 138.00TRANSMISSION-UNATTEN 3
HONEYVILLE SUB 46.00 138.00TRANSMISSION-UNATTEN 4
HORSESHOE SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 5
HUNTINGTON SUB 138.00 345.00 24.90TRANSMISSION-UNATTEN 6
JERUSALEM SUB 46.00 138.00TRANSMISSION-UNATTEN 7
LAMPO SUB 46.00 138.00TRANSMISSION-UNATTEN 8
MATHINGTON SUB 46.00 138.00 13.20TRANSMISSION-UNATTEN 9
MCFADDEN SUB 46.00 138.00TRANSMISSION-UNATTEN 10
MIDDLETON SUB 69.00 138.00 34.50TRANSMISSION-UNATTEN 11
MIDVALLEY SUB 138.00 345.00TRANSMISSION-UNATTEN 12
MIDWAY CITY SUB 46.00 138.00TRANSMISSION-UNATTEN 13
MINERAL PRODUCTS SUB 46.00 69.00TRANSMISSION-UNATTEN 14
MOAB SUB 69.00 138.00TRANSMISSION-UNATTEN 15
NEBO SUB 46.00 138.00TRANSMISSION-UNATTEN 16
PAROWAN VALLEY SUB 138.00 230.00 34.50TRANSMISSION-UNATTEN 17
PAVANT SUB 46.00 230.00TRANSMISSION-UNATTEN 18
PINTO SUB 138.00 345.00 69.00TRANSMISSION-UNATTEN 19
RED BUTTE SUB 138.00 345.00TRANSMISSION-UNATTEN 20
SIGURD SUB 230.00 345.00 138.00TRANSMISSION-UNATTEN 21
SMITHFIELD SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 22
SPANISH FORK SUB 138.00 345.00 46.00TRANSMISSION-UNATTEN 23
ST GEORGE SUB 16.50 138.00TRANSMISSION-UNATTEN 24
THREE PEAKS SUB 138.00 345.00TRANSMISSION-UNATTEN 25
WEST CEDAR SUB 138.00 230.00 34.50TRANSMISSION-UNATTEN 26
TOTAL 3377.77 8441.00 724.35 27
Number of Substations-43 28
29
WASHINGTON 30
ATTALIA SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
BOWMAN SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
CASCADE KRAFT SUB 12.47 69.00 4.16DISTRIBUTION-UNATTEN 33
CLINTON SUB 12.47 115.00DISTRIBUTION-UNATTEN 34
DAYTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
DODD ROAD SUB 20.80 69.00DISTRIBUTION-UNATTEN 36
GRANDVIEW SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 37
HOPLAND SUB 12.47 115.00DISTRIBUTION-UNATTEN 38
NACHES SUB 12.00 115.00DISTRIBUTION-UNATTEN 39
NOB HILL SUB 12.47 115.00DISTRIBUTION-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 / /2016/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
67 2 1
225 3 2
142 2 3
35 1 4
80 2 5
270 4 6
67 1 7
75 1 8
160 5 1 9
45 1 10
141 4 11
900 2 12
67 1 13
12 1 14
67 1 15
67 1 16
138 2 17
133 2 18
258 3 19
414 2 20
1124 6 21
63 2 22
1017 5 23
100 3 1 24
450 1 25
262 3 26
10997 106 2 27
28
29
30
25 1 31
45 2 32
118 6 33
25 1 34
23 2 35
25 4 36
42 2 37
50 2 38
25 1 39
42 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.18
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/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).
NORTH PARK SUB 12.47 115.00DISTRIBUTION-UNATTEN 1
ORCHARD SUB 12.47 115.00DISTRIBUTION-UNATTEN 2
PACIFIC SUB 12.47 115.00DISTRIBUTION-UNATTEN 3
POMEROY SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
PROSPECT POINT SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
PUNKIN CENTER SUB 12.47 115.00DISTRIBUTION-UNATTEN 6
RIVER ROAD SUB 12.47 115.00DISTRIBUTION-UNATTEN 7
SELAH SUB 12.47 115.00DISTRIBUTION-UNATTEN 8
SULPHUR CREEK SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
SUNNYSIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 10
TIETON SUB 12.47 115.00 34.50DISTRIBUTION-UNATTEN 11
TOPPENISH SUB 12.47 115.00DISTRIBUTION-UNATTEN 12
TOUCHET SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
VOELKER SUB 12.47 115.00DISTRIBUTION-UNATTEN 14
WAITSBURG SUB 12.47 69.00DISTRIBUTION-UNATTEN 15
WAPATO SUB 12.47 115.00DISTRIBUTION-UNATTEN 16
WENAS SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
WHITE SWAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 18
WILEY SUB 12.47 115.00DISTRIBUTION-UNATTEN 19
TOTAL 369.49 2921.00 107.66 20
Number of Substations-29 21
22
CENTRAL SUB 12.47 69.00T/D-UNATTENDED 23
MILL CREEK SUB 12.47 69.00T/D-UNATTENDED 24
UNION GAP SUB 115.00 230.00 12.47T/D-UNATTENDED 25
TOTAL 139.94 368.00 12.47 26
Number of Substations-3 27
28
OUTLOOK SUB 115.00 230.00TRANSMISSION-UNATTEN 29
PASCO SUB 69.00 115.00 7.20TRANSMISSION-UNATTEN 30
POMONA HEIGHTS SUB 115.00 230.00 13.20TRANSMISSION-UNATTEN 31
WALLA WALLA 230kV SUB 69.00 230.00TRANSMISSION-UNATTEN 32
WALLULA SUB 69.00 230.00TRANSMISSION-UNATTEN 33
WINE COUNTRY SUB 115.00 230.00TRANSMISSION-UNATTEN 34
TOTAL 552.00 1265.00 20.40 35
Number of Substations-6 36
37
WYOMING 38
ANTELOPE MINE SUB 34.50 230.00DISTRIBUTION-UNATTEN 39
ARROWHEAD SUB 34.50 230.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.19
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/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
50 2 2
28 3 3
9 1 4
40 2 5
20 2 6
76 5 7
45 2 8
25 1 9
45 2 10
29 2 11
50 2 12
6 1 13
25 1 14
9 1 15
45 2 16
25 2 17
22 2 18
45 2 19
1059 60 20
21
22
14 1 23
45 2 24
595 5 25
654 8 26
27
28
125 1 29
39 9 30
325 3 31
300 2 32
120 2 33
250 1 34
1159 18 35
36
37
38
25 1 39
150 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.19
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/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).
ASTLE STREET 13.20 34.50DISTRIBUTION-UNATTEN 1
BAILEY DOME SUB 12.47 57.00DISTRIBUTION-UNATTEN 2
BAR NUNN 13.20 116.00DISTRIBUTION-UNATTEN 3
BAR X SUB 34.50 230.00DISTRIBUTION-UNATTEN 4
BIG MUDDY SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
BIG PINEY SUB 24.90 69.00DISTRIBUTION-UNATTEN 6
BLACKS FORK SUB 34.50 230.00DISTRIBUTION-UNATTEN 7
BRIDGER PUMP SUB 34.50 230.00 13.20DISTRIBUTION-UNATTEN 8
BRYAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
BUFFALO TOWN SUB 4.16 20.80DISTRIBUTION-UNATTEN 10
BYRON SUB 4.16 34.50DISTRIBUTION-UNATTEN 11
CASSA SUB 20.80 57.00 12.47DISTRIBUTION-UNATTEN 12
CENTER STREET SUB 4.16 115.00DISTRIBUTION-UNATTEN 13
CHAPMAN SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
CHUKAR SUB 4.16 12.47DISTRIBUTION-UNATTEN 15
CHURCH AND DWIGHT SUB 0.48 34.50DISTRIBUTION-UNATTEN 16
COKEVILLE SUB 24.90 46.00DISTRIBUTION-UNATTEN 17
COLUMBIA-GENEVA SUB 13.80 230.00DISTRIBUTION-UNATTEN 18
COMMUNITY PARK SUB 13.20 115.00DISTRIBUTION-UNATTEN 19
CROOKS GAP SUB 12.47 34.50DISTRIBUTION-UNATTEN 20
DEER CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
DJ COAL MINE SUB 34.50 69.00DISTRIBUTION-UNATTEN 22
DOUGLAS SUB 2.30 57.00DISTRIBUTION-UNATTEN 23
DRY FORK SUB 4.16 69.00DISTRIBUTION-UNATTEN 24
ELK BASIN SUB 7.20 34.50DISTRIBUTION-UNATTEN 25
EMIGRANT SUB 12.47 115.00DISTRIBUTION-UNATTEN 26
EVANS SUB 12.47 115.00DISTRIBUTION-UNATTEN 27
EVANSTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 28
FORT CASPER SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
FORT SANDERS SUB 13.20 115.00DISTRIBUTION-UNATTEN 30
FRANNIE SUB 34.50 230.00DISTRIBUTION-UNATTEN 31
FRONTIER SUB 4.16 69.00DISTRIBUTION-UNATTEN 32
GARLAND SUB 34.50 230.00DISTRIBUTION-UNATTEN 33
GLENDO SUB 4.16 57.00DISTRIBUTION-UNATTEN 34
GRASS CREEK SUB 34.50 230.00DISTRIBUTION-UNATTEN 35
GREAT DIVIDE SUB 34.50 115.00DISTRIBUTION-UNATTEN 36
GREYBULL SUB 4.16 34.50DISTRIBUTION-UNATTEN 37
HANNA SUB 12.47 34.50DISTRIBUTION-UNATTEN 38
JACKALOPE SUB 12.47 115.00DISTRIBUTION-UNATTEN 39
KEMMERER SUB 24.90 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 / /2016/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
12 1 1
2 1 2
30 1 3
25 1 4
7 1 5
14 1 6
150 2 7
73 4 8
25 1 9
2 3 10
2 3 11
2 6 12
12 1 13
4 1 14
1 3 15
3 2 16
4 1 17
45 2 18
45 2 19
5 3 20
9 1 21
12 1 22
6 3 23
9 1 24
5 1 25
12 1 26
9 1 27
40 2 28
28 1 29
20 1 30
50 2 31
6 1 32
45 2 33
3 4 34
25 1 35
20 1 36
3 1 37
6 1 38
25 1 39
10 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 / /2016/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).
KIRBY CREEK PUMPING STATION 2.40 115.00DISTRIBUTION-UNATTEN 1
KIRBY CREEK SUB 4.16 34.50DISTRIBUTION-UNATTEN 2
LANDER SUB 12.47 34.50DISTRIBUTION-UNATTEN 3
LARAMIE SUB 13.20 115.00DISTRIBUTION-UNATTEN 4
LATHAM SUB 34.50 230.00DISTRIBUTION-UNATTEN 5
LINCH SUB 13.80 69.00DISTRIBUTION-UNATTEN 6
LITTLE MOUNTAIN SUB 34.50 230.00DISTRIBUTION-UNATTEN 7
LOVELL SUB 4.16 34.50DISTRIBUTION-UNATTEN 8
MILL IRON SUB 13.80 34.50DISTRIBUTION-UNATTEN 9
MILLS SUB 4.16 46.00DISTRIBUTION-UNATTEN 10
MURPHY DOME SUB 13.20 34.50DISTRIBUTION-UNATTEN 11
NUGGETT SUB 7.20 69.00DISTRIBUTION-UNATTEN 12
OPAL SUB 24.90 69.00DISTRIBUTION-UNATTEN 13
ORIN SUB 7.20 57.00DISTRIBUTION-UNATTEN 14
ORPHA SUB 7.20 57.00DISTRIBUTION-UNATTEN 15
PARADISE SUB 25.00 69.00DISTRIBUTION-UNATTEN 16
PARCO SUB 12.47 34.50DISTRIBUTION-UNATTEN 17
PINEDALE SUB 24.90 69.00DISTRIBUTION-UNATTEN 18
PITCHFORK SUB 24.90 69.00DISTRIBUTION-UNATTEN 19
POISON SPIDER SUB 2.40 69.00DISTRIBUTION-UNATTEN 20
POLECAT SUB 12.47 34.50DISTRIBUTION-UNATTEN 21
RAINBOW SUB 13.20 34.50DISTRIBUTION-UNATTEN 22
RAVEN SUB 34.50 230.00DISTRIBUTION-UNATTEN 23
RED BUTTE SUB 13.20 115.00DISTRIBUTION-UNATTEN 24
REFINERY SUB 12.47 115.00DISTRIBUTION-UNATTEN 25
SAGE HILL SUB 13.20 34.50DISTRIBUTION-UNATTEN 26
SHOSHONI SUB 2.40 34.50DISTRIBUTION-UNATTEN 27
SLATE CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
SOUTH CODY SUB 24.90 69.00DISTRIBUTION-UNATTEN 29
SOUTH ELK BASIN SUB 4.16 34.50DISTRIBUTION-UNATTEN 30
SOUTH TRONA SUB 34.50 230.00DISTRIBUTION-UNATTEN 31
SPRING CREEK SUB 13.20 115.00DISTRIBUTION-UNATTEN 32
SVILAR SUB 4.16 34.50DISTRIBUTION-UNATTEN 33
TEN MILE STEP DOWN SUB 12.50 34.50DISTRIBUTION-UNATTEN 34
TEN MILE SUB 34.50 69.00DISTRIBUTION-UNATTEN 35
THERMOPOLIS TOWN SUB 4.16 34.50DISTRIBUTION-UNATTEN 36
THUNDER CREEK SUB 12.47 57.00DISTRIBUTION-UNATTEN 37
VETERANS SUB 13.20 34.50DISTRIBUTION-UNATTEN 38
WERTZ-SINCLAIR SUB 4.16 57.00 12.50DISTRIBUTION-UNATTEN 39
WEST ADAMS SUB 4.16 34.50DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.21
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
3 3 1
2 3 2
25 2 3
50 2 4
25 1 5
12 1 6
20 1 7
4 1 8
12 1 9
1 3 10
5 1 11
1 12
8 1 13
1 1 14
3 3 15
30 1 16
5 1 17
20 1 18
17 9 2 19
3 1 20
1 3 21
12 1 22
200 2 23
30 1 24
45 2 25
6 1 26
2 3 27
1 1 28
14 3 1 29
2 6 30
150 2 31
28 1 32
2 3 33
5 1 34
12 1 35
5 1 36
9 1 37
25 2 38
2 6 39
3 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 / /2016/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).
WESTVACO SUB 34.50 230.00DISTRIBUTION-UNATTEN 1
WORLAND TOWN SUB 4.16 34.50DISTRIBUTION-UNATTEN 2
WYOPO SUB 34.50 230.00DISTRIBUTION-UNATTEN 3
TOTAL 1339.66 7896.27 38.17 4
Number of Substations-85 5
6
BUFFALO SUB 20.80 230.00T/D-UNATTENDED 7
ELK HORN SUB 12.47 115.00T/D-UNATTENDED 8
FIREHOLE SUB 34.50 230.00T/D-UNATTENDED 9
HILLTOP SUB 34.50 115.00 20.80T/D-UNATTENDED 10
LABARGE SUB 24.90 69.00T/D-UNATTENDED 11
POINT OF ROCKS SUB 34.50 230.00T/D-UNATTENDED 12
RIVERTON 230 SUB 12.47 230.00 34.50T/D-UNATTENDED 13
YELLOWCAKE SUB 34.50 230.00T/D-UNATTENDED 14
TOTAL 208.64 1449.00 55.30 15
Number of Substations-8 16
17
DAVE JOHNSTON PLANT/SUB 115.00 230.00 69.00TRANSMISSION-ATTENDE 18
JIM BRIDGER 345kV SUB 230.00 345.00 34.50TRANSMISSION-ATTENDE 19
NAUGHTON SUB 138.00 230.00 69.00TRANSMISSION-ATTENDE 20
BAIROIL SUB 34.50 115.00 57.00TRANSMISSION-UNATTEN 21
CASPER SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 22
CHAPPEL CREEK SUB 69.00 230.00TRANSMISSION-UNATTEN 23
CHIMNEY BUTTE SUB 69.00 230.00TRANSMISSION-UNATTEN 24
FOOTE CREEK WIND FARM 34.50 230.00TRANSMISSION-UNATTEN 25
GLENDO AUTO SUB 57.00 69.00TRANSMISSION-UNATTEN 26
MANSFACE SUB 34.50 230.00TRANSMISSION-UNATTEN 27
MIDWEST SUB 69.00 230.00 34.50TRANSMISSION-UNATTEN 28
MINERS SUB 34.50 230.00 9.70TRANSMISSION-UNATTEN 29
MUSTANG SUB 115.00 230.00TRANSMISSION-UNATTEN 30
OREGON BASIN SUB 34.50 230.00 69.00TRANSMISSION-UNATTEN 31
PLATTE SUB 115.00 230.00 34.50TRANSMISSION-UNATTEN 32
RAILROAD SUB 138.00 230.00TRANSMISSION-UNATTEN 33
ROCK SPRINGS 230 SUB 34.50 230.00TRANSMISSION-UNATTEN 34
SAGE SUB 46.00 69.00TRANSMISSION-UNATTEN 35
STANDPIPE SUB 12.47 230.00TRANSMISSION-UNATTEN 36
THERMOPOLIS SUB 115.00 230.00TRANSMISSION-UNATTEN 37
TOTAL 1610.47 4278.00 446.20 38
Number of Substations-20 39
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 / /2016/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
5 1 2
20 1 1 3
1831 154 4 4
5
6
20 1 7
25 1 8
50 2 9
45 2 1 10
8 6 11
25 1 12
74 4 13
25 1 14
272 18 1 15
16
17
336 4 18
703 7 19
661 4 20
53 3 21
575 4 22
67 1 23
75 1 24
196 2 25
15 2 26
20 1 27
157 3 28
20 1 29
100 1 30
65 2 31
140 3 32
400 1 33
50 2 34
23 1 35
75 1 36
175 2 37
3906 46 38
39
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 / /2016/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
Distribution - 42 2
T/D - 2 3
Transmission - 5 4
5
IDAHO 6
Distribution - 65 7
T/D - 5 8
Transmission - 17 9
10
MONTANA 11
Transmission - 3 12
13
OREGON 14
Distribution - 180 15
T/D - 12 16
Transmission - 27 17
18
UTAH 19
Distribution - 273 20
T/D - 31 21
Transmission - 43 22
23
WASHINGTON 24
Distribution - 29 25
T/D - 3 26
Transmission - 6 27
28
WYOMING 29
Distribution - 85 30
T/D - 8 31
Transmission - 20 32
33
ALL STATES 34
Distribution - 674 35
T/D - 61 36
Transmission - 121 37
38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 426.23
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2016/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
323 2
130 3
725 4
5
6
736 7
344 8
5081 9
10
11
200 12
13
14
4615 15
1260 16
7492 17
18
19
5597 20
7124 21
10997 22
23
24
1059 25
654 26
1159 27
28
29
1831 30
272 31
3906 32
33
34
14161 35
9784 36
29560 37
38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.23
Schedule Page: 426.3 Line No.: 18 Column: a
The Antelope 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: 426.3 Line No.: 20 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.: 25 Column: a
The Goshen 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.: 27 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.: 28 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.: 32 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.: 38 Column: a
The Broadview 500kV Substation is jointly owned by PacifiCorp, NorthWestern Energy, Puget
Sound Energy, Inc., Portland General Electric Company and Avista Corporation. Ownership
and operations and maintenance costs vary by type of asset as defined in the Transmission
Agreement.
Schedule Page: 426.3 Line No.: 39 Column: a
The Colstrip 500kV Substation is jointly owned by PacifiCorp, NorthWestern
Energy, Puget Sound Energy, Inc., Portland General Electric Company and Avista
Corporation. Ownership and operations and maintenance costs vary by type of asset as
defined in the Transmission Agreement.
Schedule Page: 426.9 Line No.: 10 Column: a
The Dixonville 500kV Substation is jointly owned by PacifiCorp and Bonneville Power
Administration ("BPA"). Ownership of the substation is as follows: PacifiCorp 50.0% and
BPA 50.0%. Operation and maintenance costs are shared between the two parties and
responsibility is as follows: PacifiCorp 58.0% and BPA 42.0%.
Schedule Page: 426.9 Line No.: 14 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.: 19 Column: a
The Malin 500kV Substation is jointly owned by PacifiCorp, BPA and Portland General
Electric Company. Ownership and operations and maintenance costs vary by type of asset
defined in the Joint Ownership and Operating Agreement.
Schedule Page: 426.9 Line No.: 20 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: 426.19 Line No.: 32 Column: a
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Joint Ownership and Operating Agreement.
Schedule Page: 426.22 Line No.: 18 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.: 19 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
2016/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
/ /2016/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 185,190,751Bridger Coal Company 151,501
3 Coal purchases 11,194,071Trapper Mining Inc. 151,501
4 Administrative services under the IASA 5,820,689BHE
5 Administrative services under the IASA 3,199,195MEC
6 Administrative services under the IASA 364,975NV Energy, Inc. 107,923
7 Administrative services under the IASA 9,280Kern River Gas Transmission Company 923
8 Gas transportation services and encroachment
9 agreement for Sigurd to Red Butte 3,390,978Kern River Gas Transmission Company 547,571
10 Rail services and right-of-way fees 37,262,344BNSF Railway Company 151,507,567,589
11 Employee relocation services 1,412,541HomeServices of America, Inc.
12 Banking services and financial transactions
13 related to energy hedging activity 1,263,672Wells Fargo & Company
14 Banking services 528,971U.S. Bancorp
15 Computer hardware and software and computer
16 systems maintenance and support services 2,155,311International Business Machines Corp 165,909,921,935
17 Lubricating oil and grease products 750,859Phillips 66 Company
18 Equipment rental 386,710Deere & Company 512,514
19
20 Non-power Goods or Services Provided for Affiliate
21 Information technology and administrative
22 support services 980,399Bridger Coal Company
23 Joint use services 946,509Charter Communications, Inc. 416,454,593
24 Administrative services under the IASA 927,942MEC
25 Administrative services under the IASA 1,496,460BHE U.S. Transmission, LLC
26 Administrative services under the IASA 419,828MTL Canyon Holdings, LLC
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
FERC FORM NO. 1 (New) Page 429
FERC FORM NO. 1-F (New)
Schedule Page: 429 Line No.: 4 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 and regulatory groups. The legislative and 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 and 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.: 4 Column: c
Accounts charged from BHE: 107, 426.1, 426.4, 426.5, 923 and 928.
Schedule Page: 429 Line No.: 4 Column: d
Excluded from this line are "convenience" payments made to vendors by one entity on behalf
of, and charged to, other entities within the BHE group. Such affiliate charges reflect
the ability to obtain price discounts as a result of larger purchasing power.
Excluded from this page are reimbursements by BHE for payments made by PacifiCorp to its
employees under the long-term incentive plan ("LTIP") that was maintained by BHE upon
vesting of the awards. Also excluded from this page are reimbursements of payments related
to wages and benefits associated with transferred employees.
The convenience payments, the LTIP reimbursements and the reimbursements associated with
transferred employees do not constitute "services" as required by this page.
Schedule Page: 429 Line No.: 5 Column: b
This footnote applies to all occurrences of "MEC" on page 429. Complete name is
MidAmerican Energy Company.
Schedule Page: 429 Line No.: 5 Column: c
Accounts charged from MEC: 107, 426.4, 426.5 and 923.
Schedule Page: 429 Line No.: 5 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.: 6 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
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.: 7 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.: 10 Column: d
Non-power goods or services provided by BNSF Railway Company are as follows:
Rail services $37,213,748
Right-of-way fees 48,596
$37,262,344
Included in the rail services are amounts related to a jointly-owned plant that are paid
indirectly to BNSF Railway Company.
Schedule Page: 429 Line No.: 11 Column: c
Accounts charged from HomeServices of America, Inc.: 506, 535, 539, 548, 549, 557, 560,
561.2, 570, 580, 581, 590, 592, 593, 903, 908 and 921.
Schedule Page: 429 Line No.: 13 Column: c
Accounts charged from Wells Fargo & Company: 186, 228.3, 419, 426.5, 427, 431, 501, 547,
548, 903, 921 and 928.
Schedule Page: 429 Line No.: 13 Column: d
Non-power goods or services provided by Wells Fargo & Company are as follows:
Banking services $1,128,022
Financial transactions related to energy hedging activity 135,650
$1,263,672
Schedule Page: 429 Line No.: 14 Column: c
Accounts charged from U.S. Bancorp: 186, 419, 427, 431, 537, 557, 589, 903, 920, 928 and
930.2.
Schedule Page: 429 Line No.: 16 Column: b
Complete name is International Business Machines Corporation.
Schedule Page: 429 Line No.: 17 Column: c
Accounts charged from Phillips 66 Company: 154, 500, 501, 502, 506, 511, 512, 513, 514,
539, 548, 553, 557, 562, 570, 571, 582, 583, 592 and 593.
Schedule Page: 429 Line No.: 22 Column: c
Accounts charged to Bridger Coal Company: 426.5, 501, 557, 923 and 930.2.
Schedule Page: 429 Line No.: 24 Column: c
Accounts charged to MEC: 426.5, 556, 557, 580, 588, 590, 903, 920 and 921.
Schedule Page: 429 Line No.: 24 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.: 25 Column: c
Accounts charged to BHE U.S. Transmission, LLC: 426.5, 560, 580, 920 and 921.
Schedule Page: 429 Line No.: 25 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.: 26 Column: c
Accounts charged to MTL Canyon Holdings, LLC: 560, 580, 920 and 921.
Schedule Page: 429 Line No.: 26 Column: d
Excluded from this line are "convenience" payments made to vendors by one entity on behalf
of, and charged to, other entities within the BHE group. Such affiliate charges reflect
the ability to obtain price discounts as a result of larger purchasing power and do not
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
constitute "services" as required by this page.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2016/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)