2020Annual Report FERC Form and Supplement.pdf

1407 W. North Temple, Suite 330 Salt Lake City, Utah 84116 May 26, 2021
VIA ELECTRONIC FILING Idaho Public Utilities Commission
11331 W Chinden Blvd.
Building 8 Suite 201A Boise, ID 83714 Attention: Jan Noriyuki
Commission Secretary Re: Annual Idaho Form 1 Report – 2020 Rocky Mountain Power, a division of PacifiCorp, hereby submits for filing the Idaho Public
Utilities Commission Annual State Form 1 report for 2020. This is being provided with PacifiCorp’s annual FERC Form 1. It is respectively requested that all formal correspondence and staff requests regarding this matter be addressed to:
By E-mail (preferred): [e-mail] By Fax: [phone]
By regular mail: Data Request Response Center PacifiCorp 825 NE Multnomah, Suite 2000 Portland, OR 97232
Any informal inquiries may be directed to Ted Weston, Idaho Regulatory Manager at 801-220-2963. Sincerely,
Joelle Steward Vice President, Regulation
RECEIVED
2021May 26, PM 11:03
IDAHO PUBLIC
UTILITIES COMMISSION
PAC-E
THIS FILING IS
Item 1: An Initial (Original)
Submission
OR Resubmission No. ____X
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
OMB No.1902-0021
OMB No.1902-0029
OMB No.1902-0205
(Expires 11/30/2022)
(Expires 11/30/2022)
(Expires 11/30/2022)
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 2020/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 1,168
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 168 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
IDENTIFICATION
FERC FORM NO. 1/3-Q:
REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER
Nikki L. Kobliha (Signature on file)
825 N.E. Multnomah Street, Suite 1900, Portland, OR 97232
2020/Q4
825 N.E. Multnomah Street, Suite 1900, Portland, OR 97232
01 Exact Legal Name of Respondent
(1) An Original (2) A ResubmissionX
02 Year/Period of Report
End ofPacifiCorp
03 Previous Name and Date of Change (if name changed during year)
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
05 Name of Contact Person 06 Title of Contact Person
07 Address of Contact Person (Street, City, State, Zip Code)
08 Telephone of Contact Person,Including
Area Code
09 This Report Is 10 Date of Report
(Mo, Da, Yr)
01 Name
02 Title
03 Signature 04 Date Signed
(Mo, Da, Yr)
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
/ /
Mark Reis Corporate Accounting Director
[phone] / /
Nikki L. Kobliha
Vice President, CFO and Treasurer 04/14/2021
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accounts.
FERC FORM No.1/3-Q (REV. 02-04)Page 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
LIST OF SCHEDULES (Electric Utility)
PacifiCorp X
/ /
2020/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
/ /
2020/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
/ /
2020/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
/ /2020/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
approximately 2.0 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
2020/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
/ /2020/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., Mr. Walter Scott, Jr., a member of BHE's Board of Directors (along with his family members
and related or affiliated entities) and Mr. Gregory E. Abel, BHE's Chairman, beneficially own 91.1%, 7.9% and 1.0%,
respectively, of BHE's voting 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
/ /
2020/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 100.00 1 Energy West Mining Company
Mining 100.00 2 Fossil Rock Fuels, LLC
Mining 100.00 3 Glenrock Coal Company
Management services 100.00 4 Interwest Mining Company
Management services 100.00 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.: 2 Column: a
Fossil Rock Fuels, LLC was dissolved in 2020.

Schedule Page: 103 Line No.: 3 Column: a
Glenrock Coal Company ceased mining operations in 1999 and was dissolved in 2020.
Schedule Page: 103 Line No.: 4 Column: a
Interwest Mining Company was dissolved in 2020.

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. As of December 31,
2020, the members were 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%).
On January 1, 2021, Tri-State Generation and Transmission Association, Inc. terminated its
membership in the cooperative, changing the member interests for Salt River Project
Agricultural Improvement and Power District (43.72%), PacifiCorp (29.14%) and Platte River
Power Authority (27.14%).
Schedule Page: 103 Line No.: 8 Column: c
The PacifiCorp Foundation ("Foundation") is an independent non-profit foundation created
by PacifiCorp in 1988. The Foundation operates as the Rocky Mountain Power Foundation and
the Pacific Power Foundation. As of December 31, 2020, the Foundation's two 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
2020/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
/ /
2020/Q4
Line
No.
Title Name of Officer Salaryfor Year(c)(b)(a)
1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
Executive Officers as of December 31, 2020: 1
2
Chairman of the Board of Directors 3
and Chief Executive Officer, PacifiCorp William J. Fehrman 4
5
President and Chief Executive Officer, 6
Pacific Power 375,000Stefan A. Bird 7
8
President and Chief Executive Officer, 9
Rocky Mountain Power 361,080Gary W. Hoogeveen 10
11
Vice President, Chief Financial Officer and Treasurer, 12
PacifiCorp 262,260Nikki L. Kobliha 13
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FERC FORM NO. 1 (ED. 12-96) Page 104
Schedule Page: 104 Line No.: 1 Column: a
PacifiCorp sets forth compensation information for its "named executive officers" for the
year ended December 31, 2020, consistent with Item 402 of Regulation S-K promulgated by
the United States 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 C.F.R. §388.107(d),(f).
Schedule Page: 104 Line No.: 4 Column: c
Mr. Fehrman received no direct compensation from PacifiCorp. PacifiCorp reimbursed
its indirect parent company, Berkshire Hathaway Energy Company ("BHE"), for the cost of
Mr. Fehrman’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. For further information on executive compensation, refer to BHE’s Annual
Report on Form 10-K, for the year ended December 31, 2020.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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
/ /
2020/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, 2020: 1
2
William J. Fehrman 3
666 Grand Avenue, 27th Floor, Des Moines, IA 50309(Chairman of the Board of Directors and CEO, PacifiCorp) 4
5
Stefan A. Bird 6
825 N.E. Multnomah Street, Suite 2000, Portland, OR 97232(President and CEO, Pacific Power) 7
8
Gary W. Hoogeveen 9
1407 West North Temple, Suite 310, Salt Lake City, UT 84116(President and CEO, Rocky Mountain Power) 10
11
Nikki L. Kobliha 12
825 N.E. Multnomah Street, Suite 1900, Portland, OR 97232(VP, CFO and Treasurer, PacifiCorp) 13
14
825 N.E. Multnomah Street, Suite 2000, Portland, OR 97232Natalie L. Hocken 15
16
666 Grand Avenue, 27th Floor, Des Moines, IA 50309Calvin D. Haack 17
18
666 Grand Avenue, 27th Floor, Des Moines, IA 50309Patrick J. Goodman 19
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47
48
FERC FORM NO. 1 (ED. 12-95) Page 105
Schedule Page: 105 Line No.: 17 Column: a
Mr. Haack was elected as a director of PacifiCorp on May 29, 2020. For further
information, refer to Item 13 in Important Changes During the Year in this Form No. 1.
Schedule Page: 105 Line No.: 19 Column: a
Mr. Goodman resigned as a director of PacifiCorp effective May 29, 2020. 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
2020/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
/ /2020/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
/ /2020/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
03/18/202020200318-5087 ER20-1335 1
05/14/202020200514-5161 ER11-3643 2
05/14/202020200514-5180 ER20-1828 3
12/22/202020201222-5045 ER21-711 4
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FERC FORM NO. 1 (NEW. 12-08) Page 106a
Schedule Page: 1061 Line No.: 1 Column: d
PacifiCorp submits tariff filing per 35.13(a)(2)(iii): OATT Revised Attachment H-1
(Revised Depreciation Rates 2020) to be effective 6/1/2020 under FERC Docket No. ER20-1335

Schedule Page: 1061 Line No.: 1 Column: e
PacifiCorp's Volume No. 11 Open Access Transmission Tariff

Schedule Page: 1061 Line No.: 2 Column: d
Transmission Formula Rate Annual Update Informational Filing of PacifiCorp under FERC
Docket No. ER11-3643

Schedule Page: 1061 Line No.: 2 Column: e
PacifiCorp's Volume No. 11 Open Access Transmission Tariff
Schedule Page: 1061 Line No.: 3 Column: d
PacifiCorp submits tariff filing per 35: OATT Order 864 Compliance Filing to be effective
6/1/2020 under FERC Docket No. ER20-1828
Schedule Page: 1061 Line No.: 3 Column: e
PacifiCorp's Volume No. 11 Open Access Transmission Tariff

Schedule Page: 1061 Line No.: 4 Column: d
PacifiCorp submits tariff filing per 35.13(a)(2)(iii): OATT Revised Attachment H-1
(Revised Depreciation Rates) to be effective 1/1/2021 under FERC Docket No. ER21-711, as
supplemented on January 6, 2021

Schedule Page: 1061 Line No.: 4 Column: e
PacifiCorp's Volume No. 11 Open Access Transmission Tariff

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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
/ /2020/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.
204-207 Electric Plant in Service (b) 46 1
204-207 Electric Plant in Service (g) 46 2
204-207 Electric Plant in Service (g) 58 3
204-207 Electric Plant in Service (b) 75 4
204-207 Electric Plant in Service (g) 75 5
204-207 Electric Plant in Service (b) 99 6
204-207 Electric Plant in Service (g) 99 7
204-207 Electric Plant in Service (b) 104 8
204-207 Electric Plant in Service (g) 104 9
219 Accum. Prov. for Depr. of Electric Utility Plant (c) 20 10
219 Accum. Prov. for Depr. of Electric Utility Plant (c) 22 11
219 Accum. Prov. for Depr. of Electric Utility Plant (c) 24 12
219 Accum. Prov. for Depr. of Electric Utility Plant (c) 25 13
219 Accum. Prov. for Depr. of Electric Utility Plant (c) 26 14
219 Accum. Prov. for Depr. of Electric Utility Plant (c) 28 15
219 Accum. Prov. for Depr. of Electric Utility Plant (c) 29 16
320-323 Electric Operation and Maintenance Expenses (b) 185 17
320-323 Electric Operation and Maintenance Expenses (b) 197 18
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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 / /2020/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)
None
Oregon(3)
Dallas 09/28/2020 09/28/2030 7.0%
Glendale 06/25/2020 06/25/2030 7.0%
Lebanon 01/22/2020 01/22/2030 7.0%
Wasco 05/13/2020 05/13/2025 3.5%
Utah(4)
Brighton 05/01/2020 05/01/2025 —
Copperton 05/15/2020 05/15/2040 —
Duchesne County 04/19/2020 04/19/2030 —
Eagle Mountain 03/01/2020 03/01/2025 —
Genola 08/01/2020 08/01/2045 —
Grantsville 04/01/2020 04/01/2040 —
Kearns 07/11/2020 07/11/2030 —
Lindon 11/01/2020 11/01/2030 —
Magna 08/01/2020 08/01/2030 —
Nibley 07/01/2020 07/01/2040 —
White City 09/01/2020 09/01/2030 —
Washington(5)
Grandview 12/20/2020 12/20/2040 —
Waitsburg 02/07/2020 02/07/2040 —
Zillah 05/13/2020 05/13/2030 —
Wyoming(6)
None
(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, PacifiCorp collects associated taxes from customers and remits them directly to the applicable municipalities. If applicable, franchise agreement fees
are an expense to PacifiCorp and are embedded in rates.
(5) In Washington, PacifiCorp collects associated taxes from customers and remits them directly to the applicable municipalities.
(6) 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
2020/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 2020, PacifiCorp acquired from Cedar Springs Transmission LLC ("Cedar Springs"), the 200-megawatt Cedar Springs
II wind-powered generating facility, including interests in generation interconnection facilities, located in Wyoming. PacifiCorp and
Cedar Springs filed a joint application for the transfer of assets with the Federal Energy Regulatory Commission ("FERC") under the
Federal Power Act Section 203(a)(1), 16 U.S.C. § 824b(a)(1) (2012), in Docket No. EC19-67, which the FERC approved in May
2019. PacifiCorp will file accounting entries with the FERC, within six months of the December 1, 2020 consummation of the
transaction.
ITEM 4.
None.
ITEM 5.
In November 2020, PacifiCorp completed a major segment of the Energy Gateway Transmission expansion program and placed
in-service the 140-mile 500kV Aeolus-Bridger/Anticline transmission line and supporting segments. In addition, to address
transmission line constraints, the 40-mile 230kV Pomona-Vantage transmission line in Washington was placed in-service. For
additional information, refer to pages 424-425, Transmission lines added during the year in this Form No. 1.
ITEM 6.
Short-term Debt
Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of December 31, 2020, PacifiCorp had $93 million of
short-term debt outstanding at a weighted average interest rate of 0.16%.
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:
FERC – Docket No. ES20-1, dated December 12, 2019, letter order effective January 1, 2020 through December 31,
2021.
Idaho Public Utilities Commission ("IPUC") – Case No. PAC-E-16-03, Order No. 33476, dated March 4, 2016,
effective through April 30, 2021, extended in Case No. PAC-E-21-02, Order No. 34927, dated February 23, 2021,
effective through April 30, 2026.
Oregon Public Utility Commission ("OPUC") – Docket No. UF-4120, Order No. 98-158, dated April 16, 1998.

Washington Utilities and Transportation Commission ("WUTC") – Docket No. UE-980404, dated April 8, 1998.
For further discussion, refer to Note 7 of Notes to Financial Statements in this Form No. 1.
Long-term Debt
In April 2020, PacifiCorp issued $400 million of its 2.70% First Mortgage Bonds due September 2030 and $600 million of its 3.30%
First Mortgage Bonds due March 2051. PacifiCorp used the net proceeds to fund capital expenditures, primarily for renewable
resources and associated transmission projects and for general corporate 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
2020/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.2
State commission authorizations for the above issuance were as follows:
IPUC – Case No. PAC-E-18-10, Order No. 34205, dated December 7, 2018.
OPUC – Docket No. UF-4304, Order No. 18-452, dated December 4, 2018.
As of December 31, 2020, PacifiCorp had regulatory authorization from the OPUC and the IPUC to issue an additional $3 billion of
long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. Also, as of December 31, 2020,
PacifiCorp had an effective shelf registration statement with the United States Securities and Exchange Commission to issue an
indeterminate amount of first mortgage bonds through September 2023.
State commission authorizations to issue an additional $3 billion of long-term debt are as follows:
IPUC – Case No. PAC-E-20-15, Order 34831, dated November 12, 2020, effective through September 30, 2025.
OPUC – Docket No. UF-4318, Order No. 20-393, dated November 3, 2020.
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,
2020, PacifiCorp estimated it would be able to issue up to $10.8 billion of new first mortgage bonds under the most restrictive
issuance test in the mortgage. Any issuances are subject to market conditions and amounts may be further limited by regulatory
authorizations or commitments or by covenants and tests contained in other financing agreements. PacifiCorp also has the ability to
release property from the lien of the mortgage on the basis of property additions, bond credits or deposits of cash.
For further discussion, refer to Note 8 of Notes to Financial Statements in this Form No. 1.
ITEM 7.
None.
ITEM 8.
For the year ended December 31, 2020, PacifiCorp's bargaining unit wage scale changes were as follows:
Unions Represented % Increase(1)Effective Date(s)
Estimated Annual
Financial Impact(2)
IBEW 57 Combustion Turbine (UT) 3.25% 01/26/2020 $ 105,525
IBEW 57 Laramie (WY) 1.60% 06/26/2020 10,476
IBEW 57 Power Delivery (UT, ID & WY) 2.76% 01/26/2020 2,311,597
IBEW 57 Power Supply (UT, ID & WY) 2.90% 01/26/2020 1,084,414
IBEW 659 (OR, CA) 1.69% 04/26/2020 528,475
IBEW 77 (WA) 2.33% 01/26/2020 26,781
IBEW 125 (OR, WA) 2.33% 01/26/2020 651,324
UWUA 127 (WY) 0.53% 09/26/2020 251,375
UWUA 197 (OR) 1.52% 05/26/2020 19,832
Total $4,989,799
(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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.3
ITEM 9.
For information regarding certain legal proceedings affecting PacifiCorp, including matters related to wildfires in California and
Oregon during calendar year 2020, refer to Note 14 of Notes to Financial Statements in this Form No. 1.
ITEM 10.
During the year ended December 31, 2020, PacifiCorp dissolved the wholly owned subsidiaries of Fossil Rock Fuels, LLC, Glenrock
Coal Company and Interwest Mining Company.
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, 2020.
ITEM 11.
(Reserved.)
ITEM 12.
None.
ITEM 13.
On May 29, 2020, Patrick J. Goodman, Executive Vice President of Berkshire Hathaway Energy Company ("BHE"), resigned as a
director of PacifiCorp and Calvin D. Haack, Senior Vice President and Chief Financial Officer of BHE was elected as a director of
PacifiCorp.
ITEM 14.
Not applicable.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.4

Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
PacifiCorp / /2020/Q4
UTILITY PLANT 1
30,752,136,973 28,843,430,112200-201Utility Plant (101-106, 114) 2
1,539,838,861 2,002,448,524200-201Construction Work in Progress (107) 3
32,291,975,834 30,845,878,636TOTAL Utility Plant (Enter Total of lines 2 and 3) 4
10,874,594,134 10,870,776,722200-201(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5
21,417,381,700 19,975,101,914Net 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
21,417,381,700 19,975,101,914Net 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
12,333,949 13,320,639Nonutility Property (121) 18
3,224,650 3,196,879(Less) Accum. Prov. for Depr. and Amort. (122) 19
69,928 69,928Investments in Associated Companies (123) 20
137,091,815 201,902,001224-225Investment 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
106,378,001 102,845,814Other Investments (124) 24
0 0Sinking Funds (125) 25
0 0Depreciation Fund (126) 26
0 0Amortization Fund - Federal (127) 27
35,358,662 36,427,872Other Special Funds (128) 28
0 0Special Funds (Non Major Only) (129) 29
6,372,711 2,278,492Long-Term Portion of Derivative Assets (175) 30
0 0Long-Term Portion of Derivative Assets – Hedges (176) 31
294,380,416 353,647,867TOTAL 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
11,310,312 10,421,766Cash (131) 35
69,648 0Special Deposits (132-134) 36
0 0Working Fund (135) 37
52,513 11,969,487Temporary Cash Investments (136) 38
1,374,246 2,405,884Notes Receivable (141) 39
472,567,933 420,564,473Customer Accounts Receivable (142) 40
39,312,444 30,462,387Other Accounts Receivable (143) 41
17,084,938 7,644,908(Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42
0 0Notes Receivable from Associated Companies (145) 43
28,457,757 795,724Accounts Receivable from Assoc. Companies (146) 44
222,141,625 150,404,985227Fuel Stock (151) 45
0 0227Fuel Stock Expenses Undistributed (152) 46
0 0227Residuals (Elec) and Extracted Products (153) 47
260,235,105 244,022,924227Plant 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 / /2020/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
80,191,819 62,585,511Prepayments (165) 57
0 0Advances for Gas (166-167) 58
0 0Interest and Dividends Receivable (171) 59
1,184,888 924,623Rents Receivable (172) 60
253,806,000 244,728,000Accrued Utility Revenues (173) 61
11,101,465 0Miscellaneous Current and Accrued Assets (174) 62
33,026,440 13,451,134Derivative Instrument Assets (175) 63
6,372,711 2,278,492(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
1,391,374,546 1,182,813,498Total Current and Accrued Assets (Lines 34 through 66) 67
DEFERRED DEBITS 68
37,670,714 33,683,227Unamortized Debt Expenses (181) 69
0 0230aExtraordinary Property Losses (182.1) 70
0 0230bUnrecovered Plant and Regulatory Study Costs (182.2) 71
1,296,157,597 1,119,161,023232Other Regulatory Assets (182.3) 72
1,673,810 576,164Prelim. 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
0 -14,358Temporary Facilities (185) 77
101,368,220 114,194,930233Miscellaneous Deferred Debits (186) 78
0 0Def. Losses from Disposition of Utility Plt. (187) 79
0 0352-353Research, Devel. and Demonstration Expend. (188) 80
3,388,709 3,971,176Unamortized Loss on Reaquired Debt (189) 81
777,003,313 783,561,636234Accumulated Deferred Income Taxes (190) 82
0 0Unrecovered Purchased Gas Costs (191) 83
2,217,262,363 2,055,133,798Total Deferred Debits (lines 69 through 83) 84
25,320,399,025 23,566,697,077TOTAL ASSETS (lines 14-16, 32, 67, and 84) 85
FERC FORM NO. 1 (REV. 12-03) Page 111
Schedule Page: 110 Line No.: 44 Column: c
As of December 31, 2020, Account 146, Accounts receivable from associated companies,
included $27,548,045 of income taxes receivable from Berkshire Hathaway Energy Company,
PacifiCorp’s indirect parent company.
Schedule Page: 110 Line No.: 77 Column: d
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
2020/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 / /2020/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
PROPRIETARY CAPITAL 1
3,417,945,8963,417,945,896Common Stock Issued (201) 2 250-251
2,397,6002,397,600Preferred Stock Issued (204) 3 250-251
00Capital Stock Subscribed (202, 205) 4
00Stock Liability for Conversion (203, 206) 5
00Premium on Capital Stock (207) 6
1,102,063,9561,102,063,956Other Paid-In Capital (208-211) 7 253
00Installments Received on Capital Stock (212) 8 252
00(Less) Discount on Capital Stock (213) 9 254
41,101,06141,101,061(Less) Capital Stock Expense (214) 10 254b
3,846,833,9444,628,196,840Retained Earnings (215, 215.1, 216) 11 118-119
125,565,22983,092,814Unappropriated 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
-15,916,633-19,097,488Accumulated Other Comprehensive Income (219) 15 122(a)(b)
8,437,788,9319,173,498,557Total Proprietary Capital (lines 2 through 15) 16
LONG-TERM DEBT 17
7,705,275,0008,667,150,000Bonds (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
24,99613,970Unamortized Premium on Long-Term Debt (225) 22
13,445,28918,031,923(Less) Unamortized Discount on Long-Term Debt-Debit (226) 23
7,691,854,7078,649,132,047Total Long-Term Debt (lines 18 through 23) 24
OTHER NONCURRENT LIABILITIES 25
27,046,12420,983,471Obligations Under Capital Leases - Noncurrent (227) 26
10,159,6114,731,983Accumulated Provision for Property Insurance (228.1) 27
21,850,505153,031,206Accumulated Provision for Injuries and Damages (228.2) 28
159,048,125171,735,512Accumulated Provision for Pensions and Benefits (228.3) 29
34,314,27332,574,469Accumulated Miscellaneous Operating Provisions (228.4) 30
1,500,0009,239,918Accumulated Provision for Rate Refunds (229) 31
22,833,30019,164,041Long-Term Portion of Derivative Instrument Liabilities 32
00Long-Term Portion of Derivative Instrument Liabilities - Hedges 33
256,476,842270,152,870Asset Retirement Obligations (230) 34
533,228,780681,613,470Total Other Noncurrent Liabilities (lines 26 through 34) 35
CURRENT AND ACCRUED LIABILITIES 36
130,000,00093,000,000Notes Payable (231) 37
624,405,083722,327,719Accounts Payable (232) 38
60,042,48924,836,545Notes Payable to Associated Companies (233) 39
136,335,569143,269,702Accounts Payable to Associated Companies (234) 40
44,331,53442,224,507Customer Deposits (235) 41
71,717,47669,730,217Taxes Accrued (236) 42 262-263
117,354,090128,769,917Interest 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 / /2020/Q4
(continued)COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
00Matured Interest (240) 46
21,382,03521,412,558Tax Collections Payable (241) 47
82,553,11795,233,583Miscellaneous Current and Accrued Liabilities (242) 48
3,979,5277,686,260Obligations Under Capital Leases-Current (243) 49
29,690,17926,335,953Derivative Instrument Liabilities (244) 50
22,833,30019,164,041(Less) Long-Term Portion of Derivative Instrument Liabilities 51
00Derivative Instrument Liabilities - Hedges (245) 52
00(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 53
1,298,998,2741,355,703,395Total Current and Accrued Liabilities (lines 37 through 53) 54
DEFERRED CREDITS 55
100,135,630105,190,481Customer Advances for Construction (252) 56
11,203,50712,326,236Accumulated Deferred Investment Tax Credits (255) 57 266-267
00Deferred Gains from Disposition of Utility Plant (256) 58
201,430,606216,557,492Other Deferred Credits (253) 59 269
1,930,223,3761,700,242,286Other Regulatory Liabilities (254) 60 278
00Unamortized Gain on Reaquired Debt (257) 61
174,829,838152,581,995Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277
2,889,829,8792,908,481,325Accum. Deferred Income Taxes-Other Property (282) 63
297,173,549365,071,741Accum. Deferred Income Taxes-Other (283) 64
5,604,826,3855,460,451,556Total Deferred Credits (lines 56 through 64) 65
23,566,697,07725,320,399,025TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 66
FERC FORM NO. 1 (rev. 12-03) Page 113
Schedule Page: 112 Line No.: 39 Column: c
Represents amounts due to Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp,
pursuant to an umbrella loan agreement for which 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, 2020, the interest rate on the outstanding loan balance was
0.16%.
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, 2019, the interest rate on the outstanding loan balance was
2.05%.
Schedule Page: 112 Line No.: 42 Column: d
As of December 31, 2019, Account 236, Taxes accrued, included $28,316,216 of income taxes
payable to Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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
/ /2020/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
5,333,490,161 5,065,712,793300-301Operating Revenues (400) 2
Operating Expenses 3
2,600,315,603 2,427,820,299320-323Operation Expenses (401) 4
425,975,941 404,986,660320-323Maintenance Expenses (402) 5
1,132,669,721 879,989,526336-337Depreciation Expense (403) 6
336-337Depreciation Expense for Asset Retirement Costs (403.1) 7
48,015,712 49,689,883336-337Amort. & Depl. of Utility Plant (404-405) 8
7,826,626 5,083,195336-337Amort. of Utility Plant Acq. Adj. (406) 9
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10
Amort. of Conversion Expenses (407) 11
1,993,985 148,092Regulatory Debits (407.3) 12
1,037,696(Less) Regulatory Credits (407.4) 13
208,904,338 199,137,026262-263Taxes Other Than Income Taxes (408.1) 14
9,029,531 151,665,847262-263Income Taxes - Federal (409.1) 15
29,923,616 34,920,585262-263 - Other (409.1) 16
1,085,922,871 1,188,782,866234, 272-277Provision for Deferred Income Taxes (410.1) 17
1,203,873,466 1,311,969,270234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.1) 18
-2,252,575 -2,738,724266Investment 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
62 173(Less) Gains from Disposition of Allowances (411.8) 22
Losses from Disposition of Allowances (411.9) 23
Accretion Expense (411.10) 24
4,343,414,145 4,027,515,812TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25
990,076,016 1,038,196,981Net 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
/ /2020/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
5,333,490,161 5,065,712,793 2
3
2,600,315,603 2,427,820,299 4
425,975,941 404,986,660 5
1,132,669,721 879,989,526 6
7
48,015,712 49,689,883 8
7,826,626 5,083,195 9
10
11
1,993,985 148,092 12
1,037,696 13
208,904,338 199,137,026 14
9,029,531 151,665,847 15
29,923,616 34,920,585 16
1,085,922,871 1,188,782,866 17
1,203,873,466 1,311,969,270 18
-2,252,575 -2,738,724 19
20
21
62 173 22
23
24
4,343,414,145 4,027,515,812 25
990,076,016 1,038,196,981 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
/ /2020/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)
990,076,016 1,038,196,981Net Utility Operating Income (Carried forward from page 114) 27
Other Income and Deductions 28
Other Income 29
Nonutilty Operating Income 30
1,377,228 2,141,746Revenues From Merchandising, Jobbing and Contract Work (415) 31
1,478,109 2,120,904(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32
Revenues From Nonutility Operations (417) 33
29,731 263,038(Less) Expenses of Nonutility Operations (417.1) 34
371,308 196,104Nonoperating Rental Income (418) 35
17,675,307 23,563,311119Equity in Earnings of Subsidiary Companies (418.1) 36
10,121,094 18,097,499Interest and Dividend Income (419) 37
98,115,567 72,317,120Allowance for Other Funds Used During Construction (419.1) 38
5,504,193 6,570,592Miscellaneous Nonoperating Income (421) 39
2,117,405 3,595,254Gain on Disposition of Property (421.1) 40
133,774,262 124,097,684TOTAL Other Income (Enter Total of lines 31 thru 40) 41
Other Income Deductions 42
4,975 200,037Loss on Disposition of Property (421.2) 43
1,329,358 1,330,948Miscellaneous Amortization (425) 44
2,572,991 2,342,288 Donations (426.1) 45
-7,233,756 -8,140,640 Life Insurance (426.2) 46
40,713 -1,272,934 Penalties (426.3) 47
1,275,212 1,092,950 Exp. for Certain Civic, Political & Related Activities (426.4) 48
6,124,235 34,550,630 Other Deductions (426.5) 49
4,113,728 30,103,279TOTAL Other Income Deductions (Total of lines 43 thru 49) 50
Taxes Applic. to Other Income and Deductions 51
317,911 350,102262-263Taxes Other Than Income Taxes (408.2) 52
1,519,317 -2,461,788262-263Income Taxes-Federal (409.2) 53
344,083 -557,526262-263Income Taxes-Other (409.2) 54
99,704,873 63,463,964234, 272-277Provision for Deferred Inc. Taxes (410.2) 55
99,314,436 62,277,453234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.2) 56
Investment Tax Credit Adj.-Net (411.5) 57
-1,431,198 352,431(Less) Investment Tax Credits (420) 58
4,002,946 -1,835,132TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59
125,657,588 95,829,537Net Other Income and Deductions (Total of lines 41, 50, 59) 60
Interest Charges 61
395,447,394 369,853,259Interest on Long-Term Debt (427) 62
4,430,043 3,892,240Amort. of Debt Disc. and Expense (428) 63
582,467 583,695Amortization 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
68,131 177,870Interest on Debt to Assoc. Companies (430) 67
24,017,899 24,622,419Other Interest Expense (431) 68
47,853,687 36,284,269(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69
376,681,221 362,834,188Net Interest Charges (Total of lines 62 thru 69) 70
739,052,383 771,192,330Income Before Extraordinary Items (Total of lines 27, 60 and 70) 71
Extraordinary Items 72
Extraordinary Income (434) 73
(Less) Extraordinary Deductions (435) 74
Net Extraordinary Items (Total of line 73 less line 74) 75
262-263Income Taxes-Federal and Other (409.3) 76
Extraordinary Items After Taxes (line 75 less line 76) 77
739,052,383 771,192,330Net Income (Total of line 71 and 77) 78
FERC FORM NO. 1/3-Q (REV. 02-04) Page 117
Schedule Page: 114 Line No.: 2 Column: c
The Commission has a price cap for wholesale sales of $1,000 per megawatt hour of energy
sold. Accordingly, amounts in excess of the $1,000 per megawatt hour have been reserved.

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, 2020 and 2019, depreciation expense associated with transportation
equipment was $17,001,326 and $16,386,376, respectively.
Schedule Page: 114 Line No.: 7 Column: c
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as
a regulatory asset.
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, 2020 and 2019, payroll taxes were
$41,280,714 and $40,623,353, respectively.
Schedule Page: 114 Line No.: 24 Column: c
Generally, PacifiCorp records the accretion expense of asset retirement obligations as a
regulatory asset.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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
/ /
2020/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)
3,227,391,376 3,798,019,657 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)
747,629,019 721,377,076 16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
( 4,236,163) -5,177,730215.1 18 Appropriation of excess earnings at certain hydroelectric generating facilities
19
20
21
( 4,236,163) -5,177,730 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)
( 175,000,000)238 31 Common Stock
32
33
34
35
( 175,000,000) 36 TOTAL Dividends Declared-Common Stock (Acct. 438)
2,397,327 60,147,722216.1 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
3,798,019,657 4,574,204,823 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
/ /
2020/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)
48,814,287 53,992,017 46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
48,814,287 53,992,017 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
3,846,833,944 4,628,196,840 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
104,399,245 125,565,229 49 Balance-Beginning of Year (Debit or Credit)
23,563,311 17,675,307 50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
( 2,397,327) -60,147,722 52 Transfers to/from Unappropriated Retained Earnings (Account 216)
125,565,229 83,092,814 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, 2020 and declared dividends on
preferred stock during the year ended December 31, 2020 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, 2019 and declared dividends on
preferred stock during the year ended December 31, 2019 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
During the year ended December 31, 2020, paid distributions from subsidiaries of
PacifiCorp were as follows:
Pacific Minerals, Inc. $60,000,000
Fossil Rock Fuels, LLC 87,149
Trapper Mining Inc. 60,573
$60,147,722
Schedule Page: 118 Line No.: 37 Column: d
During the year ended December 31, 2019, paid distributions from subsidiaries of
PacifiCorp were as follows:
Fossil Rock Fuels, LLC $ 2,397,000
Trapper Mining Inc. 327
$ 2,397,327
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
2020/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
/ /2020/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:
771,192,330 739,052,383 2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
897,855,483 1,151,239,762 4 Depreciation and Depletion
56,127,827 58,003,694 5 Amortization:
6
7
-121,999,893 -117,560,158 8 Deferred Income Taxes (Net)
-3,091,155 -821,377 9 Investment Tax Credit Adjustment (Net)
-1,814,992 -177,191,411 10 Net (Increase) Decrease in Receivables
22,855,227 -87,948,821 11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
-9,920,410 369,736,250 13 Net Increase (Decrease) in Payables and Accrued Expenses
-64,974,675 -173,153,044 14 Net (Increase) Decrease in Other Regulatory Assets
9,960,664 -55,931,765 15 Net Increase (Decrease) in Other Regulatory Liabilities
72,317,120 98,115,567 16 (Less) Allowance for Other Funds Used During Construction
21,165,984 -42,472,415 17 (Less) Undistributed Earnings from Subsidiary Companies
22,900,991 -49,558,460 18 Amounts Due To/From Affiliates (Net)
12,400,000 23,200,000 19 Derivative Collateral (Net)
19,842,961 551,623 20 Other Operating Activities:
21
1,517,851,254 1,623,975,524 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):
-2,247,610,148 -2,637,870,331 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
-72,317,120 -98,115,567 30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32
33
-2,175,293,028 -2,539,754,764 34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
7,608,830 5,817,459 37 Proceeds from Disposal of Noncurrent Assets (d)
38
39 Investments in and Advances to Assoc. and Subsidiary Companies
2,665,000 22,337,771 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
/ /2020/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
733,463 2,045,030 53 Other Investing Activities:
54
55
56 Net Cash Provided by (Used in) Investing Activities
-2,164,285,735 -2,509,554,504 57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
989,337,013 987,159,337 61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
99,950,000 66 Net Increase in Short-Term Debt (c)
29,000,000 67 Other (provide details in footnote):
68
69
1,118,287,013 987,159,337 70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
-350,000,000 -38,125,000 73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
-802,544 -35,243,234 76 Other (provide details in footnote):
-1,479,581 -1,568,715 77 Repayment of Finance Lease Principal in Capital Lease Obligations
-36,935,028 78 Net Decrease in Short-Term Debt (c)
79
-161,902 -161,902 80 Dividends on Preferred Stock
-175,000,000 81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
590,842,986 875,125,458 83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
-55,591,495 -10,453,522 86 (Total of lines 22,57 and 83)
87
84,255,851 28,664,356 88 Cash and Cash Equivalents at Beginning of Period
89
28,664,356 18,210,834 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 finance lease
assets of $18,570,041 and $17,865,957, during the years ended December 31, 2020 and 2019,
respectively.
Schedule Page: 120 Line No.: 5 Column: a
Years Ended December 31,
2020 2019
Amortization of software development & other intangibles $ 49,345,070 $ 51,020,831
Amortization of electric plant acquisition adjustments 7,826,626 5,083,195
Establishment of a regulatory asset (1,037,696) -
Amortization of regulatory assets 1,869,694 23,801
$ 58,003,694 $ 56,127,827
Schedule Page: 120 Line No.: 20 Column: a
Years Ended December 31,
2020 2019
Depreciation and depletion included in cost of fuel $ 2,076,277 $ 2,078,082
Net gain on sale of property (2,412,688) (4,186,776)
Write-off of assets under construction 5,949,328 6,610,739
Change in corporate owned life insurance cash surrender
value (7,204,947) (8,109,131)
Amortization of debt issuance expenses and bond
discount/premium 4,419,017 3,881,214
Change in derivative contract assets/liabilities, net (661,895) (822,620)
Costs associated with the early retirement of Cholla
Unit No. 4 generating facility -23,431,738
Other (1,613,469) (3,040,285)
$ 551,623 $ 19,842,961
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,
2020 2019
Other investments/special funds $ 3,279,838 $ 915,947
Investment in long-term incentive plan securities (1,234,808) (182,484)
$ 2,045,030 $ 733,463
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,
2020 2019
$ (35,165,000) $ -
Net repayments of affiliate borrowing from subsidiary
company, Pacific Minerals, Inc.
Other deferred financing costs (78,234) (802,544)
$ (35,243,234) $ (802,544)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report Year/Period of Report
End of
NOTES TO FINANCIAL STATEMENTS
PacifiCorp X / /2020/Q4
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a
claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on
cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an
explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters
shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
FERC FORM NO. 1 (ED. 12-96) Page 122
PACIFICORP
NOTES TO FINANCIAL STATEMENTS
(1) Organization and Operations
PacifiCorp is a United States regulated electric utility company serving retail customers, including residential, commercial, industrial,
irrigation and other customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp
owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric
transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy
marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal
regulation. PacifiCorp 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 provision for 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 guidance.
For GAAP, unrecognized tax benefits associated with temporary differences are reflected as other liabilities while for FERC
the income tax impact of uncertain tax positions associated with temporary differences are reflected in accumulated deferred
income taxes.
Interest and penalties on income taxes for GAAP are classified as income tax expense. All such amounts are classified as
interest income, interest expense and penalties under the FERC accounting and reporting standards.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.1
Pensions and Postretirement Benefits Other Than Pensions
Pension and postretirement benefits other than pensions ("PBOP") are comprised of several different components of net
periodic benefit costs. As required by GAAP, the service cost component is reported with other compensation costs arising
from services rendered by employees, while the other components of net periodic benefit costs are presented outside of
operating income. Additionally, only the service cost component of net periodic benefit costs is eligible for capitalization
under GAAP. In accordance with FERC guidance, PacifiCorp continues to report the components of net periodic benefit
costs for pension and PBOP on the statement of income and follows GAAP guidance to capitalize only the service cost
component of net periodic benefit costs.
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 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 loss contingencies, including those related to the
Oregon and Northern California 2020 wildfires (the "2020 Wildfires") described in Note 14. 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 recognized in net income, returned to customers 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
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.2
Cash Equivalents and Restricted Cash and Cash Equivalents 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 cash and cash equivalents included in other special funds
primarily consists of vendor retention, custodial and nuclear decommissioning funds.
Cash and cash equivalents and restricted cash and cash equivalents consist of the following amounts as of December 31 (in millions):
2020 2019
Cash (131) $ 11 $ 10
Other special funds (128) 7 7
Temporary cash investments (136) — 12
Total cash and cash equivalents and restricted cash and cash equivalents $18 $29
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, 2020 and 2019,
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 Credit Losses
Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination, and
are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based
on PacifiCorp's assessment of the collectability 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. In measuring for credit losses in trade receivables,
PacifiCorp primarily utilizes credit loss history. However, PacifiCorp may adjust the allowance for credit losses to reflect current
conditions and reasonable and supportable forecasts that deviate from historical experience. The change in the balance of the
allowance for credit losses, 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):
2020 2019
Beginning balance $ 8 $ 8
Charged to operating costs and expenses, net 18 13
Write-offs, net (9)(13)
Ending balance $17 $8
Derivatives
PacifiCorp employs a number of different derivative contracts, which may include forwards, options, swaps and other agreements, to
manage price risk for electricity, natural gas and other commodities and interest rate risk. Derivative contracts are recorded on the
Comparative Balance Sheet as either assets or liabilities and are stated at estimated fair value unless they are designated as normal
purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under
master netting agreements with counterparties and cash collateral paid or received under such agreements.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.3
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 revenue or operations expenses on the Statement of Income.
For PacifiCorp's derivative contracts, the settled amount is generally included in rates. Accordingly, the net unrealized gains and
losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in rates
are recorded as regulatory assets. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized
in earnings.
Inventories
Inventories consist mainly of materials and supplies and fuel stocks (coal, 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 associated 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 represents the estimated costs of debt and equity funds necessary to finance the construction of utility
plant is capitalized as a component of utility plant, with offsetting credits to the Statement of Income. AFUDC is computed based on
guidelines set forth by the FERC. After construction is completed, PacifiCorp is permitted to earn a return on these costs as a
component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
Asset Retirement Obligations
PacifiCorp recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon
retirement of an asset. PacifiCorp's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is
recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying
amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial
recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding
adjustments to utility plant, net) 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
2020/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 appropriate FERC accounts are adjusted to write down the asset 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.
Leases
PacifiCorp has non-cancelable operating leases primarily for land, office space, office equipment, and generating facilities and
finance leases consisting primarily of office buildings, natural gas pipeline facilities, and generating facilities. These leases generally
require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of
the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets,
in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset.
Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices.
PacifiCorp does not include options in its lease calculations unless there is a triggering event indicating PacifiCorp is reasonably
certain to exercise the option. PacifiCorp's accounting policy is to not recognize right-of-use assets and lease obligations for leases
with contract terms of one year or less and not separate lease components from non-lease components and instead account for each
separate lease component and the non-lease components associated with a lease as a single lease component. Right-of-use assets will
be evaluated for impairment in accordance with GAAP when a triggering event has occurred that might affect the value and use of the
assets being leased.
PacifiCorp's leases of generating facilities generally are in the form of long-term purchases of electricity, also known as power
purchase agreements. These agreements are generally signed before or during the early stages of project construction and can yield a
lease that has not yet commenced. Power purchase agreements are primarily for renewable energy and the payments are considered
variable lease payments as they are based on the amount of output.
PacifiCorp follows FERC accounting and reporting requirements and records operating and finance right-of-use assets in Account
101.1, Property under capital leases, and the current and noncurrent operating and finance lease liabilities in Account 243, Obligations
under capital leases – Current and Account 227, Obligations under capital leases – Noncurrent, respectively.
Revenue Recognition
PacifiCorp recognizes revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or
services in an amount that reflects the consideration to which PacifiCorp expects to be entitled in exchange for those goods or
services. 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.
Substantially all of PacifiCorp's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory
commissions. These tariff-based revenues are mainly comprised of energy, transmission and distribution and have performance
obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are
provided. Other revenue primarily consists of contractual agreements, including derivative arrangements.
Revenue recognized is 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 and includes billed and unbilled amounts. Payments for amounts billed are generally due from the
customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual
arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations.
When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue
collected may be subject to refund and classified in accordance with FERC accounting standards.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.5
Unamortized Debt, Premiums, Discounts and Debt Issuance Costs
Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related
financing using the effective interest method.
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 enacted 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 certain
property-related basis differences and other various differences that PacifiCorp deems probable to be passed on to its customers in
most state jurisdictions are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when
the temporary differences reverse or as otherwise approved by PacifiCorp's various regulatory commissions. 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 commissions.
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 commissions. 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.
Coronavirus Disease 2019 ("COVID-19")
In March 2020, COVID-19 was declared a global pandemic and containment and mitigation measures were recommended worldwide,
which has had an unprecedented impact on society in general and many of the customers served by PacifiCorp. While COVID-19 has
impacted PacifiCorp's financial results and operations through December 31, 2020, the impacts have not been material. However,
more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of
COVID-19. The states in which PacifiCorp operates have moved to varying phases of recovery plans with most businesses opening
subject to certain operating restrictions. As the impacts of COVID-19 and related customer and governmental responses remain
uncertain, including the duration of restrictions on business openings, reductions in the consumption of electricity may continue to
occur, particularly in the commercial and industrial classes. Due to regulatory requirements and voluntary actions taken by PacifiCorp
related to customer collection activity and suspension of disconnections for non-payment, PacifiCorp has seen delays and reductions
in cash receipts from retail customers related to the impacts of COVID-19, which could result in higher than normal bad debt
write-offs. The amount of such reductions in cash receipts through December 2020 has not been material compared to the same period
in 2019, but uncertainty remains. Regulatory jurisdictions may allow for the deferral or recovery of certain costs incurred in
responding to COVID-19.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.6
Segment Information
PacifiCorp currently has one segment, which includes its regulated electric utility operations.
Subsequent Events
PacifiCorp has evaluated the impact of events occurring after December 31, 2020 up to February 26, 2021, 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, 2021. 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 4.1% and 3.3% for the years ended
December 31, 2020 and 2019, respectively, including the impacts of accelerated depreciation totaling $376 million and $125 million
in 2020 and 2019, respectively, for Utah's share of certain thermal plant units in 2020, including Cholla Unit No. 4 in 2020 for which
operations ceased in December 2020; Oregon's and Idaho's shares of Cholla Unit No. 4 in 2020; and Oregon's share of certain retired
wind equipment associated with wind repowering projects in 2020 and 2019. As discussed in Note 9, existing regulatory liabilities
primarily associated with the Utah Sustainability and Transportation Plan and the Tax Cuts and Jobs Act enacted on December 22,
2017, were utilized to accelerate depreciation of these assets.
PacifiCorp filed a depreciation study in 2018 with each of its state public utility commissions except the California Public Utilities
Commission. In 2020, PacifiCorp reached settlement stipulations with parties to the depreciation study in each state in which the
study was filed and received commission orders to implement revised depreciation rates effective January 1, 2021. In December 2020,
PacifiCorp filed applicable revised depreciation rates with the FERC under PacifiCorp's open access transmission tariff, which were
accepted by the FERC effective January 1, 2021. The revised depreciation rates will result in an estimated increase in depreciation
expense of $176 million in 2021 on a total company basis based on historical utility plant balances and including depreciation of
certain coal-fueled generating units in Oregon and Washington over accelerated periods. These accelerated depreciable lives for the
coal-fueled units are mainly due to state legislation requiring these costs to be excluded from customers' rates before 2026 and 2030
for Washington and Oregon, respectively.

(4) Jointly Owned Utility Facilities
Under joint facility ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly
owned generation, transmission and distribution facilities. PacifiCorp accounts for its proportionate share of each facility, and each
joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on
their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the
Statement of Income include PacifiCorp's share of the expenses of these facilities.
The amounts shown in the table below represent PacifiCorp's share in each jointly owned facility included in net utility plant, as of
December 31, 2020 (dollars in millions):
Facility Accumulated Construction
PacifiCorp in Depreciation and Work-in-
Share Service Amortization Progress
Jim Bridger Nos. 1 - 4 67 % $ 1,490 $ 737 $ 15
Hunter No. 1 94 486 199 1
Hunter No. 2 60 305 124 —
Wyodak 80 476 254 2
Colstrip Nos. 3 and 4 10 255 145 6
Hermiston 50 184 96 2
Craig Nos. 1 and 2 19 368 173 —
Hayden No. 1 25 75 43 —
Hayden No. 2 13 44 26 —
Transmission and distribution facilities Various 857 314 100
Total $4,540 $2,111 $126
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.7
(5) Leases
The following table summarizes PacifiCorp's leases recorded on the Comparative Balance Sheet as of December 31 (in millions):
2020 2019
Right-of-use assets:
Operating leases $ 11 $ 12
Finance leases 18 19
Total right-of-use assets $29 $31
Lease liabilities:
Operating leases $ 11 12
Finance leases 18 19
Total lease liabilities $29 $31
The following table summarizes PacifiCorp's lease costs for the years ended December 31 (in millions):
2020 2019
Variable $ 60 $ 77
Operating 3 3
Finance:
Amortization 2 1
Interest 2 2
Short-term 1 2
Total lease costs $68 $85
Weighted-average remaining lease term (years):
Operating leases 13.9 14.0
Finance leases 8.4 9.1
Weighted-average discount rate:
Operating leases 3.8%3.7%
Finance leases 10.5%10.6%
Cash payments associated with operating and finance lease liabilities approximated lease cost for the years ended December 31, 2020
and 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
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.8
PacifiCorp has the following remaining lease commitments as of (in millions):
December 31, 2020
Operating Finance Total
2021 $3 $7 $10
2022 2 3 5
2023 2 2 4
2024 1 2 3
2025 1 2 3
Thereafter 6 13 19
Total undiscounted lease payments 15 29 44
Less - amounts representing interest (4)(11)(15)
Lease liabilities $11 $18 $29
(6) Regulatory Matters
Regulatory Assets
PacifiCorp had regulatory assets not earning a return on investment of $704 million and $605 million as of December 31, 2020 and
2019, respectively.
(7) Short-term Debt and Credit Facilities
The following table summarizes PacifiCorp's availability under its credit facilities as of December 31 (in millions):
2020:
Credit facilities $ 1,200
Less:
Short-term debt (93)
Tax-exempt bond support (218)
Net credit facilities $889
2019:
Credit facilities $ 1,200
Less:
Short-term debt (130)
Tax-exempt bond support (256)
Net credit facilities $814
As of December 31, 2020, PacifiCorp was in compliance with the covenants of its credit facilities and letter of credit arrangements.
PacifiCorp has a $600 million unsecured credit facility expiring in June 2022 and a $600 million unsecured credit facility expiring in
June 2022 with one remaining one-year extension option subject to lender 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
variable interest rates based on the Eurodollar 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.9
As of December 31, 2020 and 2019, the weighted average interest rate on commercial paper borrowings outstanding was 0.16% and
2.05%, 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, 2020 and 2019, PacifiCorp had $11 million and $13 million, respectively, of fully available letters of credit
issued under committed arrangements. As of December 31, 2020 and 2019, $11 million and $13 million, respectively, support certain
transactions required by third parties and generally 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.
(8) Long-term Debt
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.
As of December 31, 2020, PacifiCorp had regulatory authorization from the Oregon Public Utility Commission and the Idaho Public
Utilities Commission to issue an additional $3.0 billion of long-term debt. PacifiCorp must make a notice filing with the Washington
Utilities and Transportation Commission prior to any future issuance. Also, as of December 31, 2020, PacifiCorp had an effective
shelf registration statement filed with the United States Securities and Exchange Commission to issue an indeterminate amount of first
mortgage bonds through September 2023.
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's
mortgage. Approximately $30 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage
as of December 31, 2020.
As of December 31, 2020, the annual principal maturities of long-term debt for 2021 and thereafter are as follows (in millions):
Long-term
Debt
2021 $ 420
2022 605
2023 449
2024 591
2025 302
Thereafter 6,300
Total 8,667
Unamortized discount (18)
Total $8,649
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.10
(9) Income Taxes
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
2020 2019
Current:
Federal $ 11 $ 149
State 30 34
Total 41 183
Deferred:
Federal (120) (127)
State 2 5
Total (118)(122)
Investment tax credits (1) (3)
Total income tax (benefit) expense $(78)$58
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:
2020 2019
Federal statutory income tax rate 21 % 21%
State income taxes, net of federal income tax benefit 3 3
Effects of ratemaking (22) (13)
Federal income tax credits (14) (3)
Other — (1)
Effective income tax rate (12)%7%
Income tax credits relate primarily to production tax credits ("PTC") earned by PacifiCorp's wind-powered generating facilities.
Federal renewable electricity PTCs 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.
Effects of ratemaking is primarily attributable to use of excess deferred income taxes of $118 million and $91 million for 2020 and
2019, respectively, to accelerate depreciation of certain retired wind equipment and coal-fueled generating units and to amortize
certain regulatory asset balances in accordance with regulatory orders issued in Utah, Oregon, and Idaho.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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):
2020 2019
Deferred income tax assets:
Regulatory liabilities $ 442 $ 476
Employee benefits 93 83
Derivative contracts and unamortized contract values 17 33
State carryforwards 73 70
Loss contingencies 35 3
Asset retirement obligations 65 61
Other 52 58
777 784
Deferred income tax liabilities:
Property, plant and equipment (3,061) (3,065)
Regulatory assets (343) (276)
Other (22)(21)
(3,426)(3,362)
Net deferred income tax liability $(2,649)$(2,578)
The following table provides PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December 31,
2020 (in millions):
State
Net operating loss carryforwards $ 1,138
Deferred income taxes on net operating loss carryforwards $ 53
Expiration dates 2023 – 2032
Tax credit carryforwards $ 20
Expiration dates 2021 - indefinite
The United States Internal Revenue Service has closed or effectively settled its examination of PacifiCorp's income tax returns
through December 31, 2013. The statute of limitations for PacifiCorp's state income tax returns have expired through December 31,
2011, with the exception of Utah, for which the statute has expired through December 31, 2009. In addition, Idaho's statute of
limitations has expired through December 31, 2016, except for the impact of any federal audit adjustments. The statute of limitations
expiring for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for
which the statute of limitations is not closed.
(10) Employee Benefit Plans
PacifiCorp sponsors defined benefit pension and other postretirement benefit plans that cover certain 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
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.12
Defined 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.
During 2018, the Retirement Plan incurred a settlement charge of $22 million as a result of excess lump sum distributions over the
defined threshold for the year ended December 31, 2018.
PacifiCorp's other postretirement benefit plan provides healthcare and life insurance benefits to eligible retirees.
Net Periodic Benefit Cost
For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets
is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the
first year in which they occur.
Net periodic benefit credit for the plans included the following components for the years ended December 31 (in millions):
Pension Other Postretirement
2020 2019 2020 2019
Service cost $ — $ — $ 2 $ 2
Interest cost 36 44 9 12
Expected return on plan assets (56) (67) (14) (21)
Net amortization 18 11 3 —
Net periodic benefit credit $(2)$(12)$— $(7)
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
2020 2019 2020 2019
Plan assets at fair value, beginning of year $ 1,036 $ 942 $ 334 $ 297
Employer contributions(1)5 4 — 1
Participant contributions — — 4 5
Actual return on plan assets 124 181 15 55
Benefits paid (101) (91) (26) (24)
Plan assets at fair value, end of year $1,064 $1,036 $327 $334
(1) Amounts represent employer contributions to the SERP.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.13
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
Pension Other Postretirement
2020 2019 2020 2019
Benefit obligation, beginning of year $ 1,167 $ 1,105 $ 304 $ 298
Service cost — — 2 2
Interest cost 36 44 9 12
Participant contributions — — 4 5
Actuarial loss 100 109 14 11
Benefits paid (101) (91) (26) (24)
Benefit obligation, end of year $1,202 $1,167 $307 $304
Accumulated benefit obligation, end of year $1,202 $1,167
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
2020 2019 2020 2019
Plan assets at fair value, end of year $ 1,064 $ 1,036 $ 327 $ 334
Less - Benefit obligation, end of year 1,202 1,167 307 304
Funded status $(138)$(131)$20 $30
Amounts recognized on the Comparative Balance Sheet:
Other special funds (128) $ 8 $ — $ 20 $ 30
Miscellaneous current and accrued liabilities (242) (4) (4) — —
Accumulated provision for pension and benefits (228.3) (142) (127) — —
Amounts recognized $(138)$(131)$20 $30
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
$61 million and $57 million as of December 31, 2020 and 2019, respectively. These assets are not included in the plan assets in the
above table, but are reflected primarily in other investments as of December 31, 2020 and 2019, on the Comparative Balance Sheet.
The projected benefit obligation and the accumulated benefit obligation for the pension plan were both in excess of the fair value of
the plan assets as of December 31, 2020.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.14
Unrecognized Amounts
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in
millions):
Pension Other Postretirement
2020 2019 2020 2019
Net loss (gain) $ 455 $ 442 $ (13) $ (26)
Regulatory deferrals 2 1 3 6
Total $457 $443 $(10)$(20)
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2020
and 2019 is as follows (in millions):
Accumulated
Other
Regulatory Comprehensive
Asset Loss Total
Pension
Balance, December 31, 2018 $443 $17 $460
Net (gain) loss arising during the year (11) 5 (6)
Net amortization (10)(1)(11)
Total (21)4 (17)
Balance, December 31, 2019 422 21 443
Net loss arising during the year 27 5 32
Net amortization (17)(1)(18)
Total 10 4 14
Balance, December 31, 2020 $432 $25 $457
Regulatory
Asset (Liability)
Other Postretirement
Balance, December 31, 2018 $5
Net gain arising during the year (25)
Net amortization —
Total (25)
Balance, December 31, 2019 (20)
Net loss arising during the year 13
Net amortization (3)
Total 10
Balance, December 31, 2020 $(10)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.15
Plan Assumptions
Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
Pension Other Postretirement
2020 2019 2020 2019
Benefit obligations as of December 31:
Discount rate 2.50% 3.25% 2.50% 3.20%
Rate of compensation increase N/A N/A N/A N/A
Interest crediting rates for cash balance plan(1)(2)0.82% 2.27% N/A N/A
Net periodic benefit cost for the years ended December 31:
Discount rate 3.25% 4.25% 3.20% 4.25%
Expected return on plan assets 6.50 7.00 4.92 6.86
(1) 2020 Cash Balance Interest Crediting Rate assumption is 0.82% for 2021-2022 and 2.00% for 2023 and all future years for nonunion participants and 1.42%
for 2021-2022 and 2.40% for 2023+ for union participants.
(2) 2019 Cash Balance Interest Crediting Rate assumption was 2.27% for 2020-2021 and 2.10% for 2022 and all future years for nonunion participants and
2.16% for 2020-2021 and 2.70% for 2022+ for union participants.
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 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 a labor settlement reached with United Mine Workers of America ("UMWA") in
December 2014, 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 $4 million and $1 million,
respectively, during 2021. 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 evaluates a variety of factors, including funded status, income tax
laws and regulatory requirements, in determining contributions to its other postretirement benefit plan.
The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2021 through 2025
and for the five years thereafter are summarized below (in millions):
Projected Benefit Payments
Pension Other Postretirement
2021 $ 115 $ 24
2022 99 23
2023 94 22
2024 87 22
2025 82 20
2026-2030 341 90
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.16
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 Berkshire Hathaway Energy Company Investment Committee. The investment portfolio is managed in line
with the investment policy with sufficient liquidity to meet near-term benefit payments.
In 2020, the assets of the PacifiCorp Master Retirement Trust were transferred into the BHE Master Retirement Trust.
The target allocations (percentage of plan assets) for PacifiCorp's pension and other postretirement benefit plan assets are as follows
as of December 31, 2020:
Pension(1)
Other
Postretirement(1)
% %
Debt securities(2)25 – 35 75 – 83
Equity securities(2)53 – 68 16 – 24
Limited partnership interests 7 - 12 1 - 3
(1) The trust in which the PacifiCorp Retirement Plan is invested includes a separate account that is used to fund benefits for the other postretirement benefit
plan. In addition to this separate account, the assets for the other postretirement benefit plan are held in Voluntary Employees' Beneficiary Association
("VEBA") trusts, each of which has its own investment allocation strategies. Target allocations for the other postretirement benefit plan include the separate
account of the Retirement Plan trust and the VEBA trusts.
(2) For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying
investments in debt and equity securities.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.17
Fair Value Measurements
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit pension plan (in
millions):
Input Levels for Fair Value Measurements
Level 1(1)Level 2(1)Level 3(1)Total
As of December 31, 2020:
Cash equivalents $ — $ 32 $ — $ 32
Debt securities:
United States government obligations 14 — — 14
Corporate obligations — 231 — 231
Municipal obligations — 21 — 21
Equity securities:
United States companies 91 ——91
Total assets in the fair value hierarchy $105 $284 $—389
Investment funds(2) measured at net asset value 587
Limited partnership interests(3) measured at net asset value 88
Investments at fair value $1,064
As of December 31, 2019:
Cash equivalents $ — $ 24 $ — $ 24
Debt securities:
United States government obligations 21 — — 21
Corporate obligations — 94 — 94
Municipal obligations — 10 — 10
Agency, asset and mortgage-backed obligations — 42 — 42
Equity securities:
United States companies 355 — — 355
International companies 15 — — 15
Investment funds(2)55 — — 55
Total assets in the fair value hierarchy $446 $170 $—616
Investment funds(2) measured at net asset value 327
Limited partnership interests(3) measured at net asset value 93
Investments at fair value $1,036
(1) Refer to Note 13 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
78% and 22%, respectively for 2020 and 55% and 45%, respectively, for 2019, and are invested in United States and international securities of
approximately 74% and 26%, respectively, for 2020 and 51% and 49%, respectively, for 2019.
(3) Limited partnership interests include several funds that invest primarily in real estate.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.18
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit other postretirement plan
(in millions):
Input Levels for Fair Value Measurements
Level 1(1)Level 2(1)Level 3(1)Total
As of December 31, 2020:
Cash and cash equivalents $ 8 $ 1 $ — $ 9
Debt securities:
United States government obligations 11 — — 11
Corporate obligations — 86 — 86
Municipal obligations — 16 — 16
Agency, asset and mortgage-backed obligations — 44 — 44
Equity securities:
United States companies 4 ——4
Total assets in the fair value hierarchy $23 $147 $—170
Investment funds(2) measured at net asset value 153
Limited partnership interests(3) measured at net asset value 4
Investments at fair value $327
As of December 31, 2019:
Cash and cash equivalents $ 8 $ 1 $ — $ 9
Debt securities:
United States government obligations 12 — — 12
Corporate obligations — 26 — 26
Municipal obligations — 2 — 2
Agency, asset and mortgage-backed obligations — 22 — 22
Equity securities:
United States companies 74 — — 74
International companies 4 — — 4
Investment funds(2)44 ——44
Total assets in the fair value hierarchy $142 $51 $—193
Investment funds(2) measured at net asset value 136
Limited partnership interests(3) measured at net asset value 5
Investments at fair value $334
(1) Refer to Note 13 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
38% and 62%, respectively, for 2020 and 56% and 44%, respectively, for 2019, and are invested in United States and international securities of
approximately 93% and 7%, respectively, for 2020 and 79% and 21%, respectively, for 2019.
(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
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.19
For level 1 investments, a readily observable quoted market price or net asset value of an identical security in an active market is used
to record the fair value. For level 2 investments, the fair value is determined using pricing models 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 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 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.
The following table presents PacifiCorp'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 2020 2019
Funding
improvement
plan
Surcharge
imposed under
PPA(1)2020 2019
Year contributions to plan
exceeded more than 5% of
total contributions(2)
Local 57
Trust Fund 87-0640888 At least 80% At least 80% None None $ 6 $ 7 2018, 2017
(1) PacifiCorp's minimum contributions to the plan are based on the amount of wages paid to employees covered by the Local 57 Trust Fund collective
bargaining agreements, subject to ERISA minimum funding requirements.
(2) For the Local 57 Trust Fund, information is for plan years beginning July 1, 2018 and 2017. Information for the plan year beginning July 1, 2019 is not yet
available.
The current collective bargaining agreements governing the Local 57 Trust Fund expire in 2023.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.20
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, 2020, 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 $41 million
and $40 million for the years ended December 31, 2020 and 2019, respectively.
(11) 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
$1,125 million and $1,019 million as of December 31, 2020 and 2019, respectively.
The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 31
(in millions):
2020 2019
Beginning balance $ 257 $ 227
Change in estimated costs (11) 27
Additions 25 9
Retirements (10) (15)
Accretion 9 9
Ending balance $270 $257
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.
(12) 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.21
PacifiCorp has established a risk management process that is designed to identify, manage 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.
There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Notes 2 and 13 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, 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, 2020:
Not designated as hedging contracts(1):
Commodity assets $ 29 $ 6 $ 1 $ — $ 36
Commodity liabilities (2)— (23) (28)(53)
Total 27 6 (22)(28)(17)
Total derivatives 27 6 (22) (28) (17)
Cash collateral receivable — — 15 9 24
Total derivatives - net basis $27 $6 $(7)$(19)$7
As of December 31, 2019:
Not designated as hedging contracts(1):
Commodity assets $ 15 $ 2 $ 4 $ — $ 21
Commodity liabilities (3) — (31) (50) (84)
Total 12 2 (27)(50)(63)
Total derivatives 12 2 (27) (50) (63)
Cash collateral receivable — — 20 27 47
Total derivatives - net basis $12 $2 $(7)$(23)$(16)
(1) PacifiCorp's commodity derivatives are generally included in rates and as of December 31, 2020 and 2019, a regulatory asset of $17 million and $62 million,
respectively, was recorded related to the net derivative liability of $17 million and $63 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
2020/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 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):
2020 2019
Beginning balance $ 62 $ 96
Changes in fair value recognized in regulatory assets (11) (37)
Net gains (losses) reclassified to operating revenue 3 (34)
Net (losses) gains reclassified to energy costs (37)37
Ending balance $17 $62
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 2020 2019
Electricity sales Megawatt hours (1) (2)
Natural gas purchases Decatherms 100 129
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 agreements, including 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
recognized credit rating agencies. These agreements 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" if there is a material adverse change in PacifiCorp's
creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2020, PacifiCorp's credit ratings for its
senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment
grade.
The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features
totaled $51 million and $80 million as of December 31, 2020 and 2019, respectively, for which PacifiCorp had posted collateral of
$24 million and $47 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, 2020 and 2019, PacifiCorp would have been required to post
$25 million and $27 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably
due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.23
(13) Fair Value Measurements
The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, other investments, payables, accrued liabilities and
short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has various
financial assets and liabilities that are measured at fair value on the financial statements using inputs from the three levels of the fair
value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is
significant to the fair value measurement. The three levels are as follows:
Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the
ability to access at the measurement date.
Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or
similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset
or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other
means (market corroborated inputs).
Level 3 - Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in
pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best
information available, including its own data.
The following table presents PacifiCorp's assets and liabilities recognized on the Comparative Balance Sheet and measured at fair
value on a recurring basis (in millions):
Input Levels for Fair Value
Measurements
Level 1 Level 2 Level 3 Other(1)Total
As of December 31, 2020:
Assets:
Commodity derivatives $ — $ 36 $ — $ (3) $ 33
Money market mutual funds(2)6 — — — 6
Investment funds 24 ———24
$30 $36 $—$(3)$63
Liabilities - Commodity derivatives $—$(53)$—$27 $(26)
As of December 31, 2019:
Assets:
Commodity derivatives $ — $ 21 $ — $ (7) $ 14
Money market mutual funds(2)17 — — — 17
Investment funds 25 — — — 25
$42 $21 $—$(7)$56
Liabilities - Commodity derivatives $—$(84)$—$54 $(30)
(1) Represents netting under master netting arrangements and a net cash collateral receivable of $24 million and $47 million as of December 31, 2020 and 2019,
respectively.
(2) Amounts are included in other special funds and temporary cash investments on the Comparative Balance Sheet. The fair value of these money market
mutual funds approximates cost.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.24
Derivative contracts are recorded on the Comparative Balance Sheet as either assets or liabilities and are stated at estimated fair value
unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the
fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp
transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves
represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates.
PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial
models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers,
exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for
certain major electricity and natural gas trading hubs are generally readily obtainable for the first three 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 three 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 12 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. 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):
2020 2019
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $8,649 $10,995 $7,692 $9,280
(14) 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.
California and Oregon 2020 Wildfires
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major
wildfires, private and public property damage, personal injuries and loss of life and widespread power outages in Oregon and
Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple
counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion
County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon burning over 500,000 acres in aggregate. Third party reports
for these wildfires indicate over 2,000 structures, including residences, destroyed; several structures damaged; multiple individuals
injured; and several fatalities. Fire suppression costs estimated by various agencies total approximately $150 million. Investigations
into the cause and origin of each wildfire are complex and ongoing and are being conducted by various entities, including the United
States Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of
Justice, PacifiCorp and various experts engaged by PacifiCorp.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.25
Seven lawsuits have been filed in Oregon and California, including a putative class action complaint in Oregon, on behalf of citizens
and businesses who suffered damages from fires allegedly caused by PacifiCorp. The final determinations of liability, however, will
only be made following comprehensive investigations and litigation processes.
In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property
damages without the utility being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs
to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through
special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its
equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could nevertheless be found
liable for all damages proximately caused by negligence, including property and natural resource damage; fire suppression costs;
personal injury and loss of life damages; and interest.
PacifiCorp has accrued $136 million as its best estimate of the potential losses net of expected insurance recoveries associated with
the 2020 Wildfires that are considered probable of being incurred. These accruals include estimated losses for fire suppression costs,
property damage, personal injury damages and loss of life damages. It is reasonably possible that PacifiCorp will incur additional
losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that
could be incurred due to the number of properties and parties involved and the lack of specific claims for all potential claimants. To
the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover at least a
portion of the losses.

Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards,
emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected
species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp
believes it is in material compliance with all applicable laws and regulations.
Hydroelectric Relicensing
PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve
disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA establishes a process for
PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent
with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon
and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from
harms associated with dam removal; (3) transfer of the FERC license to a third-party dam removal entity, the Klamath River Renewal
Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of
customers until dam removal commences.
In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four mainstem
Klamath dams from PacifiCorp to the KRRC. The FERC approved partial transfer of the Klamath license in a July 2020 order, subject
to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee
during the surrender and removal process given concerns about liability protections for PacifiCorp and its customers. In November
2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States
to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer
application by January 16, 2021 to remove PacifiCorp from the license for the Klamath Hydroelectric Project and add the States and
KRRC as co-licensees for the purposes of surrender. On January 13, 2021, the new license transfer application was filed with the
FERC, notifying it that PacifiCorp and the KRRC are not accepting co-licensee status under FERC's July 2020 order, and instead are
seeking the license transfer outcome described in the new license transfer application. In addition, the MOA provides for additional
contingency funding of $45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally
share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam
removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental
conditions.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.26
As of December 31, 2020, PacifiCorp's assets included $21 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 in Utah, Wyoming and Idaho through December 31, 2022.
Hydroelectric Commitments
Certain of PacifiCorp's hydroelectric licenses contain requirements for PacifiCorp to make certain capital and operating expenditures
related to its hydroelectric facilities, which are estimated to be approximately $182 million over the next 10 years.
Commitments
PacifiCorp has the following firm commitments that are not reflected on the Comparative Balance Sheet. Minimum payments as of
December 31, 2020 are as follows (in millions):
2021 2022 2023 2024 2025
2026 and
Thereafter Total
Contract type:
Purchased electricity contracts -
commercially operable $ 223 $ 201 $ 195 $ 192 $ 172 $ 2,028 $ 3,011
Purchased electricity contracts -
non-commercially operable 25 25 25 26 28 456 585
Fuel contracts 636 426 368 320 137 611 2,498
Construction commitments 90 — — — — — 90
Transmission 104 97 90 74 49 409 823
Easements 14 14 13 13 13 278 345
Maintenance, service and
other contracts 100 69 40 35 36 214 494
Total commitments $1,192 $832 $731 $660 $435 $3,996 $7,846
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 solar or 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. Certain power
purchase agreements qualify as leases as described in Note 2. Refer to Note 5 for variable lease costs associated with these lease
commitments.
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 operations 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
2020 and 2019 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.27
Fuel Contracts
PacifiCorp has "take or pay" coal and natural gas contracts that require minimum payments.
Construction Commitments
PacifiCorp's construction commitments included in the table above relate to firm commitments and include costs associated with
certain generating plant, 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.

Easements
PacifiCorp has non-cancelable easements for land on which certain of its assets, primarily wind-powered generating facilities, are
located.
Guarantees
PacifiCorp has entered into guarantees as part of the normal course of business and the sale or transfer of certain assets. These
guarantees are not expected to have a material impact on PacifiCorp's financial results.
(15) 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.
(16) Common Shareholder's Equity
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, 2020, 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. As of December 31, 2020, PacifiCorp's actual common equity percentage, as calculated
under this measure, was 53%, and PacifiCorp would have been permitted to dividend $2.7 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, Inc. as indicated by two of the three rating services. As of December 31, 2020, 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 7.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.28
(17) 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):
2020 2019
Interest paid, net of amounts capitalized $ 348 $ 340
Income taxes paid, net(1)$98 $160
Supplemental disclosure of non-cash investing and financing activities:
Accounts payable related to utility plant additions $344 $293
(1) PacifiCorp is party to a tax-sharing agreement and is part of the Berkshire Hathaway United States federal income tax return. Amounts substantially
represent income taxes paid to BHE.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.29
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
PacifiCorp X
/ /2020/Q4
Line
No.
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
Other
Adjustments
(e)
Foreign Currency
Hedges
(d)
Minimum Pension
Liability adjustment
(net amount)
(c)
Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Item
(a)
( 12,635,042)
Balance of Account 219 at Beginning of
Preceding Year
1
578,074
Preceding Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
2
( 3,859,665)
Preceding Quarter/Year to Date Changes in
Fair Value
3
( 3,281,591)Total (lines 2 and 3) 4
( 15,916,633)
Balance of Account 219 at End of Preceding
Quarter/Year
5
( 15,916,633)
Balance of Account 219 at Beginning of
Current Year
6
786,253
Current Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
7
( 3,967,108)
Current Quarter/Year to Date Changes in
Fair Value
8
( 3,180,855)Total (lines 7 and 8) 9
( 19,097,488)
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
/ /2020/Q4
Line
No.
Total
Comprehensive
Income
(j)
Net Income (Carried
Forward from
Page 117, Line 78)
(i)
Totals for each
category of items
recorded in
Account 219
(h)
( 12,635,042) 1
578,074 2
( 3,859,665) 3
771,192,330 767,910,739( 3,281,591) 4
( 15,916,633) 5
( 15,916,633) 6
786,253 7
( 3,967,108) 8
739,052,383 735,871,528( 3,180,855) 9
( 19,097,488) 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
/ /2020/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
29,225,749,548 29,225,749,548Plant in Service (Classified) 3
28,773,303 28,773,303Property Under Capital Leases 4
Plant Purchased or Sold 5
1,317,233,199 1,317,233,199Completed Construction not Classified 6
Experimental Plant Unclassified 7
30,571,756,050 30,571,756,050Total (3 thru 7) 8
Leased to Others 9
23,912,440 23,912,440Held for Future Use 10
1,539,838,861 1,539,838,861Construction Work in Progress 11
156,468,483 156,468,483Acquisition Adjustments 12
32,291,975,834 32,291,975,834Total Utility Plant (8 thru 12) 13
10,874,594,134 10,874,594,134Accum Prov for Depr, Amort, & Depl 14
21,417,381,700 21,417,381,700Net Utility Plant (13 less 14) 15
Detail of Accum Prov for Depr, Amort & Depl 16
In Service: 17
10,045,111,703 10,045,111,703Depreciation 18
Amort & Depl of Producing Nat Gas Land/Land Right 19
Amort of Underground Storage Land/Land Rights 20
689,402,579 689,402,579Amort of Other Utility Plant 21
10,734,514,282 10,734,514,282Total 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
140,079,852 140,079,852Amort of Plant Acquisition Adj 32
10,874,594,134 10,874,594,134Total 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
/ /2020/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
/ /2020/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 209,624,286 2,265,629 3
(303) Miscellaneous Intangible Plant 806,258,510 45,140,753 4
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 1,015,882,796 47,406,382 5
2. PRODUCTION PLANT 6
A. Steam Production Plant 7
(310) Land and Land Rights 92,993,849 -5,141 8
(311) Structures and Improvements 1,056,453,683 8,707,543 9
(312) Boiler Plant Equipment 4,657,546,678 48,824,706 10
(313) Engines and Engine-Driven Generators 11
(314) Turbogenerator Units 1,008,433,107 7,663,275 12
(315) Accessory Electric Equipment 492,434,835 1,633,741 13
(316) Misc. Power Plant Equipment 34,262,485 1,368,761 14
(317) Asset Retirement Costs for Steam Production 159,106,198 16,920,637 15
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 7,501,230,835 85,113,522 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 36,429,166 2,372,597 27
(331) Structures and Improvements 281,578,484 10,248,213 28
(332) Reservoirs, Dams, and Waterways 517,856,965 18,866,613 29
(333) Water Wheels, Turbines, and Generators 143,899,365 4,286,390 30
(334) Accessory Electric Equipment 86,336,749 712,167 31
(335) Misc. Power PLant Equipment 2,577,272 1,714 32
(336) Roads, Railroads, and Bridges 25,037,292 1,452,408 33
(337) Asset Retirement Costs for Hydraulic Production 34
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 1,093,715,293 37,940,102 35
D. Other Production Plant 36
(340) Land and Land Rights 50,958,845 1,790,164 37
(341) Structures and Improvements 231,545,463 37,621,488 38
(342) Fuel Holders, Products, and Accessories 16,218,012 183,051 39
(343) Prime Movers 2,796,951,544 1,017,386,044 40
(344) Generators 498,116,230 89,476,020 41
(345) Accessory Electric Equipment 325,115,884 80,874,583 42
(346) Misc. Power Plant Equipment 16,130,916 6,481,644 43
(347) Asset Retirement Costs for Other Production 19,096,402 30,305,789 44
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 3,954,133,296 1,264,118,783 45
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 12,549,079,424 1,387,172,407 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
/ /2020/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
209,752,933 2,136,982 3
844,621,680 6,777,583 4
1,054,374,613 8,914,565 5
6
7
91,620,243 1,368,465 8
997,012,716 68,148,510 9
4,337,648,373 368,723,011 10
11
941,784,721 74,311,661 12
424,234,732 69,833,844 13
30,788,447 4,842,799 14
156,343,007 -19,683,828 15
6,979,432,239 -19,683,828 587,228,290 16
17
18
19
20
21
22
23
24
25
26
38,801,763 27
289,377,697 2,449,000 28
533,915,462 2,808,116 29
146,463,461 1,722,294 30
86,921,041 127,875 31
2,572,135 6,851 32
26,317,434 172,266 33
34
1,124,368,993 7,286,402 35
36
52,747,960 1,049 37
268,960,711 206,240 38
16,401,063 39
3,388,890,852 -1,176,920 424,269,816 40
552,922,683 -192,938 34,476,629 41
402,779,576 1,252,087 4,462,978 42
22,571,639 40,921 43
48,665,167 -737,024 44
4,753,939,651 -117,771 -737,024 463,457,633 45
12,857,740,883 -117,771 -20,420,852 1,057,972,325 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
/ /2020/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
3. TRANSMISSION PLANT 47
(350) Land and Land Rights 281,363,904 33,835,015 48
(352) Structures and Improvements 283,787,044 23,536,330 49
(353) Station Equipment 2,279,276,707 429,162,676 50
(354) Towers and Fixtures 1,307,439,631 35,330,362 51
(355) Poles and Fixtures 1,015,701,010 333,100,980 52
(356) Overhead Conductors and Devices 1,287,027,290 316,850,103 53
(357) Underground Conduit 3,848,826 8,411 54
(358) Underground Conductors and Devices 8,238,468 842,149 55
(359) Roads and Trails 11,937,200 208,813 56
(359.1) Asset Retirement Costs for Transmission Plant 2,528,190 57
TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 6,478,620,080 1,175,403,029 58
4. DISTRIBUTION PLANT 59
(360) Land and Land Rights 65,329,981 3,287,272 60
(361) Structures and Improvements 124,996,790 1,689,023 61
(362) Station Equipment 1,085,813,833 69,408,435 62
(363) Storage Battery Equipment 63
(364) Poles, Towers, and Fixtures 1,267,917,057 83,921,949 64
(365) Overhead Conductors and Devices 806,824,019 45,386,970 65
(366) Underground Conduit 399,131,386 21,490,279 66
(367) Underground Conductors and Devices 935,090,905 45,799,047 67
(368) Line Transformers 1,433,055,320 69,683,118 68
(369) Services 860,892,630 47,034,186 69
(370) Meters 245,107,614 9,771,082 70
(371) Installations on Customer Premises 8,802,174 85,206 71
(372) Leased Property on Customer Premises 72
(373) Street Lighting and Signal Systems 62,338,943 1,414,572 73
(374) Asset Retirement Costs for Distribution Plant 1,344,766 74
TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 7,296,645,418 398,971,139 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 23,615,657 245,646 86
(390) Structures and Improvements 257,936,605 12,919,351 87
(391) Office Furniture and Equipment 72,082,727 19,907,110 88
(392) Transportation Equipment 119,232,266 14,577,323 89
(393) Stores Equipment 14,958,720 1,193,460 90
(394) Tools, Shop and Garage Equipment 63,565,114 4,679,171 91
(395) Laboratory Equipment 34,959,699 2,003,653 92
(396) Power Operated Equipment 190,961,993 26,143,257 93
(397) Communication Equipment 501,800,356 28,717,798 94
(398) Miscellaneous Equipment 8,519,781 312,596 95
SUBTOTAL (Enter Total of lines 86 thru 95) 1,287,632,918 110,699,365 96
(399) Other Tangible Property 1,854,828 97
(399.1) Asset Retirement Costs for General Plant 39,748 98
TOTAL General Plant (Enter Total of lines 96, 97 and 98) 1,289,527,494 110,699,365 99
TOTAL (Accounts 101 and 106) 28,629,755,212 3,119,652,322 100
(102) Electric Plant Purchased (See Instr. 8) 101
(Less) (102) Electric Plant Sold (See Instr. 8) 102
(103) Experimental Plant Unclassified 103
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 28,629,755,212 3,119,652,322 104
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
/ /2020/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
47
316,648,705 2,011,988 562,202 48
307,051,390 271,984 49
2,692,741,773 126,688 15,824,298 50
1,342,612,357 157,636 51
1,334,393,967 -8,250,877 6,157,146 52
1,609,180,590 8,250,877 2,947,680 53
3,857,237 54
9,080,617 55
12,146,013 56
2,528,190 57
7,630,240,839 2,138,676 25,920,946 58
59
68,539,032 -34,368 43,853 60
126,592,724 93,089 61
1,152,037,123 -8,917 3,176,228 62
63
1,336,560,426 15,278,580 64
846,200,790 6,010,199 65
418,714,601 1,907,064 66
977,356,247 3,533,705 67
1,492,229,942 10,508,496 68
906,830,209 1,096,607 69
251,189,373 23,216 3,712,539 70
8,808,014 79,366 71
72
62,903,579 849,936 73
1,331,349 -13,417 74
7,649,293,409 -20,069 -13,417 46,289,662 75
76
77
78
79
80
81
82
83
84
85
23,863,596 2,293 86
267,093,881 -129,423 3,632,652 87
85,373,133 129,423 6,746,127 88
130,141,333 -1,000 3,667,256 89
15,715,275 436,905 90
63,799,815 4,444,470 91
35,926,482 1,036,870 92
208,705,880 8,399,370 93
510,180,404 1,000 20,338,750 94
8,670,555 -23,216 138,606 95
1,349,470,354 -20,923 48,841,006 96
1,822,901 31,927 97
39,748 98
1,351,333,003 -20,923 48,872,933 99
30,542,982,747 1,979,913 -20,434,269 1,187,970,431 100
101
102
103
30,542,982,747 1,979,913 -20,434,269 1,187,970,431 104
Page 207FERC FORM NO. 1 (REV. 12-05)
Schedule Page: 204 Line No.: 46 Column: b
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance
Beg. of Year
(b)
TOTAL Production Plant 46(b) $12,549,079,424
Less: (317) Asset Retirement Costs for Steam Production(1) 15(b) 159,106,198
Less: (326) Asset Retirement Costs for Nuclear Production(1) 24(b) -
Less: (337) Asset Retirement Costs for Hydraulic Production(1) 34(b) -
Less: (347) Asset Retirement Costs for Other Production(1) 44(b) 19,096,402
Revised TOTAL Production Plant $12,370,876,824
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.

Schedule Page: 204 Line No.: 46 Column: g
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance
End of Year
(g)
TOTAL Production Plant 46(g) $12,857,740,883
Less: (317) Asset Retirement Costs for Steam Production(1) 15(g) 156,343,007
Less: (326) Asset Retirement Costs for Nuclear Production(1) 24(g) -
Less: (337) Asset Retirement Costs for Hydraulic Production(1) 34(g) -
Less: (347) Asset Retirement Costs for Other Production(1) 44(g) 48,665,167
Revised TOTAL Production Plant $12,652,732,709
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 204 Line No.: 58 Column: g
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance at
End of Year
(g)
TOTAL Transmission Plant 58(g) $ 7,630,240,839
Less: (359.1) Asset Retirement Costs for Transmission Plant(1) 58(g) 2,528,190
Revised TOTAL Transmission Plant $ 7,627,712,649
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.

Schedule Page: 204 Line No.: 75 Column: b
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance at
Beg. of Year
(b)
TOTAL Distribution Plant 75(b) $ 7,296,645,418
Less: (374) Asset Retirement Costs for Distribution Plant(1) 74(b) 1,344,766
Revised TOTAL Distribution Plant $ 7,295,300,652
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.
Schedule Page: 204 Line No.: 75 Column: g
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance at
End of Year
(g)
TOTAL Distribution Plant 75(g) $ 7,649,293,409
Less: (374) Asset Retirement Costs for Distribution Plant(1) 74(g) 1,331,349
Revised TOTAL Distribution Plant $ 7,647,962,060
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.

Schedule Page: 204 Line No.: 97 Column: b
Account 399.21, Land owned in fee
Schedule Page: 204 Line No.: 97 Column: g
Refer to footnote on page 204, line no. 97, column (b)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 204 Line No.: 99 Column: b
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance at
Beg. of Year
(b)
TOTAL General Plant 99(b) $ 1,289,527,494
Less: (399) Other Tangible Property(1) 97(b) 1,854,828
Less: (399.1) Asset Retirement Costs for General Plant(2) 98(b) 39,748
Revised TOTAL General Plant $ 1,287,632,918
(1) To adjust PacifiCorp's formula rate, per FERC Docket No. FA16-4-000 for mining assets
related to production plant.
(2) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.

Schedule Page: 204 Line No.: 99 Column: g
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance at
End of Year
(g)
TOTAL General Plant 99(g) $ 1,351,333,003
Less: (399) Other Tangible Property(1) 97(g) 1,822,901
Less: (399.1) Asset Retirement Costs for General Plant(2) 98(g) 39,748
Revised TOTAL General Plant $ 1,349,470,354
(1) To adjust PacifiCorp's formula rate, per FERC Docket No. FA16-4-000 for mining assets
related to production plant.
(2) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 204 Line No.: 104 Column: b
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance at
Beg. of Year
(b)
TOTAL Intangible Plant 5(b) $ 1,015,882,796
Revised TOTAL Production Plant(1) 12,370,876,824
TOTAL Transmission Plant 58(b) 6,478,620,080
Revised TOTAL Distribution Plant(2) 7,295,300,652
Revised TOTAL General Plant(3) 1,287,632,918
(102) Electric Plant Purchased 101(b) -
(Less) (102) Electric Plant Sold 102(b) -
(103) Experimental Plant Unclassified 103(b) -
Revised TOTAL Electric Plant in Service $28,448,313,270
(1) Refer to footnote on page 204, line no. 46, column (b)
(2) Refer to footnote on page 204, line no. 75, column (b)
(3) Refer to footnote on page 204, line no. 99, column (b)
Schedule Page: 204 Line No.: 104 Column: g
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance at
End of Year
(g)
TOTAL Intangible Plant 5(g) $ 1,054,374,613
Revised TOTAL Production Plant(1) 12,652,732,709
TOTAL Transmission Plant(2) 7,627,712,649
Revised TOTAL Distribution Plant(3) 7,647,962,060
Revised TOTAL General Plant(4) 1,349,470,354
(102) Electric Plant Purchased 101(g) -
(Less) (102) Electric Plant Sold 102(g) -
(103) Experimental Plant Unclassified 103(g) -
Revised TOTAL Electric Plant in Service $30,332,252,385
(1) Refer to footnote on page 204, line no. 46, column (g)
(2) Refer to footnote on page 204, line no. 58, column (g)
(3) Refer to footnote on page 204, line no. 75, column (g)
(4) Refer to footnote on page 204, line no. 99, column (g)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
PacifiCorp X
/ /2020/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 746,2682032 2
2007Wild Horse Wind Plant 6,763,0942042 3
2007Twelve Mile Wind Plant 2,160,2072042 4
2008Jumbers Point Substation 1,173,2762026 5
2009Mountain Green Substation 284,9962030 6
2009Hoggard Substation 254,3972025 7
2009Oquirrh-Terminal 345kV Transmission Line 396,0202024 8
2010Bend Service Center 2,982,3212021 9
2010Legacy Substation 562,2762021 10
2011Populus Substation 254,7532023 11
2012Lassen Substation 683,3182021 12
2012Old Mill Substation 1,838,2812027 13
2013Chimney Butte-Paradise 230kV Transmission Line 598,4572026 14
2016Fiddlers Canyon Substation 1,136,5872028 15
2017Gateway Area Substation 3,166,1882025 16
Miscellaneous, each under $250,000: 912,001 17
18
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 23,912,440
Schedule Page: 214 Line No.: 3 Column: c
Land purchased for future development, subject to business strategy and development plans.
Schedule Page: 214 Line No.: 4 Column: c
Land purchased for future development, subject to business strategy and development plans.
Schedule Page: 214 Line No.: 17 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
2020/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
/ /2020/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
3,204,394 Customer Contacts Software Project 2
3,185,867 Cutler Hydro Relicensing 3
2,744,592 Landlord Microsite Software Project 4
2,610,699 Mapping System Consolidation Software 5
2,363,468 Nodal Pricing Model Software (2020 Protocol) 6
2,273,476 SunNet iTOA Outage Management Software Project 7
2,193,685 Computer Aided Distribution Operations System Software Upgrade 8
1,742,759 PAR/SO-IRP Software 9
1,507,566 Weber Hydro Relicensing 10
11
Production: 12
301,322,460 Pryor Mountain Wind Project 240 MW 13
273,262,549 TB Flats Wind Project 500 MW 14
68,183,932 Foote Creek I Wind Repowering 15
39,569,729 Wind Plant Equipment Purchases 16
14,283,999 Lewis River System Relicensing Implementation 17
5,623,723 Huntington Waste Water Redirect 18
4,495,587 Toketee Dam Rehabilitation Evaluation 19
3,470,612 Jim Bridger Coal Combustion Residual Flue Gas Desulfurization Pond 4 Stage 1 20
3,071,769 Yale Saddle Dam Seismic Remediation 21
2,319,489 Jim Bridger U4 Catalyst Replacement, Selective Catalytic Reduction System 22
2,014,976 Hermiston U1 & U2 Low Pressure Evaporator and Feedwater Heater Replacement 23
1,965,923 Viva Naughton FERC Production Compliance 24
1,883,095 Blundell Plant and Steam Field Controls Update 25
1,614,737 Soda Hydro Spinning Reserve 26
1,457,856 Yale Dam Spillway Upgrades Evaluation 27
1,233,404 Bear River Hydro Flood and Structural Assessment Project 28
1,107,040 Cutler Flowline Coating 29
30
Transmission: 31
171,905,891 Aeolus - Mona 500kV Line 32
87,393,236 Boardman - Hemingway 500kV Line 33
71,726,842 Populus - Hemingway 500kV Line 34
49,833,110 Anticline - Populus 500kV Line 35
20,155,315 Windstar - Shirley Basin 230kV Line 36
16,328,379 Oquirrh - Terminal 345kV Line 37
15,394,304 2020 Storm Damage Restoration 38
10,828,244 Sams Valley New 500-230kV Substation 39
10,624,043 Goshen - Sugarmill - Rigby 161kV Line 40
10,344,087 Rexburg Substation - Install 161kV Source from Rigby 41
10,207,756 Jordanelle - Midway 138kV Line 42
FERC FORM NO. 1 (ED. 12-87) Page 216
43 TOTAL 1,539,838,861
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
/ /2020/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.
7,509,901 Spanish Fork Substation 345-138kV Transformer Upgrade TPL 1
6,270,199 Goshen Substation Install 3rd 345-161kV (700 MVA) Transformer TPL 2
4,559,184 Q850 Invenergy - Millican Solar 3
4,096,431 Outlook - Punkin Center 115kV Line #2 4
4,064,008 Grace - Goshen 161kV Line Permits 5
3,981,228 Q766 Hunter Solar, LLC 6
3,575,384 Jim Bridger 345-230kV Transformer 2 Upgrade 7
2,798,288 Hazelwood Tie Line to BPA, Albany New 115kV 8
2,384,280 Aeolus - Bridger/Anticline 500kV Line 9
2,127,541 Spanish Fork - Santaquin 46kV Rebuild for Wildfire 10
2,009,624 Yreka Substation 115-69kV Transformer Addition 11
1,740,405 Madras Purchase 230-69kV (125 MVA) Transformer 12
1,524,314 Purchase Spare 230-161kV (150 MVA) Transformer 13
1,457,670 C7 Data Centers, Load Increase 14
1,191,112 Outlook Substation - Replace Transformer 15
1,154,492 Purchase Spare 230-69kV (150 MVA) Transformer 16
1,128,941 Pole Replacements in Willamette Service Area - Marion, Lane 17
1,108,116 Clearwater 1 Generator Step-Up Transformer Replacement 18
1,028,479 Q804 Clover Creek Solar, LLC 19
20
Distribution: 21
17,396,365 Utah Advanced Metering Infrastructure 22
7,322,415 Wildhorse Resort Phase 2 Load Addition 23
6,524,567 Yellowcake - Install 230-34.5kV (75 MVA) Transformer 24
6,445,464 Genesis Alkali - 27 MW Load 25
5,360,262 NWQ, LLC - 23.75 MW Load 26
4,785,507 Lassen Substation - New Substation 27
4,319,968 California Distribution Spacer Cable Installation 28
3,605,687 WVC Industrial, LLC - 6.363 MW Load 29
3,397,834 Idaho Advanced Metering Infrastructure 30
3,052,666 Flint Substation - Construct New 115-12.5kV Substation 31
3,013,550 Salt Lake Dept of Airports - 14.7 MW Load 32
2,994,674 126th South - New 138-12.47kV Substation 33
2,426,980 Fire High Consequence Area (FHCA) - Rebuild Mountain Dell 11 with Hendrix Cable 34
2,409,950 Utah Underground Cable Replacement 35
2,378,088 California Fire Mitigation - Distribution Substation Relay Replacements 36
2,341,767 Portland Willamette River Crossing Project 37
1,651,793 Fire High Consequence Area (FHCA) - Rebuild Columbia 11 with Hendrix Cable 38
1,505,845 Fire High Consequence Area (FHCA) - Rebuild New Harmony 11 with Hendrix Cable 39
1,450,350 Fire High Consequence Area (FHCA) - Rebuild Eden 11 with Hendrix Cable 40
1,139,315 Oregon Distribution Spacer Cable Installation 41
1,056,160 Centercal Properties, Mountain View II 42
FERC FORM NO. 1 (ED. 12-87) Page 216.1
43 TOTAL 1,539,838,861
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
/ /2020/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.
General: 1
5,485,000 Monarch PAC6 Upgrade and Hardware 2
1,808,752 Replacement of DMX Fiber Optic Communications Infrastructure/Equip - Southern Oregon 3
1,610,356 Lloyd Center Tower - Open Office Plan 4
1,360,351 Madras Service Center - Build Grid Resilience Facility 5
6
167,837,005Miscellaneous 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 216.2
43 TOTAL 1,539,838,861
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
/ /2020/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 10,085,581,074 10,085,581,074
Depreciation Provisions for Year, Charged to 2
(403) Depreciation Expense 3 1,132,669,721 1,132,669,721
(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 9,306,127 9,306,127
9
TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
10 1,141,975,848 1,141,975,848
Net Charges for Plant Retired: 11
Book Cost of Plant Retired 12 1,178,959,378 1,178,959,378
Cost of Removal 13 83,150,037 83,150,037
Salvage (Credit) 14 3,664,643 3,664,643
TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
15 1,258,444,772 1,258,444,772
Other Debit or Cr. Items (Describe, details in
footnote):
16 75,999,553 75,999,553
17
Book Cost or Asset Retirement Costs Retired 18
Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
19 10,045,111,703 10,045,111,703
Steam Production 20
Section B. Balances at End of Year According to Functional Classification
3,828,404,199 3,828,404,199
Nuclear Production 21
Hydraulic Production-Conventional 22 477,257,698 477,257,698
Hydraulic Production-Pumped Storage 23
Other Production 24 260,781,904 260,781,904
Transmission 25 1,942,571,043 1,942,571,043
Distribution 26 3,028,085,015 3,028,085,015
Regional Transmission and Market Operation 27
General 28 508,011,844 508,011,844
TOTAL (Enter Total of lines 20 thru 28) 29 10,045,111,703 10,045,111,703
Page 219FERC FORM NO. 1 (REV. 12-05)
Schedule Page: 219 Line No.: 3 Column: b
For a discussion on provisions for depreciation that were made during the year, refer to
Note 3 of Notes to Financial Statements in this Form No. 1.

Schedule Page: 219 Line No.: 4 Column: b
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as
a regulatory asset.
Schedule Page: 219 Line No.: 8 Column: b
Account 143, Other accounts receivable: depreciation expense
billed to joint owners $ 221,120
Account 182.3, Other regulatory assets or Account 254, Other regulatory
liabilities: asset retirement obligations asset depreciation 25,414,713
Account 182.3, Other regulatory assets: deferral of Carbon generating
facility depreciation (5,081,466)
Account 182.3, Other regulatory assets: deferral of increased
depreciation, due to depreciation study rates, net of amortization (643,868)
Account 254, Regulatory liabilities: Cholla Unit No. 4 generating
facility decommissioning costs (29,628,434)
Account 503, Steam from other sources: Blundell depreciation 2,022,736
Transportation depreciation charged to operations and maintenance
expense and construction work in progress based on usage activity 17,001,326
Total Other Accounts $ 9,306,127
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 $ 8,168,875
Other items include: 67,830,678
- Recovery from third parties for asset relocations and damaged property
- Insurance recoveries
- Adjustments of reserve related to electric plant sold and/or purchased
- Reclassifications to regulatory assets and other accounts
Total Other Debit or Cr. Items $ 75,999,553
Schedule Page: 219 Line No.: 20 Column: c
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Item
(a)
Ref.
Line No.
(Column)
Electric Plant
in Service
(c)
Steam Production 20(c) $ 3,828,404,199
Less: Asset retirement obligations related cost components(1) 99,500,594
Revised Steam Production $ 3,728,903,605
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 219 Line No.: 22 Column: c
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Item
(a)
Ref.
Line No.
(Column)
Electric Plant
in Service
(c)
Hydraulic Production - Conventional 22(c) $ 477,257,698
Less: Asset retirement obligations related cost components(1) 2,677,888
Revised Hydraulic Production - Conventional $ 474,579,810
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.
Schedule Page: 219 Line No.: 24 Column: c
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Item
(a)
Ref.
Line No.
(Column)
Electric Plant
in Service
(c)
Other Production 24(c) $ 260,781,904
Less: Asset retirement obligations related cost components(1) 1,838,037
Revised Other Production $ 258,943,867
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.
Schedule Page: 219 Line No.: 25 Column: c
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Item
(a)
Ref.
Line No.
(Column)
Electric Plant
in Service
(c)
Transmission 25(c) $ 1,942,571,043
Less: Asset retirement obligations related cost components(1) 18,437
Revised Transmission $ 1,942,552,606
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 219 Line No.: 26 Column: c
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Item
(a)
Ref.
Line No.
(Column)
Electric Plant
in Service
(c)
Distribution 26(c) $ 3,028,085,015
Less: Asset retirement obligations related cost components(1) 1,049,560
Revised Distribution $ 3,027,035,455
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.
Schedule Page: 219 Line No.: 28 Column: c
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Item
(a)
Ref.
Line No.
(Column)
Electric Plant
in Service
(c)
General 28(c) $ 508,011,844
Less: Asset retirement obligations related cost components(1) (170,126)
Revised General $ 508,181,970
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.
Schedule Page: 219 Line No.: 29 Column: c
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Item
(a)
Ref.
Line No.
(Column)
Electric Plant
in Service
(c)
Revised Steam Production(1) $ 3,728,903,605
Nuclear Production 21(c) -
Revised Hydraulic Production - Conventional(2) 474,579,810
Hydraulic Production - Pumped Storage 23(c) -
Revised Other Production(3) 258,943,867
Revised Transmission(4) 1,942,552,606
Revised Distribution(5) 3,027,035,455
Regional Transmission and Market Operation 27(c) -
Revised General(6) 508,181,970
Revised TOTAL $ 9,940,197,313
(1) Refer to footnote on page 219, line no. 20, column (c)
(2) Refer to footnote on page 219, line no. 22, column (c)
(3) Refer to footnote on page 219, line no. 24, column (c)
(4) Refer to footnote on page 219, line no. 25, column (c)
(5) Refer to footnote on page 219, line no. 26, column (c)
(6) Refer to footnote on page 219, line no. 28, 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
2020/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
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
PacifiCorp X
/ /2020/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
115,793,091 Undistributed Subsidiary Earnings 4
163,753,092 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
9,771,559 Undistributed Subsidiary Earnings 21
15,809,559 SUBTOTAL 22
23
2011Fossil Rock Fuels, LLC 24
22,336,770 Paid-in Capital 25
579 Undistributed Subsidiary Earnings 26
22,337,349 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 201,902,001 53,999,001
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
/ /2020/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
73,981,802 18,188,711 4
121,941,803 18,188,711 5
6
7
1,000 8
1,000 9
10
11
12
13
14
15
16
17
18
19
6,038,000 20
9,111,012 -599,974 21
15,149,012 -599,974 22
23
24
25
86,570 26
86,570 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 17,675,307 137,091,815
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. Bridger Coal Company is a coal mining joint
venture with Idaho Energy Resources Company, a subsidiary of Idaho Power Company.
Schedule Page: 224 Line No.: 4 Column: g
During the year ended December 31, 2020, Pacific Minerals, Inc., a wholly owned subsidiary
of PacifiCorp, declared and paid a dividend of $60 million to PacifiCorp.

Schedule Page: 224 Line No.: 11 Column: a
In September 2020, Glenrock Coal Company, an inactive wholly owned subsidiary of
PacifiCorp was dissolved.

Schedule Page: 224 Line No.: 15 Column: a
In August 2020, Interwest Mining Company, a wholly owned subsidiary of PacifiCorp was
dissolved.

Schedule Page: 224 Line No.: 21 Column: g
During the year ended December 31, 2020, Trapper Mining Inc., a subsidiary of PacifiCorp,
paid a distribution of $60,573 to PacifiCorp.
Schedule Page: 224 Line No.: 24 Column: a
In August 2020, Fossil Rock Fuels, LLC a wholly owned subsidiary of PacifiCorp was
dissolved.
Schedule Page: 224 Line No.: 26 Column: g
During the year ended December 31, 2020, Fossil Rock Fuels, LLC, a wholly owned subsidiary
of PacifiCorp, paid a distribution of $87,149 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
2020/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
/ /2020/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.
150,404,985 Electric 222,141,625 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)
162,913,741 Electric 176,943,869 5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
67,226,405 Electric 68,021,729 7 Production Plant (Estimated)
852,235 Electric 1,231,929 8 Transmission Plant (Estimated)
13,010,416 Electric 14,018,480 9 Distribution Plant (Estimated)
10 Regional Transmission and Market Operation Plant
(Estimated)
20,127 Electric 19,098 11 Assigned to - Other (provide details in footnote)
244,022,924 260,235,105 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
394,427,909 482,376,730 20 TOTAL Materials and Supplies (Per Balance Sheet)
Page 227FERC FORM NO. 1 (REV. 12-05)
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
2020/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
/ /2020/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.
2021
1,067,998.00 156,646.00Balance-Beginning of Year 1
2
Acquired During Year: 3
Issued (Less Withheld Allow) 4
Returned by EPA 5
6
7
Purchases/Transfers: 8
9
10
11
12
13
14
Total 15
16
Relinquished During Year: 17
22,284.00 Charges to Account 509 18
Other: 19
20
Cost of Sales/Transfers: 21
22
23
24
25
26
27
Total 28
1,045,714.00 156,646.00Balance-End of Year 29
30
Sales: 31
Net Sales Proceeds(Assoc. Co.) 32
Net Sales Proceeds (Other) 33
Gains 34
Losses 35
Allowances Withheld (Acct 158.2)
2,259.00 2,259.00Balance-Beginning of Year 36
Add: Withheld by EPA 37
Deduct: Returned by EPA 38
2,259.00Cost of Sales 39
2,259.00Balance-End of Year 40
41
Sales: 42
Net Sales Proceeds (Assoc. Co.) 43
Net Sales Proceeds (Other) 44
Gains 45
Losses 46
FERC FORM NO. 1 (ED. 12-95) Page 228a
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Allowances (Accounts 158.1 and 158.2)
PacifiCorp X
/ /2020/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.
2022 2023
1 4,072,753.00 156,646.00 156,647.00 5,610,690.00
2
3
4 156,644.00 156,644.00
5
6
7
8
9
10
11
12
13
14
15
16
17
18 22,284.00
19
20
21
22
23
24
25
26
27
28
29 4,229,397.00 156,646.00 156,647.00 5,745,050.00
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
/ /2020/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2. List each study separately.
3. In column (a) provide the name of the study.
4. In column (b) report the cost incurred to perform the study at the end of period.
5. In column (c) report the account charged with the cost of the study.
6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
7. In column (e) report the account credited with the reimbursement received for performing the study.
the Period
Transmission Studies 1
4,825Q2578 561.6 4,825 456 2
878Q2594 561.6 878 456 3
26,227Q2611 561.6 26,227 456 4
7,229Q2769 561.6 5
1,740Q2782 561.6 6
6,184Q2790 561.6 7
1,041Q2799 561.6 1,041 456 8
650Q2800 561.6 650 456 9
12,343Q2801 561.6 10
3,666Q2819 561.6 3,666 456 11
390Q2828 561.6 390 456 12
4,122Q2837 561.6 4,122 456 13
933Q2844 561.6 933 456 14
6,595Q2846 561.6 6,595 456 15
152Q2847 561.6 16
347Q2865 561.6 17
152Q2866 561.6 18
4,294Q2867 561.6 19
6,009Q2872 561.6 20
Generation Studies 21
100CGIQ0011 561.7 100 456 22
160CGIQ0012 561.7 160 456 23
16,686GIQ0255 561.7 16,686 456 24
281GIQ0443 561.7 25
27,271GIQ0718 561.7 27,271 456 26
6,363GIQ0721 561.7 6,363 456 27
195GIQ0731 561.7 195 456 28
10,349GIQ0739 561.7 10,349 456 29
2,137GIQ0741 561.7 2,137 456 30
5,087GIQ0778 561.7 5,087 456 31
181GIQ0783 561.7 181 456 32
632GIQ0789 561.7 632 456 33
80GIQ0792 561.7 80 456 34
241GIQ0801 561.7 241 456 35
140GIQ0802 561.7 140 456 36
1,647GIQ0805 561.7 1,647 456 37
556GIQ0807 561.7 556 456 38
276GIQ0820 561.7 39
492GIQ0821 561.7 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
/ /2020/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
152Q2873 561.6 2
195Q2879 561.6 195 456 3
51,539Customer Studies Accrual 561.6 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
597GIQ0823 561.7 22
341GIQ0824 561.7 341 456 23
615GIQ0835 561.7 615 456 24
417GIQ0836 561.7 417 456 25
9,306GIQ0838 561.7 9,306 456 26
481GIQ0839 561.7 481 456 27
858GIQ0849 561.7 858 456 28
341GIQ0854 561.7 341 456 29
2,487GIQ0855 561.7 2,487 456 30
2,000GIQ0858 561.7 31
3,718GIQ0859 561.7 32
100GIQ0860 561.7 33
20GIQ0861 561.7 34
285GIQ0862 561.7 285 456 35
2,589GIQ0863 561.7 36
239GIQ0864 561.7 239 456 37
199GIQ0865 561.7 199 456 38
622GIQ0871 561.7 622 456 39
40GIQ0872 561.7 40 456 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
/ /2020/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
20GIQ0875 561.7 20 456 22
8,651GIQ0876 561.7 23
181GIQ0877 561.7 181 456 24
80GIQ0882 561.7 80 456 25
261GIQ0898 561.7 261 456 26
7,014GIQ0905 561.7 7,014 456 27
5,407GIQ0906 561.7 5,407 456 28
7,899GIQ0907 561.7 7,899 456 29
14,481GIQ0915 561.7 14,481 456 30
8,956GIQ0916 561.7 8,956 456 31
9,175GIQ0917 561.7 9,175 456 32
40GIQ0920 561.7 40 456 33
140GIQ0925 561.7 140 456 34
40GIQ0926 561.7 40 456 35
341GIQ0927 561.7 341 456 36
60GIQ0928 561.7 60 456 37
60GIQ0929 561.7 60 456 38
100GIQ0933 561.7 100 456 39
60GIQ0934 561.7 60 456 40
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100GIQ0935 561.7 100 456 22
100GIQ0936 561.7 100 456 23
40GIQ0937 561.7 40 456 24
299GIQ0938 561.7 299 456 25
201GIQ0940 561.7 201 456 26
241GIQ0947 561.7 241 456 27
120GIQ0948 561.7 120 456 28
80GIQ0949 561.7 80 456 29
100GIQ0950 561.7 100 456 30
80GIQ0951 561.7 80 456 31
7,073GIQ0953 561.7 7,073 456 32
60GIQ0965 561.7 60 456 33
2,737GIQ0968 561.7 2,737 456 34
4,215GIQ0971 561.7 4,215 456 35
4,539GIQ0974 561.7 4,539 456 36
461GIQ0976 561.7 461 456 37
401GIQ0978 561.7 401 456 38
181GIQ0979 561.7 181 456 39
140GIQ0980 561.7 140 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.3
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60GIQ0981 561.7 60 456 22
120GIQ0982 561.7 120 456 23
341GIQ0985 561.7 341 456 24
80GIQ0986 561.7 80 456 25
20GIQ0993 561.7 20 456 26
201GIQ0994 561.7 201 456 27
181GIQ0995 561.7 181 456 28
201GIQ0997 561.7 201 456 29
7,037GIQ0999 561.7 7,037 456 30
20GIQ1000 561.7 20 456 31
60GIQ1004 561.7 60 456 32
140GIQ1005 561.7 140 456 33
40GIQ1006 561.7 40 456 34
80GIQ1007 561.7 80 456 35
11,079GIQ1008 561.7 11,079 456 36
3,941GIQ1009 561.7 3,941 456 37
120GIQ1010 561.7 120 456 38
421GIQ1013 561.7 421 456 39
120GIQ1014 561.7 120 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.4
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60GIQ1015 561.7 60 456 22
60GIQ1016 561.7 60 456 23
8,516GIQ1019 561.7 8,516 456 24
80GIQ1023 561.7 80 456 25
281GIQ1024 561.7 281 456 26
152GIQ1027 561.7 152 456 27
94GIQ1028 561.7 94 456 28
11,443GIQ1029 561.7 11,443 456 29
8,193GIQ1031 561.7 8,193 456 30
3,588GIQ1032 561.7 3,588 456 31
3,506GIQ1033 561.7 3,506 456 32
4,322GIQ1034 561.7 4,322 456 33
241GIQ1035 561.7 241 456 34
281GIQ1036 561.7 281 456 35
140GIQ1037 561.7 36
160GIQ1038 561.7 160 456 37
120GIQ1039 561.7 120 456 38
2,077GIQ1043 561.7 2,077 456 39
4,095GIQ1045 561.7 4,095 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.5
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20GIQ1047 561.7 20 456 22
40GIQ1048 561.7 40 456 23
120GIQ1049 561.7 120 456 24
140GIQ1050 561.7 140 456 25
60GIQ1051 561.7 60 456 26
60GIQ1052 561.7 60 456 27
201GIQ1053 561.7 201 456 28
160GIQ1054 561.7 160 456 29
241GIQ1056 561.7 241 456 30
40GIQ1057 561.7 40 456 31
5,018GIQ1058 561.7 5,018 456 32
8,809GIQ1059 561.7 8,809 456 33
40GIQ1060 561.7 40 456 34
40GIQ1061 561.7 40 456 35
40GIQ1062 561.7 40 456 36
120GIQ1063 561.7 120 456 37
120GIQ1065 561.7 120 456 38
20GIQ1066 561.7 20 456 39
501GIQ1068 561.7 501 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.6
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341GIQ1069 561.7 341 456 22
261GIQ1070 561.7 261 456 23
261GIQ1071 561.7 261 456 24
140GIQ1072 561.7 140 456 25
160GIQ1073 561.7 160 456 26
201GIQ1074 561.7 201 456 27
40GIQ1075 561.7 40 456 28
20GIQ1076 561.7 20 456 29
120GIQ1078 561.7 120 456 30
20GIQ1081 561.7 20 456 31
281GIQ1083 561.7 281 456 32
60GIQ1084 561.7 60 456 33
160GIQ1085 561.7 160 456 34
836GIQ1086 561.7 836 456 35
140GIQ1087 561.7 140 456 36
201GIQ1092 561.7 201 456 37
221GIQ1094 561.7 221 456 38
321GIQ1095 561.7 321 456 39
80GIQ1096 561.7 80 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.7
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80GIQ1097 561.7 80 456 22
281GIQ1098 561.7 281 456 23
120GIQ1099 561.7 120 456 24
80GIQ1100 561.7 80 456 25
160GIQ1101 561.7 160 456 26
40GIQ1102 561.7 40 456 27
562GIQ1103 561.7 562 456 28
201GIQ1104 561.7 201 456 29
201GIQ1105 561.7 201 456 30
80GIQ1106 561.7 80 456 31
120GIQ1108 561.7 120 456 32
80GIQ1109 561.7 80 456 33
140GIQ1110 561.7 140 456 34
181GIQ1111 561.7 181 456 35
120GIQ1112 561.7 120 456 36
40GIQ1113 561.7 40 456 37
301GIQ1116 561.7 301 456 38
201GIQ1117 561.7 201 456 39
1,990GIQ1118 561.7 1,990 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.8
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181GIQ1120 561.7 181 456 22
40GIQ1122 561.7 40 456 23
80GIQ1123 561.7 80 456 24
160GIQ1124 561.7 160 456 25
160GIQ1125 561.7 160 456 26
140GIQ1126 561.7 140 456 27
100GIQ1127 561.7 100 456 28
221GIQ1129 561.7 221 456 29
40GIQ1130 561.7 40 456 30
274GIQ1131 561.7 274 456 31
100GIQ1132 561.7 100 456 32
314GIQ1133 561.7 314 456 33
254GIQ1134 561.7 254 456 34
94GIQ1135 561.7 94 456 35
13GIQ1136 561.7 13 456 36
13GIQ1137 561.7 13 456 37
5,594GIQ1140 561.7 5,594 456 38
13GIQ1141 561.7 13 456 39
13GIQ1142 561.7 13 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.9
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221GIQ1143 561.7 221 456 22
241GIQ1144 561.7 241 456 23
100GIQ1145 561.7 100 456 24
100GIQ1146 561.7 100 456 25
80GIQ1147 561.7 80 456 26
100GIQ1149 561.7 100 456 27
80GIQ1150 561.7 80 456 28
80GIQ1151 561.7 80 456 29
60GIQ1152 561.7 60 456 30
457GIQ1153 561.7 457 456 31
236GIQ1154 561.7 236 456 32
236GIQ1155 561.7 236 456 33
236GIQ1156 561.7 236 456 34
201GIQ1157 561.7 201 456 35
8,816GIQ1158 561.7 8,816 456 36
261GIQ1159 561.7 261 456 37
582GIQ1160 561.7 582 456 38
120GIQ1161 561.7 120 456 39
100GIQ1162 561.7 100 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.10
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279GIQ1163 561.7 279 456 22
279GIQ1164 561.7 279 456 23
181GIQ1165 561.7 181 456 24
20GIQ1166 561.7 20 456 25
100GIQ1167 561.7 100 456 26
100GIQ1168 561.7 100 456 27
80GIQ1169 561.7 80 456 28
80GIQ1170 561.7 80 456 29
360GIQ1171 561.7 360 456 30
1,112GIQ1172 561.7 1,112 456 31
604GIQ1173 561.7 604 456 32
80GIQ1174 561.7 80 456 33
1,137GIQ1175 561.7 1,137 456 34
404GIQ1176 561.7 404 456 35
408GIQ1177 561.7 408 456 36
507GIQ1178 561.7 507 456 37
179GIQ1179 561.7 179 456 38
589GIQ1180 561.7 589 456 39
592GIQ1181 561.7 592 456 40
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80GIQ1182 561.7 80 456 22
325GIQ1183 561.7 325 456 23
( 599)GIQ1185 561.7 24
4,739GIQ1186 561.7 4,739 456 25
( 111)GIQ1187 561.7 26
647GIQ1188 561.7 647 456 27
939GIQ1189 561.7 939 456 28
961GIQ1190 561.7 961 456 29
4,040GIQ1191 561.7 4,040 456 30
1,114GIQ1192 561.7 1,114 456 31
1,212GIQ1193 561.7 1,212 456 32
1,029GIQ1194 561.7 1,029 456 33
4,777GIQ1233 561.7 4,777 456 34
8,743LGIQ0409 561.7 8,743 456 35
13,124LGIQ0634 561.7 13,124 456 36
11,606LGIQ0636 561.7 11,606 456 37
25,453LGIQ0642 561.7 25,453 456 38
298LGIQ0731 561.7 298 456 39
6,536LGIQ0787 561.7 6,536 456 40
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4,988LGIQ0788 561.7 4,988 456 22
5,597LGIQ0838 561.7 5,597 456 23
5,465LGIQ0953 561.7 5,465 456 24
7,542LGIQ1008 561.7 7,542 456 25
2,904LGIQ1009 561.7 2,904 456 26
1,389LGIQ1029 561.7 1,389 456 27
1,512LGIQ1197 561.7 1,512 456 28
1,329LGIQ1198 561.7 1,329 456 29
1,336LGIQ1199 561.7 1,336 456 30
1,296LGIQ1200 561.7 1,296 456 31
1,174LGIQ1201 561.7 1,174 456 32
971LGIQ1202 561.7 971 456 33
659LGIQ1203 561.7 659 456 34
1,422LGIQ1207 561.7 1,422 456 35
1,062LGIQ1208 561.7 1,062 456 36
1,171LGIQ1209 561.7 1,171 456 37
931LGIQ1210 561.7 931 456 38
213LGIQ1211 561.7 213 456 39
1,113LGIQ1212 561.7 1,113 456 40
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66LGIQ1213 561.7 66 456 22
126LGIQ1214 561.7 126 456 23
66LGIQ1215 561.7 66 456 24
133LGIQ1217 561.7 133 456 25
1,110LGIQ1218 561.7 1,110 456 26
1,692LGIQ1219 561.7 1,692 456 27
1,112LGIQ1220 561.7 1,112 456 28
313LGIQ1221 561.7 313 456 29
211LGIQ1222 561.7 211 456 30
725LGIQ1223 561.7 725 456 31
211LGIQ1224 561.7 211 456 32
211LGIQ1225 561.7 211 456 33
241LGIQ1232 561.7 241 456 34
14,236OCSGIQ0001 561.7 14,236 456 35
8,869OCSGIQ0002 561.7 8,869 456 36
10,428OCSGIQ0003 561.7 10,428 456 37
9,540OCSGIQ0004 561.7 9,540 456 38
2,214OCSGIQ0005 561.7 2,214 456 39
5,585OCSGIQ0006 561.7 5,585 456 40
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4,957OCSGIQ0007 561.7 4,957 456 22
6,055OCSGIQ0008 561.7 6,055 456 23
6,110OCSGIQ0009 561.7 6,110 456 24
6,809OCSGIQ0010 561.7 6,809 456 25
8,842OCSGIQ0011 561.7 8,842 456 26
2,970OCSGIQ0012 561.7 2,970 456 27
1,408OCSGIQ0013 561.7 1,408 456 28
1,093OCSGIQ0014 561.7 1,093 456 29
1,338OCSGIQ0015 561.7 1,338 456 30
1,031OCSGIQ0016 561.7 1,031 456 31
1,876OCSGIQ0017 561.7 1,876 456 32
9,731OCSGIQ0018 561.7 9,731 456 33
8,642OCSGIQ0019 561.7 8,642 456 34
10,326OCSGIQ0020 561.7 10,326 456 35
1,610OCSGIQ0021 561.7 1,610 456 36
1,464OCSGIQ0022 561.7 1,464 456 37
5,225OCSGIQ0023 561.7 5,225 456 38
9,181OCSGIQ0024 561.7 9,181 456 39
9,272OCSGIQ0025 561.7 9,272 456 40
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9,014OCSGIQ0026 561.7 9,014 456 22
7,787OCSGIQ0027 561.7 7,787 456 23
903OCSGIQ0028 561.7 903 456 24
4,850OCSGIQ0029 561.7 4,850 456 25
291OCSGIQ0030 561.7 291 456 26
853OCSGIQ0031 561.7 853 456 27
1,044OCSGIQ0032 561.7 1,044 456 28
7,484OCSGIQ0033 561.7 7,484 456 29
8,852OCSGIQ0034 561.7 8,852 456 30
6,957OCSGIQ0035 561.7 6,957 456 31
8,546OCSGIQ0036 561.7 8,546 456 32
7,095OCSGIQ0037 561.7 7,095 456 33
4,959OCSGIQ0038 561.7 4,959 456 34
7,847OCSGIQ0039 561.7 7,847 456 35
5,498OCSGIQ0040 561.7 5,498 456 36
7,513OCSGIQ0041 561.7 7,513 456 37
3,674OCSGIQ0042 561.7 3,674 456 38
4,544OCSGIQ0043 561.7 4,544 456 39
2,066OCSGIQ0044 561.7 2,066 456 40
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3,617OCSGIQ0045 561.7 3,617 456 22
2,284OCSGIQ0046 561.7 2,284 456 23
5,138OCSGIQ0047 561.7 5,138 456 24
1,485OCSGIQ0048 561.7 1,485 456 25
1,139OCSGIQ0049 561.7 1,139 456 26
570OCSGIQ0050 561.7 570 456 27
787OCSGIQ0051 561.7 787 456 28
1,741OCSGIQ0052 561.7 1,741 456 29
745OCSGIQ0053 561.7 745 456 30
626OCSGIQ0054 561.7 626 456 31
769OCSGIQ0055 561.7 769 456 32
628OCSGIQ0056 561.7 628 456 33
528OCSGIQ0057 561.7 528 456 34
564OCSGIQ0058 561.7 564 456 35
389OCSGIQ0059 561.7 389 456 36
172OCSGIQ0060 561.7 172 456 37
152OCSGIQ0061 561.7 152 456 38
4,079OGIQ0413 561.7 4,079 456 39
1,049OGIQ1043 561.7 1,049 456 40
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16
17
18
19
20
Generation Studies 21
12,470OGIQ1045 561.7 12,470 456 22
8,013OGIQ1158 561.7 8,013 456 23
4,363SGIQ1191 561.7 4,363 456 24
1,287SGIQ1195 561.7 1,287 456 25
1,056SGIQ1196 561.7 1,056 456 26
1,438SGIQ1204 561.7 1,438 456 27
1,293SGIQ1205 561.7 1,293 456 28
909SGIQ1206 561.7 909 456 29
1,967SGIQ1216 561.7 1,967 456 30
221SGIQ1226 561.7 221 456 31
201SGIQ1227 561.7 201 456 32
181SGIQ1228 561.7 181 456 33
201SGIQ1229 561.7 201 456 34
160SGIQ1230 561.7 160 456 35
181SGIQ1231 561.7 181 456 36
61,832OATT Cluster Studies 561.7 61,832 456 37
7,824Pre-Application Studies - East 561.7 7,824 456 38
5,816Pre-Application Studies - West 561.7 5,816 456 39
6,362Customer Studies Accrual 561.7 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.18
Schedule Page: 231.18 Line No.: 37 Column: a
Refer to FERC Docket No. ER20-924, PacifiCorp's tariff filing per 35.13(a)(2)(iii): Open
Access Transmission Tariff Queue Reform.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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
/ /
2020/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)
6,865 6,865DSM Balancing Account - ID 1
184,618,685 184,618,685DSM Balancing Account - UT 2
8,019,942 11,269,853 6,242,233908 9,492,144DSM Balancing Account - WY 3
158,773 207,124 132,655908 181,006Irrigation Load Control - OR 4
5,982,332 4,027,902 2,919,505555,431 965,075Deferred Excess Net Power Costs - CA 5
25,040,842 23,803,252 18,416,430555 17,178,840Deferred Excess Net Power Costs - ID 6
2,980,283 1,564,306 1,460,791555 44,814Deferred Excess Net Power Costs - OR (1) 7
53,028,498 41,326,958 15,632,072555,182.3 3,930,532Deferred Excess Net Power Costs - UT 8
18,775,811 6,932,372 12,204,799555 361,360Deferred Excess Net Power Costs - WY 9
172,562 174,081456 1,519Deferred Excess RECs in Rates - WY 10
5,102,748 5,102,748Decoupling Mechanism - WA 11
34,344 373,879 33,719282,283 373,254Solar ITC Basis Adjustment Regulatory Asset 12
421,866,172 431,404,187 18,367,131 27,905,146Pension 13
735,190 735,190Other postretirement 14
449,069 449,069Postemployment Costs 15
27,927 8,065 19,862407.3Powerdale Decommissioning - ID (10) 16
478,637 478,637403Carbon Plant Regulatory Asset - ID (6) 17
3,444,642 3,444,642403Carbon Plant Regulatory Asset - UT (6) 18
1,158,187 1,158,187403Carbon Plant Regulatory Asset - WY (6) 19
3,118,823 1,078,260 2,040,563407.3,557Carbon Plant Inventory Regulatory Asset 20
720,622 317,074407.3 1,037,696Carbon Plant Inventory Regulatory Asset - CA (3) 21
25,487,600 63,837,870 38,350,270Cholla Unit No. 4 Plant and Closure Costs 22
1,472,497 1,344,454 128,043403Depreciation Study Deferral - UT (17) 23
5,085,195 4,643,004 442,191403Depreciation Study Deferral - WY (17) 24
490,000 455,000 35,000557Generating Plant Liquidated Damages - UT 25
1,135,840 1,081,552 54,288557Generating Plant Liquidated Damages - WY 26
12,002,814 8,160,607 4,247,407404 405,200Klamath Hydroelectric Relicensing Costs - UT (10) 27
56,567 4,379 52,188456Washington Colstrip Unit No. 3 (22) 28
85,346,686 88,897,735 5,772,451 9,323,500Environmental Costs (10) 29
140,206,260 158,208,512 18,002,252Asset Retirement Obligations Regulatory Difference 30
60,164,142 42,394,907 17,769,235174,242Unamortized Contract Values 31
62,098,272 16,630,636 45,467,636175,244Unrealized Loss on Derivative Contracts 32
1,588,786 1,588,786Greenhouse Gas Allowance Compliance - CA 33
5,634,041 5,717,575 5,153,876555,908 5,237,410Solar Feed-In Tariff Deferral - OR (1) 34
497,724 1,383,745 453,711908 1,339,732Oregon Community Solar Program 35
1,724,900 1,940,715 156,835908 372,650Solar Incentive Subscriber Program - UT 36
47,903 651,908 158,021555 762,026Renewable Portfolio Standards Compliance - WA (1) 37
300,000 300,000Protocol - MSP Deferral - ID 38
13,200,000 13,200,000Protocol - MSP Deferral - UT 39
4,000,000 4,000,000Protocol - MSP Deferral - WY 40
43,749 152,013 108,264Deferred Intervenor Funding Grants - CA 41
66,865 103,348 36,483Deferred Intervenor Funding Grants - ID 42
1,496,800 2,110,849 614,049Deferred Intervenor Funding Grants - OR 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
/ /
2020/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)
38,048 38,048Deferred Independent Evaluator Costs - OR 1
1,053,102 257,113 795,989924Catastrophic Event Regulatory Asset - CA (2) 2
9,665 116,114142 106,449Alternative Rate for Energy (CARE) - CA 3
974,878 1,793,733 818,855Washington Low Income Program 4
378,170 505,634 970,292501 1,097,756Deferred Overburden Cost - ID 5
1,064,073 1,422,725 2,730,153501 3,088,805Deferred Overburden Cost - WY 6
8,545,344 7,807,348 737,996440,442BPA Balancing Account - OR 7
197,289 197,289440,442BPA Balancing Account - WA 8
942,723 1,921,319 300,257421.1 1,278,853Property Sales Balancing Account - OR 9
10,647,303 13,765,693 7,068,568924 10,186,958Property Insurance Reserve - OR 10
291,933 447,835 155,902Misc. Regulatory Assets/Liabilities - OR 11
124,908,231 116,867,286 11,951,410506 3,910,465Utah Mine Disposition 12
347,317 264,786 82,531407.3Preferred Stock Redemption Loss - UT (10) 13
55,490 42,172 13,318407.3Preferred Stock Redemption Loss - WA (10) 14
119,691 91,249 28,442407.3Preferred Stock Redemption Loss - WY (10) 15
203,210 221,622 15,448407.3 33,860Mobile Home Park Conversion - CA 16
817,388 2,475,632 1,658,244Transportation Electrification Program - OR 17
137,015 221,507 84,492Transportation Electrification Program - WA 18
3,173,502 13,816,458 10,642,956Fire Hazard & Wildfire Mitigation Plan - CA 19
16,126,628 16,126,628AMI Replaced Meters Reg. Asset - OR 20
1,282,946 1,282,946Corporate Activity Tax Reg. Asset - OR 21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
1,119,161,023TOTAL :44 1,296,157,597 201,590,139 378,586,713
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232.1
Schedule Page: 232 Line No.: 2 Column: a
Utah Demand Side Management (DSM) regulatory assets were substantially offset by amounts
billed to Utah retail customers under the related Utah Sustainable Transportation and
Energy Plan ("STEP") program in 2019. In accordance with the Utah general rate case order
issued in December 2020, the Utah STEP amounts were used to accelerate depreciation of
certain coal-fueled generation units. For further information, refer to Note 3 of Notes to
Financial Statements in this Form No. 1.

Schedule Page: 232 Line No.: 5 Column: a
Weighted average remaining life is approximately one year for deferred excess net power
cost mechanisms being amortized.
Schedule Page: 232 Line No.: 6 Column: a
Weighted average remaining life is approximately one year for deferred excess net power
cost mechanisms being amortized.
Schedule Page: 232 Line No.: 8 Column: a
Weighted average remaining life is approximately one year for deferred excess net power
cost mechanisms being amortized.
Schedule Page: 232 Line No.: 9 Column: a
Weighted average remaining life is approximately one year for deferred excess net power
cost mechanisms being amortized.

Schedule Page: 232 Line No.: 10 Column: a
Weighted average remaining life is approximately one year for deferred excess renewable
energy credits in rates being amortized.
Schedule Page: 232 Line No.: 13 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.: 13 Column: d
Pensions are associated with labor and generally charged to operations and maintenance
expense and construction work in progress. Pension settlements are charged to Account 926,
Employee pensions and benefits.
Schedule Page: 232 Line No.: 15 Column: a
Weighted average remaining life is five years.
Schedule Page: 232 Line No.: 15 Column: d
Other postemployment costs are associated with labor and generally charged to operations
and maintenance expense and work in progress.

Schedule Page: 232 Line No.: 25 Column: a
Weighted average remaining life is 13 years.

Schedule Page: 232 Line No.: 26 Column: a
Weighted average remaining life is 22 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 232 Line No.: 29 Column: d
Account 514, Maintenance of miscellaneous steam plant
Account 545, Maintenance of miscellaneous hydraulic plant
Account 554, Maintenance of miscellaneous other power generation plant
Account 598, Maintenance of miscellaneous distribution plant
Account 935, Maintenance of general plant

Schedule Page: 232 Line No.: 31 Column: a
Weighted average remaining life is three years. Represents frozen values of contracts
previously accounted for as derivatives and recorded at fair value.
Schedule Page: 232 Line No.: 32 Column: a
Weighted average remaining life is two 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.: 12 Column: a
Weighted average remaining life is approximately three years for closure costs incurred to
date considered probable of recovery.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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
/ /2020/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.
95,250 49,530 45,720557Lacomb Irrigation (24) 1
2
829,040 787,760 41,280557Bogus Creek (41) 3
4
Mead Phoenix Availability and 5
9,847,472 7,218,293 2,629,179565Transmission Charge 6
7
1,290 1,290557TGS Buyout (23) 8
9
1,061,472 1,061,472Point-to-Point Transmission 10
11
2,847,244 2,675,551 171,693557Hermiston Swap (40) 12
13
Deferred Coal Costs - Wyodak 14
1,005,544 670,362 335,182501Settlement (22) 15
16
67,510 28,125 39,385931LT Lease Commissions Prepaid 17
18
29,772,237 9,032,863 24,839,972 4,100,598 107Lake Side Maintenance Prepaid 19
20
14,099,522 18,910,764 4,811,242Lake Side 2 Maintenance Prepaid 21
22
17,691,254 22,716,944 5,025,690Chehalis Maintenance Prepaid 23
24
Currant Creek Maintenance 25
17,007,357 20,124,993 3,117,636Prepaid 26
27
Seven Mile Hill Maintenance 28
679,935 2,039,806 1,359,871Prepaid 29
30
Seven Mile Hill II Maintenance 31
133,927 401,780 267,853Prepaid 32
33
Dunlap Ranch 1 Maintenance 34
762,352 762,352Prepaid 35
36
2,039,806 2,039,806Glenrock I Maintenance Prepaid 37
38
Glenrock III Maintenance 39
803,560 803,560Prepaid 40
41
Goodnoe Hills Maintenance 42
1,112,183 1,112,183Prepaid 43
44
2,039,806 2,039,806High Plains Maintenance Prepaid 45
46
FERC FORM NO. 1 (ED. 12-94) Page 233
49 TOTAL
47 Misc. Work in Progress
48 Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
114,194,930 101,368,220
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
/ /2020/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.
Leaning Juniper 1 Maintenance 1
2,070,712 2,070,712Prepaid 2
3
1,400,714 1,400,714Marengo Maintenance Prepaid 4
5
696,156 696,156Marengo II Maintenance Prepaid 6
7
McFadden Ridge I Maintenance 8
587,217 587,217Prepaid 9
10
Rolling Hills Maintenance 11
2,039,806 2,039,806Prepaid 12
13
65,248 11,514 53,734454Lease Incentives 14
15
1,683,361 1,010,017 673,344427,431Credit Agreement Costs 16
17
434,104 290,228 143,876427PCRB Mode Conversion Costs 18
19
1994 Series Restructuring 20
284,052 225,283 58,769427Costs (16) 21
22
163,501 77,234 163,501 77,234 181Deferred S-3 Shelf Regis. Costs 23
24
498,496 755,388 256,892 565BPA LT Transmission Prepaid 25
26
306,510 306,510Emission Reduction Credits 27
28
11,101,465 11,101,465174Unamortized Contract Values 29
30
Sales of Electric Utility 31
61,240 61,240Facilities and Properties 32
33
IT Licenses and Maintenance 34
75,000 115,043 40,067 80,110 107Prepaid 35
36
Deferred Software 37
734,762 1,253,987 519,225 107,921Implementation Costs 38
39
3,646,923 3,646,923232Prepaid Coal Costs - Wyodak 40
41
1,214 596 1,768 1,150 131,146Other Deferred Charges 42
43
44
45
46
FERC FORM NO. 1 (ED. 12-94) Page 233.1
49 TOTAL
47 Misc. Work in Progress
48 Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
114,194,930 101,368,220
Schedule Page: 233 Line No.: 6 Column: a
The amortization period will end when the Cholla Plant Unit 4 has been retired from
service and all costs of terminating Unit 4 have been paid. The Cholla Plant Unit 4 was
retired from service on December 31, 2020 and final costs to terminate Unit 4 are expected
to be paid by the end of December 31, 2021.
Schedule Page: 233 Line No.: 17 Column: a
The weighted average remaining life is one year.
Schedule Page: 233.1 Line No.: 14 Column: a
The weighted average remaining life is one year.

Schedule Page: 233.1 Line No.: 16 Column: a
The weighted average remaining life is two years.
Schedule Page: 233.1 Line No.: 18 Column: a
The weighted average remaining life is four 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
2020/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
/ /2020/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
93,154,239 82,774,477Employee benefits 2
17,359,585 33,070,119Derivative contracts and unamortized contract values 3
72,747,311 70,298,021State carryforwards 4
34,677,256 2,941,690Loss contingencies 5
64,400,058 60,936,151Asset retirement obligations 6
494,664,864 533,541,178Other 7
777,003,313 783,561,636TOTAL 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
777,003,313 783,561,636TOTAL (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 Balance at Balance at
Location Beg. of Year End of Year
(a) (b) (c)
Regulatory Liabilities $ 475,895,161 $ 442,453,306
Other 57,646,017 52,211,558
$ 533,541,178 $ 494,664,864

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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
/ /2020/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.
750,000,000Account 201, Common stock issued 1
750,000,000TOTAL COMMON STOCK 2
3
Account 204, Preferred stock issued 4
100.00 126,533 5% Cumulative Preferred 5
3,500,000 Serial Preferred, Cumulative: 6
100.00 6.00% Series 7
100.00 7.00% Series 8
16,000,000 No Par Serial Preferred 9
19,626,533TOTAL PREFERRED STOCK 10
11
Authorized and Unissued Capital Stock 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. 12-91) 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
/ /2020/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
3,417,945,896 357,060,915 2
3
4
5
6
593,000 5,930 7
1,804,600 18,046 8
9
2,397,600 23,976 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. 12-88) Page 251
Schedule Page: 250 Line No.: 1 Column: a
Berkshire Hathaway Energy Company indirectly owns all of the shares of PacifiCorp's
outstanding common stock. Therefore, there is no public market for PacifiCorp's common
stock.
Schedule Page: 250 Line No.: 1 Column: d
This class of stock is not redeemable.
Schedule Page: 250 Line No.: 7 Column: d
This series of preferred stock is not redeemable.
Schedule Page: 250 Line No.: 8 Column: d
This series of preferred stock is not redeemable.
Schedule Page: 250 Line No.: 12 Column: a
Authorizations for the issuance of common stock are as follows:
- Idaho Public Utilities Commission - Case No. PAC-E-06-7, Order No. 30099, dated
July 7, 2006.
- 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.
PacifiCorp has 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
2020/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
/ /2020/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
1,973,218 Share based payments 3
14,422,979 Tax benefit from stock option exercises 4
-3,575,760 Benefit plan separation 5
1,089,950,000 Capital contributions 6
136,208 Gain on sale of ScottishPower plc stock 7
-1,275,241 Qualified production activity tax deduction 8
432,552 Contribution 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"). During the year being reported,
no capital contributions were made by BHE to PacifiCorp.

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
2020/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
/ /2020/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
/ /2020/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.
Account 221, Bonds 1
First Mortgage Bonds: 2
3,007,139 400,000,000 3.85% Series due June 15, 2021 3
744,000 4 D
2,424,350 350,000,000 2.95% Series due February 1, 2022 5
308,000 6 D
254,129 100,000,000 2.95% Series due February 1, 2022 7
-81,000 8 P
1,859,352 300,000,000 2.95% Series due June 1, 2023 9
900,000 10 D
3,345,164 425,000,000 3.60% Series due April 1, 2024 11
255,000 12 D
2,121,421 250,000,000 3.35% Series due July 1, 2025 13
320,000 14 D
2,134,659 400,000,000 3.50% Series due June 15, 2029 15
740,000 16 D
2,156,566 400,000,000 2.70% Series due September 15, 2030 17
720,000 18 D
2,874,150 300,000,000 7.70% Series due November 15, 2031 19
864,000 20 D
1,892,365 200,000,000 5.90% Series due August 15, 2034 21
722,000 22 D
2,912,021 300,000,000 5.25% Series due June 15, 2035 23
1,080,000 24 D
2,907,881 350,000,000 6.10% Series due August 1, 2036 25
1,141,000 26 D
589,216 600,000,000 5.75% Series due April 1, 2037 27
24,000 28 D
5,127,281 600,000,000 6.25% Series due October 15, 2037 29
750,000 30 D
2,290,333 300,000,000 6.35% Series due July 15, 2038 31
1,671,000 32 D
FERC FORM NO. 1 (ED. 12-96)Page 256
33 TOTAL 8,705,275,000 96,423,358
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
/ /2020/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
400,000,000 15,400,00006/15/202105/12/201106/15/202105/12/2011 3
4
350,000,000 10,325,00002/01/202201/06/201202/01/202201/06/2012 5
6
100,000,000 2,950,00002/01/202203/06/201202/01/202203/06/2012 7
8
300,000,000 8,850,00006/01/202306/06/201306/01/202306/06/2013 9
10
425,000,000 15,300,00004/01/202403/13/201404/01/202403/13/2014 11
12
250,000,000 8,375,00007/01/202506/19/201507/01/202506/19/2015 13
14
400,000,000 14,000,00006/15/202903/01/201906/15/202903/01/2019 15
16
400,000,000 7,860,00009/15/203004/08/202009/15/203004/08/2020 17
18
300,000,000 23,100,00011/15/203111/21/200111/15/203111/21/2001 19
20
200,000,000 11,800,00008/15/203408/24/200408/15/203408/24/2004 21
22
300,000,000 15,750,00006/15/203506/13/200506/15/203506/13/2005 23
24
350,000,000 21,350,00008/01/203608/10/200608/01/203608/10/2006 25
26
600,000,000 34,500,00004/01/203703/14/200704/01/203703/14/2007 27
28
600,000,000 37,500,00010/15/203710/03/200710/15/203710/03/2007 29
30
300,000,000 19,050,00007/15/203807/17/200807/15/203807/17/2008 31
32
FERC FORM NO. 1 (ED. 12-96)Page 257
33 8,667,150,000 395,447,394
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
/ /2020/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.
6,134,687 650,000,000 6.00% Series due January 15, 2039 1
6,175,000 2 D
2,737,911 300,000,000 4.10% Series due February 1, 2042 3
987,000 4 D
5,640,085 600,000,000 4.125% Series due January 15, 2049 5
1,344,000 6 D
5,149,489 600,000,000 4.15% Series due February 15, 2050 7
2,790,000 8 D
5,183,598 600,000,000 3.30% Series due March 15, 2051 9
4,944,000 10 D
115,202 15,000,000 8.53% Series C Medium-Term Notes due December 16, 2021 11
38,400 5,000,000 8.375% Series C Medium-Term Notes due December 31, 2021 12
33,243 5,000,000 8.26% Series C Medium-Term Notes due January 7, 2022 13
30,594 4,000,000 8.27% Series C Medium-Term Notes due January 10, 2022 14
131,471 15,000,000 8.05% Series E Medium-Term Notes due September 1, 2022 15
70,118 8,000,000 8.07% Series E Medium-Term Notes due September 9, 2022 16
438,238 50,000,000 8.12% Series E Medium-Term Notes due September 9, 2022 17
105,177 12,000,000 8.11% Series E Medium-Term Notes due September 9, 2022 18
87,648 10,000,000 8.05% Series E Medium-Term Notes due September 14, 2022 19
208,198 26,000,000 8.08% Series E Medium-Term Notes due October 14, 2022 20
200,190 25,000,000 8.08% Series E Medium-Term Notes due October 14, 2022 21
37,914 5,000,000 8.23% Series E Medium-Term Notes due January 20, 2023 22
30,331 4,000,000 8.23% Series E Medium-Term Notes due January 20, 2023 23
-81,560 24 P
246,981 27,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 25
100,622 11,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 26
137,211 15,000,000 7.23% Series F Medium-Term Notes due August 16, 2023 27
274,423 30,000,000 7.24% Series F Medium-Term Notes due August 16, 2023 28
38,250 5,000,000 6.75% Series F Medium-Term Notes due September 14, 2023 29
15,300 2,000,000 6.75% Series F Medium-Term Notes due September 14, 2023 30
15,300 2,000,000 6.72% Series F Medium-Term Notes due September 14, 2023 31
152,326 20,000,000 6.75% Series F Medium-Term Notes due October 26, 2023 32
FERC FORM NO. 1 (ED. 12-96)Page 256.1
33 TOTAL 8,705,275,000 96,423,358
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
/ /2020/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.
650,000,000 39,000,00001/15/203901/08/200901/15/203901/08/2009 1
2
300,000,000 12,300,00002/01/204201/06/201202/01/204201/06/2012 3
4
600,000,000 24,750,00001/15/204907/13/201801/15/204907/13/2018 5
6
600,000,000 24,900,00002/15/205003/01/201902/15/205003/01/2019 7
8
600,000,000 14,410,00003/15/205104/08/202003/15/205104/08/2020 9
10
15,000,000 1,279,50012/16/202112/16/199112/16/202112/16/1991 11
5,000,000 418,75012/31/202112/31/199112/31/202112/31/1991 12
5,000,000 413,00001/07/202201/08/199201/07/202201/08/1992 13
4,000,000 330,80001/10/202201/09/199201/10/202201/09/1992 14
15,000,000 1,207,50009/01/202209/18/199209/01/202209/18/1992 15
8,000,000 645,60009/09/202209/09/199209/09/202209/09/1992 16
50,000,000 4,060,00009/09/202209/11/199209/09/202209/11/1992 17
12,000,000 973,20009/09/202209/11/199209/09/202209/11/1992 18
10,000,000 805,00009/14/202209/14/199209/14/202209/14/1992 19
26,000,000 2,100,80010/14/202210/15/199210/14/202210/15/1992 20
25,000,000 2,020,00010/14/202210/15/199210/14/202210/15/1992 21
5,000,000 411,50001/20/202301/20/199301/20/202301/20/1993 22
4,000,000 329,20001/20/202301/29/199301/20/202301/29/1993 23
24
27,000,000 1,960,20007/21/202307/22/199307/21/202307/22/1993 25
11,000,000 798,60007/21/202307/22/199307/21/202307/22/1993 26
15,000,000 1,084,50008/16/202308/16/199308/16/202308/16/1993 27
30,000,000 2,172,00008/16/202308/16/199308/16/202308/16/1993 28
5,000,000 337,50009/14/202309/14/199309/14/202309/14/1993 29
2,000,000 135,00009/14/202309/14/199309/14/202309/14/1993 30
2,000,000 134,40009/14/202309/14/199309/14/202309/14/1993 31
20,000,000 1,350,00010/26/202310/26/199310/26/202310/26/1993 32
FERC FORM NO. 1 (ED. 12-96)Page 257.1
33 8,667,150,000 395,447,394
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
/ /2020/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.
121,861 16,000,000 6.75% Series F Medium-Term Notes due October 26, 2023 1
91,396 12,000,000 6.75% Series F Medium-Term Notes due October 26, 2023 2
904,467 100,000,000 6.71% Series G Medium-Term Notes due January 15, 2026 3
90,683,098 8,449,000,000Subtotal - First Mortgage Bonds 4
5
Pollution Control Obligations - Secured: 6
510,479 21,260,000 Poll Ctrl Rev Refunding Bonds, Sweetwater County, WY, Series 1994 7
209,777 8,190,000 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1994 8
3,274,246 121,940,000 Poll Ctrl Rev Refunding Bonds, Emery County, UT, Series 1994 9
422,858 15,060,000 Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1994 10
132,043 5,300,000 Environ. Imprvmnt Rev Bonds, Converse County, WY, Series 1995 11
404,262 22,000,000 Environ. Imprvmnt Rev Bonds, Lincoln County, WY, Series 1995 12
4,953,665 193,750,000Subtotal Pollution Control Obligations - Secured 13
14
Pollution Control Obligations - Unsecured: 15
167,524 9,335,000 Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Series 1992A 16
242,163 22,485,000 Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 17
151,908 6,305,000 Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Series 1992B 18
225,000 24,400,000 Environ. Imprvmnt Rev Bonds, Sweetwater County, WY, Series 1995 19
786,595 62,525,000Subtotal - Pollution Control Obligations - Unsecured 20
21
96,423,358 8,705,275,000TOTAL ACCOUNT 221 22
23
Account 222, Reacquired bonds 24
25
Account 223, Advances from associated companies 26
27
Account 224, Other long-term debt 28
29
Long-term debt authorized but unissued 30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 256.2
33 TOTAL 8,705,275,000 96,423,358
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
/ /2020/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.
16,000,000 1,080,00010/26/202310/26/199310/26/202310/26/1993 1
12,000,000 810,00010/26/202310/26/199310/26/202310/26/1993 2
100,000,000 6,710,00001/15/202601/23/199601/15/202601/23/1996 3
8,449,000,000 393,037,050 4
5
6
21,260,000 220,56611/01/202411/17/199411/01/202411/17/1994 7
8,190,000 82,69411/01/202411/17/199411/01/202411/17/1994 8
121,940,000 1,073,20711/01/202411/17/199411/01/202411/17/1994 9
15,060,000 168,74111/01/202411/17/199411/01/202411/17/1994 10
5,300,000 49,37311/01/202511/17/199511/01/202511/17/1995 11
22,000,000 242,59211/01/202511/17/199511/01/202511/17/1995 12
193,750,000 1,837,173 13
14
15
92,80712/01/202009/29/199212/01/202009/29/1992 16
222,41412/01/202009/29/199212/01/202009/29/1992 17
62,88812/01/202009/29/199212/01/202009/29/1992 18
24,400,000 195,06211/01/202512/14/199511/01/202512/14/1995 19
24,400,000 573,171 20
21
8,667,150,000 395,447,394 22
23
24
25
26
27
28
29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 257.2
33 8,667,150,000 395,447,394
Schedule Page: 256 Line No.: 17 Column: a
State commission authorizations for this issuance were as follows:
- Idaho Public Utilities Commission ("IPUC") - Case No. PAC-E-18-10, Order No. 34205,
dated December 7, 2018.
- Oregon Public Utility Commission ("OPUC") - Docket No. UF-4304, Order No. 18-452,
dated December 4, 2018.
Schedule Page: 256.1 Line No.: 9 Column: a
State commission authorizations for this issuance were as follows:
- IPUC - Case No. PAC-E-18-10, Order No. 34205, dated December 7, 2018.
- OPUC - Docket No. UF-4304, Order No. 18-452, dated December 4, 2018.
Schedule Page: 256.2 Line No.: 13 Column: a
Secured by pledged first mortgage bonds registered to and held by the pollution control
bond trustee generally with the same interest rates, maturity dates and redemption
provisions as the pollution control bond obligations.
Schedule Page: 256.2 Line No.: 22 Column: h
Refer to Item 6 in Important Changes During the Year and Note 8 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.: 22 Column: i
Account 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.: 30 Column: a
As of December 31, 2020, PacifiCorp had regulatory authorization from the OPUC and IPUC to
issue an additional $3 billion of long-term debt. PacifiCorp must make a notice filing
with the Washington Utilities and Transportation Commission prior to future issuances.
Also, as of December 31, 2020, PacifiCorp had an effective shelf registration statement
with the United States Securities and Exchange Commission to issue an indeterminate amount
of first mortgage bonds through September 2023. For further information, 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, 2020) 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, 2020) 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
2020/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
/ /2020/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.
739,052,383Net Income for the Year (Page 117) 1
2
3
Taxable Income Not Reported on Books 4
5
6
7
152,686,311Other 8
Deductions Recorded on Books Not Deducted for Return 9
10
11
12
1,551,139,721Other 13
Income Recorded on Books Not Included in Return 14
15
16
17
103,019,427Other 18
Deductions on Return Not Charged Against Book Income 19
20
21
22
23
24
1,831,253,821Other 25
-23,751,914State Tax Deductions 26
484,853,253Federal Tax Net Income 27
Show Computation of Tax: 28
29
101,819,183Federal Income Tax at 21.00% 30
1,499,784Provision to Return Adjustment 31
1,843Tax Reserve Changes 32
-89,377,738Renewable Energy Production Tax Credits 33
-2,201,959Other Federal Income Tax Credits 34
-1,192,265Oregon Corporate Activity Tax 35
36
10,548,848Federal Income Tax Accrual 37
38
39
40
41
42
43
44
FERC FORM NO. 1 (ED. 12-96)Page 261
Schedule Page: 261 Line No.: 8 Column: a
Particulars (Details) Amounts
Contribution in Aid of Construction $ 109,923,825
Injuries & Damages Reserve - OR 2,104,025
MCI F.O.G. Wire Lease 296
Regulatory Asset - 2017 Protocol - MSP Deferral - UT 13,200,000
Regulatory Asset - Alt Rate for Energy Program (CARE) - CA 9,665
Regulatory Asset - BPA Balancing Account - OR 737,996
Regulatory Asset - BPA Balancing Account - WA 197,289
Regulatory Asset - Catastrophic Event Deferral - CA 795,989
Regulatory Asset - Deferred Excess RECs in Rates - WY 172,562
Regulatory Asset - Washington Colstrip Unit No. 3 52,188
Regulatory Liability - Alt Rate for Energy Program (CARE) - CA 608,001
Regulatory Liability - BPA Balancing Account - WA 317,569
Regulatory Liability - CA Greenhouse Gas Allowance Compliance 1,758,325
Regulatory Liability - Deferred Excess RECs in Rates - UT 1,009,415
Regulatory Liability - Deferred Excess RECs in Rates - WY 128,677
Regulatory Liability - Depreciation Decrease - WA 6,648
Regulatory Liability - Depreciation Deferral - OR 1,407,497
Regulatory Liability - Excess Income Tax Deferral - WA 374,601
Regulatory Liability - OR Direct Access 5-Year Opt Out 2,467,556
Regulatory Liability - Renewable Portfolio Standards Compliance - OR 103,714
Regulatory Liability - Utah Home Energy Lifeline 222,338
Regulatory Liability - WA Deferred Steam Accel Depreciation 12,608,365
Reimbursements 3,813,773
Trapper Mining Stock Basis 665,997
Total $ 152,686,311

Schedule Page: 261 Line No.: 13 Column: a
Particulars (Details) Amounts
Fed/State Tax Expense $ (77,564,988)
Fed/State Tax Expense - Interest 202,972
Accrued Payroll Taxes 24,084,073
Accrued Royalties 6,717,702
Accrued Severance 1,973,858
Accrued Vacation 2,537,262
Avoided Costs 88,441,201
Book Depreciation 1,160,555,277
Book Depreciation Allocated to Medicare and M&E 172,210
Capitalization of Test Energy 2,662,525
Capitalized Labor and Benefit Costs 4,185,473
Company Plane 37,821
CWIP Reserve 1,123,542
Deferred Compensation Mark-to-Market Gain/Loss 527,972
Deferred Revenue - Other 534,385
Environmental Liability - Regulated 2,167,641
Executive Compensation - IRC Section 162(m) Limitation 277,602
Fuel Cost Adjustment 6,870,156
Hermiston Swap 171,693
Hydro Relicensing Obligation 1,329,358
Income Tax Interest 1,448
Injuries and Damages Accrual, Net of Insurance Reserves 129,076,676
Klamath Settlement Obligation 33,000,000
Lewis River Settlement Agreement 2,697
Lobbying Expenses 1,281,212
Long-Term Incentive Plan 1,287,993
Meals and Entertainment 1,739,749
Non-deductible Fringe Benefits 333,084
Non-deductible Parking Costs 957,292
Penalties 6,723
Prepaid Aircraft Maintenance 124,250
Prepaid Membership Fees 194,491
Prepaid Taxes - IPUC 198
Property Insurance Reserve - CA 471,446
Property Insurance Reserve - ID 113,544
Regulatory Asset - Carbon Plant Decom/Inventory 1,517,311
Regulatory Asset - Carbon Plant Decom/Inventory - WY 523,253
Regulatory Asset - Carbon Plant Deferred Depreciation - ID 478,639
Regulatory Asset - Carbon Plant Deferred Depreciation - UT 3,444,641
Regulatory Asset - Carbon Plant Deferred Depreciation - WY 1,158,188
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Regulatory Asset - Cholla Plant Unit No. 4 Closure 9,032,359
Regulatory Asset - Deferred Excess NPC - CA 1,954,430
Regulatory Asset - Deferred Excess NPC - ID 1,237,590
Regulatory Asset - Deferred Excess NPC - OR 1,415,977
Regulatory Asset - Deferred Excess NPC - UT 11,701,538
Regulatory Asset - Deferred Excess NPC - WY 11,843,438
Regulatory Asset - Depreciation Study Deferral - ID 73,633
Regulatory Asset - Depreciation Study Deferral - UT 128,043
Regulatory Asset - Depreciation Study Deferral - WY 442,191
Regulatory Asset - Independent Evaluator Costs - UT 597,844
Regulatory Asset - Emergency Service Resiliency Program - CA 619,099
Regulatory Asset - Environmental Costs - WA 122,206
Regulatory Asset - FAS 158 Pension Liability 17,101,030
Regulatory Asset - Generating Plant Liquidated Damages - UT 35,000
Regulatory Asset - Generating Plant Liquidated Damages - WY 5,708
Regulatory Asset - Goodnoe Hills Settlement - WY 21,250
Regulatory Asset - Klamath Hydroelectric Relicensing Costs - UT 3,842,208
Regulatory Asset - Lakeside Settlement - WY 27,331
Regulatory Asset - Pension Settlement - WA 73,059
Regulatory Asset - Postemployment Costs 4,351,928
Regulatory Asset - Post Merger Loss - Reacquired Debt 582,467
Regulatory Asset - Postretirement Settlement Loss 3,337,654
Regulatory Asset - Postretirement Settlement Loss CC - WY 1,543,631
Regulatory Asset - Powerdale Decommissioning - ID 19,862
Regulatory Asset - Preferred Stock Redemption Loss - UT 82,531
Regulatory Asset - Preferred Stock Redemption Loss - WA 13,318
Regulatory Asset - Preferred Stock Redemption Loss - WY 28,442
Regulatory Asset - STEP Pilot Program Balance Account - UT 2,501,797
Regulatory Asset - Utah Mine Disposition 8,040,945
Regulatory Liability - ARO/Reg Diff - Trojan - WA Portion 285,155
Regulatory Liability - Blue Sky - WA 45,673
Regulatory Liability - Blue Sky - WY 115,446
Regulatory Liability - California Energy Savings Assistance 111,645
Regulatory Liability - Cholla Plant Unit No. 4 Decommissioning - OR 9,183,624
Regulatory Liability - Cholla Plant Unit No. 4 Decommissioning - UT 20,444,811
Regulatory Liability - Deferred Excess NPC - CA 842,039
Regulatory Liability - Deferred Excess NPC - WA 15,813,218
Regulatory Liability - Deferred Excess NPC - WY 586,639
Regulatory Liability - Steam Decommissioning - UT 8,775,068
Regulatory Liability - Steam Decommissioning - WY 446,507
Reserve for Bad Debts 9,506,354
Operating Leases (Right-of-Use Assets) 1,238,391
TGS Buyout 1,289
Trapper Mine Contract Obligation 246,783
Total $ 1,551,139,721
Schedule Page: 261 Line No.: 18 Column: a
Particulars (Details) Amounts
Book Fixed Asset Gain/Loss $ (2,412,688)
Dividend Received Deduction - Deferred Compensation (70,956)
Officer's Life Insurance (6,924,854)
Regulatory Asset - Decoupling Mechanism - WA (5,102,749)
Regulatory Liability - 50% Tax on Bonus Depreciation - WY (933,496)
Regulatory Liability - BPA Balancing Account - ID (1,542,623)
Regulatory Liability - Deferred Excess NPC - OR (21,422,483)
Regulatory Liability - Excess Income Tax Deferral - CA (1,869,663)
Regulatory Liability - Excess Income Tax Deferral - ID (570,264)
Regulatory Liability - Excess Income Tax Deferral - OR (38,658,808)
Regulatory Liability - Excess Income Tax Deferral - UT (658,945)
Regulatory Liability - Excess Income Tax Deferral - WY (2,329,404)
Regulatory Liability - Merwin Fish Collector Project - WA (3,432)
Regulatory Liability - Washington Low Income Program (818,855)
Transmission Service Deposits (1,471,604)
Unearned Joint Use Pole Contract Revenue (39,891)
Equity Earnings in Subsidiaries (17,675,307)
Intercompany Adjustment (513,405)
Total $ (103,019,427)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 261 Line No.: 25 Column: a
Particulars (Details) Amounts
Accrued Bonus $ (14,242)
Accrued Final Reclamation (367,119)
Accrued Retention (112,955)
Amortization NOPAs 99-00 RAR (28,449)
Basis Intangible Difference (337,156)
Bear River Settlement Agreement (121,300)
Capitalized Depreciation (7,807,154)
Cholla SHL NOPA (Lease Amortization) (2,256,217)
Contra PP&E Cholla Unit No. 4 Closure (2,750,283)
Contra Receivable from Joint Owners (796,951)
Cost of Removal (82,329,836)
Debt AFUDC (47,743,075)
Deferred Compensation (1,836,771)
Deferred Revenue - Other (56,217)
Deferred Revenue - Lease Incentives (31,062)
Dividend Deduction at 50% (39,217)
Environmental Liability - Non-regulated (94,255)
Equity AFUDC (97,889,023)
FAS 112 Book Reserve - Postemployment Benefits (2,635,739)
FAS 158 Pension Liability (21,587,984)
FAS 158 Postretirement Liability (3,180,075)
FAS 158 SERP Liability (1,757,667)
Federal Tax Depreciation (995,681,826)
Federal Tax Fixed Asset Gain/Loss (122,181,299)
Inventory Reserve (1,211,637)
Lease Depreciation - Timing Differences (443,913)
Long-Term Incentive Plant Mark-to-Market Gain/Loss (581,183)
Miscellaneous Current and Accrued Liability (430,000)
North Umpqua Settlement Agreement (655,786)
Operating Leases (Liability) (1,060,251)
Oregon Misc. Regulatory Assets/Liabilities (155,904)
Pension/Retirement Accrual (20,804)
Pre-1943 Preferred Stock Dividend - Deduction (107,935)
Prepaid - FSA O&M - East (1,607,480)
Prepaid - FSA O&M - East (282,370)
Prepaid Surety Bond (219,828)
Prepaid Taxes - OPUC (182,978)
Prepaid Taxes - Property Taxes (6,510,200)
Prepaid Taxes - UPSC (6,068)
Property Insurance Reserve - OR (3,118,390)
Property Insurance Reserve - UT (5,635,263)
Property Insurance Reserve - WY (377,355)
Regulatory Asset - CA Mobile Home Park Conversion (18,412)
Regulatory Asset - CA Greenhouse Gas Allowance Compliance (1,588,786)
Regulatory Asset - Carbon Plant Inventory - CA (720,621)
Regulatory Asset - Community Solar Program - OR (886,021)
Regulatory Asset - Independent Evaluator Costs - OR (38,048)
Regulatory Asset - Deferred Intervenor Funding Grants - CA (108,264)
Regulatory Asset - Deferred Intervenor Funding Grants - ID (36,483)
Regulatory Asset - Deferred Intervenor Funding Grants - OR (614,049)
Regulatory Asset - Deferred Overburden Cost - ID (127,464)
Regulatory Asset - Deferred Overburden Cost - WY (358,651)
Regulatory Asset - Environmental Costs (3,673,255)
Regulatory Asset - Fire Hazard & Wildfire Mitigation Plan - CA (10,642,956)
Regulatory Asset - Pension Settlement - CA (486,232)
Regulatory Asset - Property Sales Balancing Account - OR (978,596)
Regulatory Asset - Renewable Portfolio Standards Compliance - WA (604,005)
Regulatory Asset - Solar Feed-In Tariff Deferral - OR (83,534)
Regulatory Asset - Solar Incentive Program - UT (2,501,797)
Regulatory Asset - Transportation Electrification Program - CA (86,746)
Regulatory Asset - Transportation Electrification Program - OR (1,658,244)
Regulatory Asset - Transportation Electrification Program - WA (84,492)
Regulatory Asset/Liability - Demand Side Management (DSM) Balancing Accounts (204,571,342)
Regulatory Asset - UT Solar Incentive Subscriber Program (215,816)
Regulatory Liability - Blue Sky - CA (29,735)
Regulatory Liability - Blue Sky - ID (171,040)
Regulatory Liability - Blue Sky - OR (94,312)
Regulatory Liability - Blue Sky - UT (1,537,110)
Regulatory Liability - Oregon Clean Fuels Program (551,170)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Regulatory Liability - Oregon Energy Conservation Charge (42,859)
Regulatory Liability - Solar Feed-in Tariff Deferral - CA (623,230)
Regulatory Liability - Solar Incentive Program - UT (1,843,915)
Regulatory Liability - WA Decoupling Mechanism (15,999,235)
Repairs Deduction (164,667,959)
Rogue River - Habitat Enhancement Liability (73,640)
Tax Depletion - SRC (33,300)
Trojan Decommissioning (52,115)
Wasatch Workers Compensation Reserve (92,170)
Western Coal Carriers Benefits Obligation (1,115,000)
Total $(1,831,253,821)

Schedule Page: 261 Line No.: 37 Column: b
Berkshire Hathaway Inc. includes PacifiCorp in its United States Federal Income Tax Return. PacifiCorp's
provision for income taxes has been computed on a stand-alone basis.
Names of group members who will file a consolidated United States Federal Income Tax Return:
Under 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 Management, L.L.C. BHER Santa Rita Holdings, LLC
Aeronavis LLC BHER Santa Rita Investment, LLC
Alamo 6 Solar Holdings, LLC BHES CSG Holdings, LLCAlamo 6, LLC BHES Pearl Solar Holdings, LLC
Alaska Gas Transmission Company, LLC BHH Affiliates, LLC
Ambassador Real Estate Company BHH Iowa Affiliates, LLC
Apex Home Maintenance, LLC BHH KC Real Estate, LLC
ARE Commercial Real Estate, LLC Bishop Hill Energy II, LLC
ARE Iowa, LLC Bishop Hill II Holdings, LLC
Arizona HomeServices, LLC BRER Affiliates, LLC
Attorneys Title Holdings, Incorporated CalEnergy Company, Inc.
Berkshire Hathaway Energy Company CalEnergy Generation Operating Company
BH2H Holdings, LLC CalEnergy International Services, Inc.BHE AC Holding, LLC CalEnergy Minerals LLC
BHE America Transco, LLC CalEnergy Operating Corporation
BHE Canada LLC CalEnergy Pacific Holdings Corp
BHE Community Solar, LLC California Energy Development Corporation
BHE Compression Services, LLC California Energy Yuma CorporationBHE CS Holdings, LLC California Utility Holdco, LLC
BHE Gas, Inc. Capitol Title Company
BHE Geothermal, LLC Carolina Gas Services, Inc.
BHE GT&S, LLC Carolina Gas Transmission, LLC
BHE Hydro, LLC CE Electric (NY), Inc.
BHE Infrastructure Group, LLC CE Generation LLC
BHE Infrastructure Services, LLC CE Geothermal, Inc.
BHE Midcontinent Transmission Holdings LLC CE International Investments, Inc.
BHE Pearl Solar Holdings, LLC CE Leathers Company
BHE Pearl Solar, LLC CE Turbo LLCBHE Pipeline Group, LLC Champion Realty, Inc.
BHE Renewables, LLC Chancellor Title Services, Inc.
BHE Solar, LLC Columbia Title of Florida, Inc.
BHE Southwest Transmission Holdings LLC Commonsite, Inc.
BHE Texas Transco, LLC Cordova Energy Company, LLCBHE U.K. Electric, Inc. Cove Point GP Holding Company, LLC
BHE U.K. Inc. CPMLP Holdings Company, LLC
BHE U.K. Power, Inc. CTRE, L.L.C.
BHE U.S. Transmission, LLC Dakota Dunes Development Company
BHE Wind, LLC DCCO, Inc.
BHER Market Operations, LLC Del Ranch Company
BHER Minerals, LLC Denver Rental, LLC
BHER Power Resources, Inc. Desert Valley 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
DesertLink Investment LLC HomeServices of Wisconsin, LLC
Eastern Brine, LLC HomeServices Referral Network, LLC
Eastern Energy Field Services, Inc. HomeServices Relocation, LLC
Eastern Energy Gas Holdings, LLC Houlihan/Lawrence Inc.
Eastern Gas Transmission and Storage, Inc. HS Franchise Holding, LLC
Eastern Gathering and Processing Inc. HSF Affiliates LLC
Eastern MLP Holding Company II, LLC HSGA Real Estate Group, L.L.C.
Eastern MLP Holding Company, LLC HSN Holding, LLC
Ebby Halliday Alliance, LLC HSTX Title, LLC
Ebby Halliday Properties, Inc. HSW Affiliates Holding, LLC
Ebby Halliday Real Estate, Inc. Huff-Drees Realty, Inc.
Edina Financial Services, Inc. IES Holding II LLC
Edina Realty Referral Network, Inc. Imperial Magma LLC
Edina Realty Title, Inc. Intero Franchise Services, Inc.
Edina Realty, Inc. Intero Nevada, LLC
Elmore Company Intero Real Estate Holdings, Inc.
Esslinger-Wooten-Maxwell, Inc. Intero Real Estate Services, Inc.
E-W-M Referral Services, Inc. Intero Referral Services, Inc.
F&R/T LLC Iowa Realty Company, Inc.
Falcon Power Operating Company Iowa Realty Insurance Agency, Inc.
Farmington Properties, Inc. Iowa Title Company
FFR, Inc. Iroquois GP Holding Company, LLC
First Network Realty, Inc. Iroquois, Inc.
First Realty, Ltd JBRC, Inc.
First Weber Illinois, LLC Jim Huff Realty, Inc.
First Weber Referral Associates, Inc. JRHBW Realty, Inc. d/b/a RealtySouth
First Weber, Inc. Jumbo Road Holdings, LLC
Fishlake Power LLC Kansas City Title, Inc.
Florida Network LLC Kanstar Transmission, LLC
Florida Network Property Management, LLC Kentucky Residential Referral Service, LLC
For Rent, Inc. Kentwood City Properties, LLC
Fort Dearborn Land Title Company, LLC Kentwood Commercial, LLC
FRTC, LLC Kentwood DTC, LLC
Geronimo Community Solar Gardens Holding Company, LLC Kentwood Real Estate Services, LLC
Geronimo Community Solar Gardens, LLC Kentwood, LLC
Gibraltar Title Services, LLC Kern River Gas Transmission Company
GPWH Holdings, LLC Keystone Partners, LLC
Grande Prairie Land Holding, LLC KR Holding, LLC
Grande Prairie Wind Holdings, LLC L&F/Fonville Morisey Real Estate, LLC
Grande Prairie Wind II, LLC L&F/Fonville Morisey Title, LLC
Grande Prairie Wind, LLC Lands of Sierra, Inc.
Guarantee Appraisal Corporation Larabee School of Real Estate, Inc.
Guarantee Real Estate LFFS, Inc.
HMSV Financial Services, Inc. Long & Foster Institute of Real Estate, Inc.
HN Real Estate Group N.C., Inc. Long & Foster Insurance Agency, Inc.
HN Real Estate Group, LLC Long & Foster Licensing Company, Inc.
HN Referral Corporation Long & Foster Mortgage Ventures, Inc.
HomeServices Insurance, Inc. Long & Foster Real Estate Ventures, Inc.
HomeServices Lending, LLC Long & Foster Real Estate, Inc.
HomeServices MidAtlantic, LLC Long & Foster Settlement Services, LLC
HomeServices Northeast, LLC Lovejoy Realty Inc.
HomeServices of Alabama, Inc. Lovejoy Referral Network, LLC
HomeServices of America, Inc. M & M Ranch Acquisition Company LLC
HomeServices of California, Inc. M & M Ranch Holding Company LLC
HomeServices of Colorado, LLC Magma Land Company I
HomeServices of Connecticut, LLC Magma Power Company
HomeServices of Florida, Inc. Marshall Wind Energy Holdings, LLC
HomeServices of Georgia, LLC Marshall Wind Energy, LLC
HomeServices of Illinois Holdings, LLC MEC Construction Services Company
HomeServices of Illinois, LLC MEHC Investment, Inc.
HomeServices of Iowa, Inc. Merlin Realty Technologies, LLC
HomeServices of Kentucky Real Estate Academy, LLC MES Holding, LLC
HomeServices of Kentucky, Inc. Metro Referral Associates, Inc.
HomeServices of Minnesota, LLC MHC Investment Company
HomeServices of MOKAN, LLC MHC, Inc.
HomeServices of Nebraska, Inc. Mid-America Referral Network, Inc.
HomeServices of New Jersey, LLC MidAmerican Central California Transco LLC
HomeServices of New York, LLC MidAmerican Energy Company
HomeServices of Oregon, LLC MidAmerican Energy Machining Services LLC
HomeServices of Texas, LLC MidAmerican Energy Services, LLC
HomeServices of the Carolinas, Inc. MidAmerican Funding, LLC
HomeServices of Washington, LLC MidAmerican Geothermal Development Corp
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
MidAmerican Wind Tax Equity Holdings, LLC Reece & Nichols Realtors, Inc.
Midland Escrow Services, Inc. Reece Commercial, Inc.
Mid-States Title Insurance Agency, Inc. Referral Associates of Georgia, LLC
Midwest Capital Group, Inc. Referral Network of IL LLC
Midwest Power Midcontinent Transmission Development, LLC Referral Network of NY/NJ, LLC
Midwest Power Transmission Arkansas LLC REV LNG SSL BC LLC
Midwest Power Transmission Iowa LLC RGS Settlements of Pennsylvania, LLC
Midwest Power Transmission Kansas, LLC RGS Title of Baltimore, LLC
Midwest Power Transmission Oklahoma, LLC RGS Title, LLC
Midwest Power Transmission Texas, LLC RHL Referral Company, LLC
Midwest Preferred Realty, Inc. Roberts Brothers, Inc.
Midwest Realty Ventures, LLC Roy H. Long Realty Company, Inc.
Modular LNG Holdings, Inc. S.W. Hydro, Inc.
Montana Alberta Tie LP Inc. Sage Title Group, LLC
Montana Alberta Tie US Holdings GP Inc. Salton Sea Power Company
MPT Heartland Development, LLC Salton Sea Power Generation Company
MTL Canyon Holdings LLC Salton Sea Power LLC
NE Hub Partners, LLC Santa Rita Wind Energy LLC
NE Hub Partners, LP Saranac Energy Company, Inc.
Nebraska Referral, Inc. SCS Realty Investment Group, LLC
Nevada Power Company d/b/a NV Energy, Inc. Sequoia Aviation Corporation
Niche Storage Solutions, LLC Sierra Gas Holding Company
NNGC Acquisition LLC Sierra Pacific Power Company d/b/a NV Energy, Inc.
Northeast Midstream GP, LLC Silver State Holdings LLC
Northeast Midstream Partners, LP Silvermine Ventures LLC
Northeast Referral Group, LLC Solar San Antonio LLC
Northern Natural Gas Company Solar Star 3, LLC
NRS Referral Services, LLC Solar Star 4, LLC
NV Energy, Inc. Solar Star California XIX, LLC
NVE Holdings, LLC Solar Star California XX, LLC
NVE Insurance Co, Inc. Solar Star Funding, LLC
NW Referral Services, LLC Solar Star Projects Holdings, LLC
PCG Agencies, Inc. Southwest Relocation, LLC
PCRE, L.L.C. SSC XIX, LLC
Pickford Escrow Company, Inc. SSC XX, LLC
Pickford Holdings, LLC The Escrow Firm
Pickford Real Estate, Inc. The Kentwood Company at Cherry Creek, LLC
Pickford Services Company, Inc. The Long & Foster Companies, Inc.
Pilot Butte, LLC The Referral Company
Pinyon Pines Funding, LLC Thoroughbred Title Services, LLC
Pinyon Pines I Holding Company, LLC TIAC LLC
Pinyon Pines II Holding Company, LLC Tioga Properties, LLC
Pinyon Pines Projects Holding, LLC TitleSouth, LLC
Pinyon Pines Wind I, LLC TLTC LLC
Pinyon Pines Wind II, LLC Topaz Solar Farms, LLC
Pivotal JAX LNG, LLC TPZ Holding, LLC
Pivotal LNG, Inc. TRMC LLC
PNW Referral, LLC Two Rivers, Inc.
Preferred Carolinas Realty, Inc. TX Jumbo Road Wind, LLC
Premier Service Abstract, LLC TX Referral Alliance, Inc.
Prime Alliance Real Estate Services, LLC Volantes LLC
Priority Title Corporation Vulcan Power Company
Property Services Northeast, LLC Vulcan/BN Geothermal Power Company
Prosperity First Title, LLC Wailuku Holding Company LLC
Prosperity Home Mortgage, LLC Wailuku Investment LLC
Pru-One, Inc. Wailuku River Hydroelectric Power Co, Inc.
Real Estate Knowledge Services, L.L.C. Walnut Ridge Wind, LLC
Real Estate Links, LLC Watermark Realty Referral, Inc.
Real Estate Referral Network, Inc. Watermark Realty, Inc.
Real Living Real Estate, LLC Weathervane Referral Network, Inc.
Reece & Nichols Alliance, Inc. Western Capital 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
With respect to members of the BHE Sub-Group, BHE requires all subsidiaries to pay or receive from BHE an amount
of tax based primarily on the stand-alone method of allocation. The computation includes all tax benefits from
tax deductions from costs borne by utility customers.
Berkshire Hathaway Inc. Sub-Group:
121 Acquisition Co., LLC BNSF Logistics International, Inc.
21 SPC, Inc. BNSF Logistics Ocean Line, Inc.
21st Communities, Inc. BNSF Logistics, LLC
21st Mortgage Corporation BNSF Railway Company
2K Polymer Systems, Inc. BNSF Railway International Services, Inc.
A.E. Company, Inc. BNSF Spectrum, Inc.
Accra Manufacturing Inc. Boat America Corporation
Accurate Installations, Inc. Boat Owners Association of the United States
Acme Brick Company Boat/U.S, Inc.
Acme Building Brands, Inc. Borsheim Jewelry Company, Inc.
Acme Management Company BR Agency, Inc.
Acme Ochs Brick and Stone, Inc. Brainy Toys, Inc.
Acme Services Company, LLC Brilliant National Services, Inc.
Adalet/Scott Fetzer Company Brittain Machine Inc.
Aerocraft Heat Treating Co., Inc. Brooks Sports, Inc.
Aero-Hose Corporation Brookwood Insurance Company
Aerospace Dynamics International Inc. Burlington Northern Railroad Holdings, Inc.
Affiliated Agency Operations Co. Burlington Northern Santa Fe, LLC
Affordable Housing Partners, Inc. Business Wire, Inc.
AIPCF V CHI Blocker Inc. Caledonian Alloys Inc.
AJF Warehouse Distributors, Inc. Camp Manufacturing Company
Albacor Shipping (USA) Inc. Cannon Equipment LLC
Albecca, Inc. Cannon-Muskegon Corporation
Alpha Cargo Motor Express, Inc. Carefree/Scott Fetzer Company
Alu-Forge, Inc. Carlton Forge Works
Ambucor Health Solutions, Inc. Cavalier Homes, Inc.
American All Risk Insurance Services, Inc. Central States Indemnity Co. of Omaha
American Commercial Claims Administrators Inc. Central States of Omaha Companies, Inc.
American Dairy Queen Corporation Champion Bus, Inc.
AmGUARD Insurance Company Charter Brokerage Holdings Corp.
Andrews Laser Works Corporation Chemtool Incorporated
Angelo Po America, Inc. CJE II
Arcturus Manufacturing Corporation Claims Services, Inc.
Artform International Inc. Clayton Commercial Buildings, Inc.
Atlantic Precision, Inc. Clayton Education Corp.
Avibank Manufacturing Inc. Clayton Homes, Inc.
AzGUARD Insurance Company Clayton Properties Group II, Inc.
Bayport Systems, Inc. Clayton Properties Group, Inc.
Ben Bridge Jeweler, Inc. Clayton Supply, Inc.
Benjamin Moore & Co. Clayton, Inc.
Benson Industries, Inc. CMH Capital, Inc.
Benson, Ltd. CMH Homes, Inc.
Berkshire Hathaway Assurance Corporation CMH Manufacturing West, Inc.
Berkshire Hathaway Automotive Inc. CMH Manufacturing, Inc.
Berkshire Hathaway Credit Corporation CMH of KY, Inc.
Berkshire Hathaway Direct Insurance Company CMH Services, Inc.
Berkshire Hathaway Finance Corporation CMH Transport, Inc.
Berkshire Hathaway Global Insurance Services, LLC Coil Master Corporation
Berkshire Hathaway Homestate Insurance Company Columbia Insurance Company
Berkshire Hathaway Life Insurance Company of Nebraska Complementary Coatings Corporation
Berkshire Hathaway Specialty Insurance Company Composites Horizons LLC
BH Columbia Inc. Consumer Value Products, Inc.
BH Credit LLC Continental Divide Insurance Company
BH Finance, Inc. Cornelius Inc.
BH Holding H Jewelry Inc. Cornelius Renew, Inc.
BH Holding LLC Cort Business Services Corporation
BH Holding S Furniture Inc. Criterion Insurance Agency
BH Media Group, Inc. Crown Holdco One, Inc.
BH Shoe Holdings, Inc. Crown Holdco Two, Inc.
BHA Minority Interest Holdco, Inc. Crown Parent, Inc.
BHG Life Insurance Company CSI Life Insurance Company
BHG Structured Settlements, Inc. CTB Credit Corp
BHSF, Inc. CTB Inc.
biBERK Insurance Services, Inc. CTB International Corp
Blue Chip Stamps, Inc. CTB IW Inc.
BN Leasing Corporation CTB Midwest Inc.
BNSF Communications, Inc. CTB MN Investments
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
CTB Technology Holding Inc. GEICO Insurance Agency
CTMS North America, Inc. GEICO Marine Insurance Company
Cumberland Asset Management, Inc. GEICO Products, Inc.
Cypress Insurance Company GEICO Secure Insurance Company
D.I. Properties Inc. Gen Re Intermediaries Corporation
Dairy Queen Corporate Stores, Inc. General Re Corporation
DCI Marketing Inc. General Re Financial Products Corporation
Denver Brick Company General Re Life Corporation
Designed Metal Connections, Inc. General Reinsurance Corporation
Dickson Testing Co., Inc. General Star Indemnity Company
Display Technologies LLC General Star Management Company
DL Trading Holdings I, Inc. General Star National Insurance Company
DQ Funding Corporation Genesis Insurance Company
DQF, Inc. Genesis Management and Insurance Services Corp.
DQGC, Inc. Government Employees Financial Corp.
DTTF, Inc. Government Employees Insurance Co.
Duracell Industrial Operations, Inc. GRD Holdings Corporation
Duracell U.S. Operations Inc. Greenville Metals Inc.
EastGUARD Insurance Company GUARDco, Inc.
Eco Color Company H. H. Brown Shoe Company, Inc.
Ecodyne Corporation H.J. Justin & Sons, Inc.
Ellis & Watts Global Industries, Inc. Hackney Ladish Inc.
Elm Street Corporation Halex/Scott Fetzer Company
Empire Distributors of Colorado, Inc. Hamilton Aviation Inc.
Empire Distributors of North Carolina, Inc. Hawthorn Life International, Ltd.
Empire Distributors of Tennessee, Inc. HeatPipe Technology, Inc.
Empire Distributors, Inc. Helicomb International Inc.
Environment One Corporation Henley Holdings, LLC
Exacta Aerospace Inc. Hohmann & Barnard, Inc.
Executive Jet Management, Inc. Homefirst Agency, Inc.
Exsif Worldwide, Inc. Homemakers Plaza, Inc.
ExtruMed, Inc. Howell Penncraft, Inc.
Fatigue Technology Inc. Huntington Alloys Corporation
Financial Services Plus, Inc. IdeaLife Insurance Company
Finial Holdings, Inc. Ingersoll Cutting Tool Company
Finial Reinsurance Company Innovative Building Products, Inc.
First Berkshire Hathaway Life Insurance Company Innovative Coatings Technology Corporation
FlightSafety Capital Corp. Interco Tobacco Retailers, Inc.
FlightSafety Development Corp. International Dairy Queen, Inc.
FlightSafety International Inc. International Insurance Underwriters, Inc.
FlightSafety International Middle East Inc. Intrepid JSB, Inc.
FlightSafety New York, Inc. Ironwood Plastics Inc.
FlightSafety Properties, Inc. Iscar Metals Inc.
FlightSafety Services Corporation ITTI Group USA Holdings, Inc.
Floors, Inc. ITTI Investment Holdings, Inc.
Focused Technology Solutions, Inc. J.L. Mining Company
Fontaine Commercial Trailer, Inc. Johns Manville China, Ltd.
Fontaine Engineered Products, Inc. Johns Manville Corporation
Fontaine Fifth Wheel Company Johns Manville, Inc.
Fontaine Modification Company Jordan's Furniture, Inc.
Fontaine Spray Suppression Company Joyce Steel Erection LLC
Fontaine Trailer Company LLC Justin Brands, Inc.
Forest River Holdings, Inc. Kahn Ventures, Inc.
Forest River, Inc. Karmelkorn Shoppes, Inc.
Freedom Warehouse Corp. Ken's Spray Equipment, Inc.
Fruit of the Loom Direct, Inc. Kinexo, Inc.
Fruit of the Loom Trading Company KITCO Fiber Optics, Inc.
Fruit of the Loom, Inc. Klune Holdings Inc.
Fruit of the Loom, Inc. (Sub) Klune Industries Inc.
FTI Manufacturing Inc. L.A. Terminals, Inc.
FTL Regional Sales Co., Inc. LeachGarner, Inc.
Garan Central America Corp. Lipotec USA, Inc.
Garan Incorporated LiquidPower Specialty Products, Inc.
Garan Manufacturing Corp. LJ Aero Holdings Inc.
Garan Services Corp LJ Synch Holdings Inc.
Gateway Underwriters Agency, Inc. LMG Ventures, LLC
GEICO Advantage Insurance Company Los Angeles Junction Railway Company
GEICO Casualty Co. LSPI Holdings Inc.
GEICO Choice Insurance Company Lubrizol Advanced Materials Holding Corporation
GEICO Corporation Lubrizol Advanced Materials, Inc.
GEICO General Insurance Co. Lubrizol Global Management, Inc.
GEICO Indemnity Co. Lubrizol Inter-Americas 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
Lubrizol International Management Corporation MPP Co., Inc.
Lubrizol International, Inc. MPP Pipeline Corporation
Lubrizol Life Science, Inc. MS Property Company
Lubrizol Overseas Trading Corporation MW Wholesale, Inc.
M&C Products, Inc. National Fire & Marine Insurance Company
M&M Manufacturing, Inc. National Indemnity Company
M2 Liability Solutions, Inc. National Indemnity Company of Mid-America
Mapletree Transportation, Inc. National Indemnity Company of the South
Marathon Suspension Systems, Inc. National Liability & Fire Insurance Company
Marmon Beverage Technologies, Inc. Nationwide Uniforms
Marmon Crane Services, Inc. Nebraska Furniture Mart, Inc.
Marmon Distribution Services, Inc. NetJets Aviation, Inc.
Marmon Energy Services Company NetJets Europe Holdings, LLC
Marmon Engineered Components Company NetJets Inc.
Marmon Foodservice Technologies LLC NetJets International, Inc.
Marmon Holdings, Inc. NetJets Sales, Inc.
Marmon Link Inc. NetJets Services, Inc.
Marmon Railroad Services LLC NetJets U.S., Inc.
Marmon Retail & Highway Technologies Company LLC New England Asset Management, Inc.
Marmon Retail Products, Inc. NewCo D&W LLC
Marmon Retail Store Equipment LLC NFM Custom Countertops, LLC
Marmon Retail Technologies Company NFM of Kansas, Inc.
Marmon Tubing, Fittings & Wire Products, Inc. NFM Services, LLC
Marmon Water, Inc. NJE Holdings, LLC
Marmon Wire & Cable, Inc. NJI Sales, Inc.
Marmon-Herrington Company Noranco Manufacturing (USA) Ltd.
Marquis Jet Holdings, Inc. NorGUARD Insurance Company
Marquis Jet Partners, Inc. Northern States Agency, Inc.
Maryland Ventures, Inc. Noveon Hilton Davis, Inc.
McCarty-Hull Cigar Company, Inc. NSS Technologies Inc.
McLane Beverage Distribution, Inc. Oak River Insurance Company
McLane Beverage Holding, Inc. Old United Casualty Company
McLane Company, Inc. Old United Life Insurance Company
McLane Eastern, Inc. Orange Julius Of America
McLane Express, Inc. Oriental Trading Company, Inc.
McLane Foods, Inc. OTC Brands, Inc.
McLane Foodservice Distribution, Inc. OTC Direct, Inc.
McLane Foodservice, Inc. OTC Worldwide Holdings, Inc.
McLane Mid-Atlantic, Inc. Particle Sciences, Inc.
McLane Midwest, Inc. PCC Flow Technologies Holdings Inc.
McLane Minnesota, Inc. PCC Flow Technologies Inc.
McLane Network Solutions, Inc. PCC Rollmet Inc.
McLane New Jersey, Inc. PCC Structurals Inc.
McLane Ohio, Inc. Penn Coal Land, Inc.
McLane Southern, Inc. Perfection Hy-Test Company
McLane Suneast, Inc. Permaswage Holdings, Inc.
McLane Tri-States, Inc. Pine Canyon Land Company
McLane Western, Inc. Plaza Financial Services Co.
McWilliams Forge Company Plaza Resources Co.
Medical Protective Finance Corporation PLICO
MedPro Group, Inc. Precision Brand Products, Inc.
MedPro Risk Retention Services, Inc. Precision Castparts Corp.
Merit Distribution Services, Inc. Precision Founders Inc.
Metalac Fasteners Inc. Precision Steel Warehouse, Inc.
Meyn LLC Press Forge Company
MFS Fleet, Inc. Primus International Holding Company
MH Site Construction, Inc. Primus International Inc.
Midwest Northwest Properties, Inc. Princeton Insurance Company
Miller-Sage, Inc. Priority One Financial Services, Inc.
Mindware Corporation PRISM Holdings LLC
MiTek Holdings, Inc. PRISM Plastics, Inc.
MiTek Inc. Pro Installations, Inc.
MiTek Industries, Inc. Procrane Holdings, Inc.
MiTek Mezzanine Systems, Inc. Progressive Incorporated
MLMIC Insurance Company Protective Coating Inc.
MLMIC Services, Inc. QS Partners LLC
Morgantown-National Supply, Inc. QS Security Services LLC
Mount Vernon Fire Insurance Company R.C. Willey Home Furnishings
Mount Vernon Specialty Insurance Company Radnor Specialty Insurance Company
Mouser Electronics, Inc. Railserve, Inc.
Mouser JV 1, Inc. Railsplitter Holdings Corporation
Mouser JV 2 RathGibson Holding Co LLC
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
RCP Investment, Inc. Tool-Flo Manufacturing, Inc.
Redwood Fire and Casualty Insurance Company Top Five Club, Inc.
RENTCO Trailer Corporation Total Quality Apparel Resources
Resolute Management Inc. TPC European Holdings, LTD.
Richline Group, Inc TPC North America, Ltd.
Ringwalt & Liesche Co. Transco Railcar Repair Inc.
Rio Grande, Inc. Transco Railway Products Inc.
Roxell USA, Inc. Transco, Inc.
Sager Electrical Supply Co. Inc. Transportation Technology Services, Inc.
Santa Fe Pacific Insurance Company TRH Holding Corp.
Santa Fe Pacific Pipeline Holdings, Inc. Triangle Suspension Systems, Inc.
Santa Fe Pacific Pipelines, Inc. Tricycle, Inc.
Santa Fe Pacific Railroad Company TS City Leasing Inc.
Scott Fetzer Financial Group, Inc. TSE Brakes, Inc.
ScottCare Corporation TTI JV 1
See's Candies, Inc. TTI JV 2
See's Candy Shops, Incorporated TTI, Inc.
Serpentec, Inc. Tucker Safety Products, Inc.
Seventeenth Street Realty, Inc. TXFM, Inc.
SFEG Corp. U.S. Investment Corporation
Shaw Contract Flooring Services, Inc. U.S. Underwriters Insurance Co.
Shaw Diversified Services, Inc. UCFS Europe Company
Shaw Floors, Inc. UCFS International Holding Company
Shaw Funding Company Unified Supply Chain, Inc.
Shaw Industries Group, Inc. Uni-Form Components Co.
Shaw Industries, Inc. Union Tank Car Company
Shaw International Services, Inc. Union Underwear Co., Inc.
Shaw Retail Properties, Inc. United Consumer Financial Services Company
Shaw Sports Turf California, Inc. United Direct Finance, Inc.
Shaw Transport, Inc. United States Aviation Underwriters, Inc.
Shultz Steel Company United States Liability Insurance Company
SHX Flooring, Inc. University Swaging Corporation
SidePlate Systems, Inc. UTLX Company
Smilemakers Canada Inc. Van Enterprises, Inc.
Smilemakers, Inc. Vanderbilt ABS Corp.
SN Management, Inc. Vanderbilt Mortgage and Finance, Inc.
Soco West, Inc. Vanity Fair, Inc.
Sonnax Transmission Company Velocity Freight Transport, Inc.
SOS Metals, Inc. Veritas Insurance Group, Inc.
Southern Energy Homes, Inc. Vero Beach Flight Training Academy, Inc.
Southwest United Industries Inc. Vesta Intermediate Funding, Inc.
Special Metals Corporation VFI-Mexico, Inc.
Spectra Contract Flooring Puerto Rico, Inc. Visilinx, Inc.
SPS International Investment Company Vision Retailing, Inc.
SPS Technologies LLC VT Insurance Acquisition Sub Inc.
SPS Technologies Mexico LLC Warwick Chemicals USA, Inc.
SSP-SiMatrix Inc. Wayne/Scott Fetzer Company
Stahl/Scott Fetzer Company Weaver Manufacturing Inc.
Star Lake Railroad Company Webb Wheel Products, Inc.
StratoFlight Wellfleet Insurance Company
Summit Distribution Services, Inc. Wellfleet New York Insurance Company
TBS USA, Inc. Western Builders Supply, Inc.
Technical Power Systems, Inc. Western Fruit Express Company
Tenn-Tex Plastics, Inc. Western/Scott Fetzer Company
Texas Honing Inc. WestGUARD Insurance Company
The Ben Bridge Corporation Whittaker, Clark & Daniels, Inc.
The Buffalo News, Inc. World Book Encyclopedia, Inc.
The BVD Licensing Corporation World Book, Inc.
The Duracell Company World Book/Scott Fetzer Company
The Fechheimer Brothers Co. World Investments, Inc.
The Indecor Group, Inc. Worldwide Containers, Inc.
The Lubrizol Corporation WPLG, Inc.
The Medical Protective Company Wyman Gordon Company
The Pampered Chef, Ltd. Wyman Gordon Forgings Cleveland Inc.
The Scott Fetzer Company Wyman Gordon Forgings Inc.
The Zia Company Wyman Gordon Investment Castings Inc.
THI Acquisition Inc. Wyman Gordon Pennsylvania LLC
TIMET Real Estate Corporation X-L-Co., Inc.
Titanium Metals Corporation XTRA Companies, Inc.
TM City Leasing Inc. XTRA Corporation
TMCA International Inc. XTRA Finance Corporation
TMI Climate Solutions, Inc. 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2020/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
58,941,158 -23,108,822 10,548,848 25,283,488 Income 2
14,582,168 38,598,585 547,975 FICA 3
224,453 221,069 6,933 Unemployment 4
73,747,779 -23,108,822 49,368,502 25,838,396Subtotal 5
6
State: 7
8
Arizona: 9
2,675,392 2,656,104 1,347,340 Property 10
-368,594 -131,838 -359,914 -140,518 Income 11
2,306,798 -131,838 2,296,190 1,206,822Subtotal 12
13
California: 14
2,514,376 2,514,376 Property 15
18,263 18,886 350 Unemployment 16
1,419,680 -451,466 747,690 220,524 Franchise-Income 17
223,495 237,046 21,977 Use 18
1,292,505 1,224,727 1,365,182 Local Franchise 19
5,468,319 -451,466 4,742,725 1,608,033Subtotal 20
21
Colorado: 22
2,817,432 2,687,432 2,830,000 Property 23
44 -1,725 1,769 Income 24
2,817,432 44 2,685,707 2,831,769Subtotal 25
26
Idaho: 27
6,111,630 5,957,357 3,621,845 Property 28
1,551,437 -499,833 837,891 213,713 Income 29
74,118 73,352 17,340 KWh 30
17,566 17,274 842 Unemployment 31
248,957 267,050 19,500 Use 32
8,003,708 -499,833 7,152,924 3,873,240Subtotal 33
34
Missouri: 35
273 273 Unemployment 36
273 273Subtotal 37
38
39
40
14,156,321
FERC FORM NO. 1 (ED. 12-96)Page 262
TOTAL41 313,139,423 350,025,766 -28,974,200 71,717,476
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
/ /2020/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEARPrepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)(g) (h) (i) (j) (k) (l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
1
1,519,317 9,029,531 2
38,598,585 7,685 24,572,077 3
221,069 3,549 4
40,338,971 9,029,531 7,685 24,575,626 5
6
7
8
9
2,656,104 1,328,052 10
1,371 -361,285 11
1,371 2,294,819 1,328,052 12
13
14
147,222 2,367,154 15
18,886 973 16
20,573 727,117 17
237,046 35,528 18
1,224,727 1,297,404 19
423,727 4,318,998 1,333,905 20
21
22
1,074 2,686,358 2,700,000 23
11 -1,736 24
1,085 2,684,622 2,700,000 25
26
27
246,067 5,711,290 3,467,572 28
23,369 814,522 29
73,352 16,574 30
17,274 550 31
267,050 37,593 32
553,760 6,599,164 3,522,289 33
34
35
273 36
273 37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 263
41 20,081,205 247,857,485 65,281,938 69,730,217
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2020/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.
Montana: 1
5,361,142 5,575,904 2,572,241 Property 2
208,341 -42,586 129,756 35,999 Corporate License-Income 3
150 150 Unemployment 4
200,611 200,611 60,000 Energy License 5
142,932 142,932 42,000 Wholesale Energy 6
5,913,176 -42,586 6,049,353 2,710,240Subtotal 7
8
Nevada: 9
27,439 24,439 18,000 Commerce Tax 10
27,439 24,439 18,000Subtotal 11
12
New Mexico: 13
20,531 20,531 Property 14
64,535 -45,053 67,301 -47,819 Income 15
85,066 -45,053 87,832 -47,819Subtotal 16
17
Oregon: 18
38,693,488 32,723,191 13,406,626 168,490 Property 19
1,141,733 1,102,525 57,436 Unemployment 20
15,146,298 -2,602,676 11,017,701 1,525,921 Excise-Income 21
102,825 -10,224 100,084 -7,483 City of Portland-Income 22
1,499,200 1,499,295 749,695 Department of Energy 23
1,133,507 1,136,594 422,076 Tri-Met 24
4,259,000 135,506 4,394,506 Corporate Activity Tax 25
29,284,450 29,678,090 4,928,979 Franchise 26
91,260,501 -2,477,394 81,651,986 14,156,321 7,095,419Subtotal 27
28
Texas: 29
19 19 Unemployment 30
19 19Subtotal 31
32
South Carolina: 33
69 69 Unemployment 34
25 -25 Public Utility 35
69 94 -25Subtotal 36
37
38
39
40
14,156,321
FERC FORM NO. 1 (ED. 12-96)Page 262.1
TOTAL41 313,139,423 350,025,766 -28,974,200 71,717,476
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
/ /2020/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEARPrepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)(g) (h) (i) (j) (k) (l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
1
1,527,092 4,048,812 2,787,003 2
1,971 127,785 3
150 4
200,611 60,000 5
142,932 42,000 6
1,529,213 4,520,140 2,889,003 7
8
9
24,439 15,000 10
24,439 15,000 11
12
13
20,531 14
291 67,010 15
291 87,541 16
17
18
1,224,189 31,499,002 19,318,920 110,487 19
1,102,525 5,000 23,228 20
144,378 10,873,323 21
474 99,610 22
1,499,295 749,600 23
1,136,594 425,163 24
4,394,506 25
29,678,090 5,322,619 26
3,608,160 78,043,826 20,073,520 5,881,497 27
28
29
19 30
19 31
32
33
69 34
25 35
69 25 36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 263.1
41 20,081,205 247,857,485 65,281,938 69,730,217
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2020/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.
Utah: 1
83,070,686 33,638 82,572,108 855,165 Property 2
16,815,921 -2,250,890 13,334,384 1,230,647 Income 3
72,663 72,488 1,768 Unemployment 4
5,005,986 5,014,776 502,372 Use 5
7,500 7,500 Franchise 6
104,972,756 -2,217,252 101,001,256 2,589,952Subtotal 7
8
Washington: 9
10,513,832 11,713,832 10,600,000 Property 10
11,596 20,404 9,930 Unemployment 11
34,836 50,831 2,059 Family & Medical Leave 12
24,865 24,965 3,600 Business & Occupation 13
11,334,529 12,470,138 -190,609 Public Utility 14
2,233,778 2,076,014 392,043 Natural Gas Use Tax 15
1,924,382 556,690 1,415,146 Use 16
7,134 7,134 Forest Excise Tax 17
26,084,952 26,920,008 12,232,169Subtotal 18
19
Wyoming: 20
20,050,395 21,737,664 9,181,562 Property 21
2,000,555 2,294,623 2,037,077 Wind Generation Tax 22
42,893 41,547 1,924 Unemployment 23
1,863,650 1,851,950 308,200 Franchise 24
4,633,203 4,629,413 81,021 Use 25
91,957 91,957 Annual Report 26
28,682,653 30,647,154 11,609,784Subtotal 27
28
Miscellaneous: 29
30,943 30,943 Goshute Possessory 30
261,733 261,733 Sho-Ban Possessory 31
15,127 15,262 7,496 Navajo Possessory 32
39,236 39,236 Ute Possessory 33
223,182 79,182 144,000 Crow Possessory 34
84,605 84,605 Umatilla Possessory 35
654,826 510,961 151,496Subtotal 36
37
38
39
40
14,156,321
FERC FORM NO. 1 (ED. 12-96)Page 262.2
TOTAL41 313,139,423 350,025,766 -28,974,200 71,717,476
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
/ /2020/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
717,670 81,854,438 322,949 2
151,645 13,182,739 3
72,488 1,593 4
5,014,776 511,162 5
7,500 6
5,956,579 95,044,677 835,704 7
8
9
1,892,892 9,820,940 11,800,000 10
20,404 18,738 11
50,831 18,054 12
24,965 3,700 13
12,470,138 945,000 14
2,076,014 234,279 15
556,690 47,454 16
7,134 17
4,603,965 22,316,043 13,067,225 18
19
20
3,593,495 18,144,169 10,868,831 21
2,294,623 2,331,145 22
41,547 578 23
1,851,950 296,500 24
4,629,413 77,231 25
91,957 26
8,264,455 22,382,699 13,574,285 27
28
29
30,943 30
261,733 31
15,262 7,631 32
39,236 33
79,182 34
84,605 35
510,961 7,631 36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 263.2
41 20,081,205 247,857,485 65,281,938 69,730,217
Schedule Page: 262 Line No.: 2 Column: f
Account 146, Accounts receivable from other associated companies, which represents income
taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent
company.
Schedule Page: 262 Line No.: 2 Column: l
Account 409.2, Income taxes, other income and deductions, which represents federal income
tax applicable to other income and deductions.

Schedule Page: 262 Line No.: 3 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.

Schedule Page: 262 Line No.: 4 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.

Schedule Page: 262 Line No.: 11 Column: f
Account 143, Other accounts receivable, which represents a reclassification of the
balance.
Schedule Page: 262 Line No.: 11 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.

Schedule Page: 262 Line No.: 15 Column: l
Account 408.2, Taxes other than income taxes, other income and deductions
Schedule Page: 262 Line No.: 16 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.

Schedule Page: 262 Line No.: 17 Column: f
Account 146, Accounts receivable from other associated companies, which represents income
taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent
company.
Schedule Page: 262 Line No.: 17 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.

Schedule Page: 262 Line No.: 18 Column: l
Charged to same account as related goods.
Schedule Page: 262 Line No.: 23 Column: l
Account 408.2, Taxes other than income taxes, other income and deductions

Schedule Page: 262 Line No.: 24 Column: f
Account 143, Other accounts receivable, which represents a reclassification of the
balance.

Schedule Page: 262 Line No.: 24 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 262 Line No.: 28 Column: l
$ 1,060 Account 408.2, Taxes other than income taxes, other income and deductions
245,007 Account 107, Construction work in progress
$ 246,067
Schedule Page: 262 Line No.: 29 Column: f
Account 146, Accounts receivable from other associated companies, which represents income
taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent
company.

Schedule Page: 262 Line No.: 29 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.

Schedule Page: 262 Line No.: 31 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.

Schedule Page: 262 Line No.: 32 Column: l
Charged to same account as related goods.

Schedule Page: 262 Line No.: 36 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.

Schedule Page: 262.1 Line No.: 2 Column: l
Account 107, Construction work in progress
Schedule Page: 262.1 Line No.: 3 Column: f
Account 146, Accounts receivable from other associated companies, which represents income
taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent
company.

Schedule Page: 262.1 Line No.: 3 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.

Schedule Page: 262.1 Line No.: 4 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.

Schedule Page: 262.1 Line No.: 15 Column: f
Account 143, Other accounts receivable, which represents a reclassification of the
balance.

Schedule Page: 262.1 Line No.: 15 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.

Schedule Page: 262.1 Line No.: 19 Column: l
$ 27,061 Account 408.2, Taxes other than income taxes, other income and deductions
170,866 Account 589, Rents
1,026,262 Account 107, Construction work in progress
$ 1,224,189
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 262.1 Line No.: 20 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 21 Column: f
Account 146, Accounts receivable from other associated companies, which represents income
taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent
company.
Schedule Page: 262.1 Line No.: 21 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.

Schedule Page: 262.1 Line No.: 22 Column: f
Account 146, Accounts receivable from other associated companies, which represents income
taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent
company.

Schedule Page: 262.1 Line No.: 22 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.

Schedule Page: 262.1 Line No.: 24 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: f
$ 1,418,452 Account 146, Accounts receivable from other associated companies
(1,282,946) Account 182.3, Other regulatory assets
$ 135,506
Schedule Page: 262.1 Line No.: 30 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.

Schedule Page: 262.1 Line No.: 34 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.

Schedule Page: 262.2 Line No.: 2 Column: f
Represents accrued interest income from expected property tax refunds in the state.

Schedule Page: 262.2 Line No.: 2 Column: l
$ 42,119 Account 408.2, Taxes other than income taxes, other income and deductions
675,551 Account 107, Construction work in progress
$ 717,670
Schedule Page: 262.2 Line No.: 3 Column: f
Account 146, Accounts receivable from other associated companies, which represents income
taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent
company.

Schedule Page: 262.2 Line No.: 3 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 262.2 Line No.: 4 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.2 Line No.: 5 Column: l
Charged to same account as related goods.

Schedule Page: 262.2 Line No.: 10 Column: l
$ 49,442 Account 408.2, Taxes other than income taxes, other income and deductions
1,843,450 Account 107, Construction work in progress
$ 1,892,892

Schedule Page: 262.2 Line No.: 11 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.

Schedule Page: 262.2 Line No.: 12 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.

Schedule Page: 262.2 Line No.: 15 Column: l
Account 151, Fuel stock

Schedule Page: 262.2 Line No.: 16 Column: l
Charged to same account as related goods.

Schedule Page: 262.2 Line No.: 17 Column: l
Account 408.2, Taxes other than income taxes, other income and deductions

Schedule Page: 262.2 Line No.: 21 Column: l
$ 2,488 Account 408.2, Taxes other than income taxes, other income and deductions
14,290 Account 589, Rents
3,576,717 Account 107, Construction work in progress
$ 3,593,495
Schedule Page: 262.2 Line No.: 23 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.

Schedule Page: 262.2 Line No.: 25 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
2020/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
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
PacifiCorp X
/ /2020/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% 6,120,722 411.4,420 2,272,879 5
30% 420 210,680 2,201,959 420 119,069 6
Idaho 69,131 411.4,420 12,663 7
TOTAL 6,400,533 2,201,959 2,404,611 8
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
9
10
Idaho 190 -11,254 4,802,974 1,955,360 420 618,725 11
Total Nonutility -11,254 4,802,974 1,955,360 618,725 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
/ /2020/Q4
Line
No.ADJUSTMENT EXPLANATIONAverage Periodof Allocationto Income
1
2
3
4
3,847,843 38.82 5
2,293,570 24 6
56,468 38.82 and 30 7
6,197,881 8
9
10
6,128,355 30 11
6,128,355 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% $ 6,092,576 - $ - 411.4(1) $2,244,733 $ - $ 3,847,843 38.82
10% 28,146 - - 420(2) 28,146 - - -
$ 6,120,722 $ - $2,272,879 $ - $ 3,847,843
(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 $ 33,818 - $ - 411.4(1) $ 7,842 $ - $ 25,976 38.82
Idaho 35,313 - - 420(2) 4,821 - 30,492 30
$ 69,131 $ - $ 12,663 $ - $ 56,468
(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
2020/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
/ /2020/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.
5,374,091Working Capital Deposits 4,817,524 29,433 586,000131 1
2
6,723,040Reclamation Costs - Trapper Mine 6,961,463 238,423 3
4
Western Coal Carriers Benefits 5
10,636,000Obligation 9,521,000 1,068,833 2,183,833131,557 6
7
10,059,074Deferred Compensation Plans 8,222,304 1,486,806 3,323,576131 8
9
21,972,995Long-Term Incentive Plan 23,260,988 5,046,996 3,759,003131 10
11
Regulated Environmental 12
56,343,586Liabilities 58,511,228 10,484,159 8,316,517131,182.3 13
14
Non-Regulated Environmental 15
1,719,376Liabilities 1,625,120 77,701 171,957131,426.5 16
17
Unearned Joint Use 18
3,032,343Pole Contact Revenue 2,992,452 6,413,579 6,453,470454 19
20
109,551Misc. Security Deposits 109,978 10,722 10,295415 21
22
124,248Lease Incentives 93,186 31,062931 23
24
129,410Cowlitz/Lewis River O&M (1) 131,567 315,758 313,601539 25
26
22,000Employee Housing Security Deposits 21,000 1,200 2,200131 27
28
413,417Cogeneration Bonds-Sunnyside 413,417 29
30
10,488,050Transmission Security Deposits 9,537,050 6,004,000 6,955,000131 31
32
2,144,171Transmission Service Deposits 672,567 558,777 2,030,381131,235 33
34
558,649MCI F.O.G. Wire Lease (1) 558,945 3,353,671 3,353,375454 35
36
53,496,372Unamortized Contract Values 36,447,683 17,048,689242 37
38
2,829,321Accrued Right-of-Way Obligations 2,266,777 562,544566,589 39
40
843,553Facility Use Fee 793,201 108,577 158,929451,456 41
42
Energy Supply Management 43
45,834Deferral (1) 45,834456 44
45
7,630,811Deer Creek Accrued Royalties 14,347,296 6,899,117 182,632182.3 46
FERC FORM NO. 1 (ED. 12-94) Page 269
47 TOTAL 75,111,811 59,984,925 216,557,492 201,430,606
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
/ /2020/Q4
Line
No.
Description and Other DEBITS
Credits
Account(c)(b)(a)
Balance at
End of Year
(d)
Deferred Credits Amount
(e)
Balance at
Beginning of Year Contra
(f)
1. Report below the particulars (details) called for concerning other deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
1
70,277Deferred Revenue - Other 14,059 14,059 70,277921 2
3
6,664,437Coal Contract Costs - Naughton 2,238,687 4,425,750131 4
5
Klamath Settlement Obligation 33,000,000 33,000,000 6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-94) Page 269.1
47 TOTAL 75,111,811 59,984,925 216,557,492 201,430,606
Schedule Page: 269 Line No.: 19 Column: a
The weighted average remaining life is one year.
Schedule Page: 269 Line No.: 23 Column: a
The weighted average remaining life is three years.
Schedule Page: 269 Line No.: 41 Column: a
The weighted average remaining life is 12 years.
Schedule Page: 269.1 Line No.: 2 Column: a
The weighted average remaining life is one year for amounts being amortized.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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
/ /2020/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
26,855,963 4,608,120 174,829,838 4 Pollution Control Facilities
5 Other (provide details in footnote):
6
7
26,855,963 4,608,120 174,829,838 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
26,855,963 4,608,120 174,829,838 17 TOTAL (Acct 281) (Total of 8, 15 and 16)
18 Classification of TOTAL
19,696,615 1,556,912 142,546,910 19 Federal Income Tax
7,159,348 3,051,208 32,282,928 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
/ /2020/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
152,581,995 4
5
6
7
152,581,995 8
9
10
11
12
13
14
15
16
152,581,995 17
18
124,407,207 19
28,174,788 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
/ /2020/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 2,889,829,879 607,559,413 604,655,593 2
Gas 3
4
TOTAL (Enter Total of lines 2 thru 4) 2,889,829,879 607,559,413 604,655,593 5
Nonutility 6
7
8
TOTAL Account 282 (Enter Total of lines 5 thru 8) 2,889,829,879 607,559,413 604,655,593 9
Classification of TOTAL 10
Federal Income Tax 2,377,767,057 370,771,299 369,097,421 11
State Income Tax 512,062,822 236,788,114 235,558,172 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
/ /2020/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
182.3,254 2,908,481,325 3,766,356182.3,254 19,513,982 2
3
4
2,908,481,325 3,766,356 19,513,982 5
6
7
8
2,908,481,325 3,766,356 19,513,982 9
10
2,392,566,817 780,203 13,906,085 11
515,914,508 2,986,153 5,607,897 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
/ /2020/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
48,931,830 138,691,792 276,140,020Regulatory Assets 3
16,628,979 17,839,607 21,033,529Other 4
5
6
7
8
65,560,809 156,531,399 297,173,549TOTAL 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
65,560,809 156,531,399 297,173,549TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19
Classification of TOTAL 20
52,247,724 126,417,714 242,528,418Federal Income Tax 21
13,313,085 30,113,685 54,645,131State 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
/ /2020/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
342,606,717 19,213,159 50,083,492 34,535,696 26,958,628 3
22,465,024 4,716,702190,283190,283 8,349,912 8,477,900 4,623,823 4
5
6
7
8
365,071,741 23,929,861 58,433,404 43,013,596 31,582,451 9
10
11
12
13
14
15
16
17
18
365,071,741 23,929,861 58,433,404 43,013,596 31,582,451 19
20
297,886,223 19,680,208 47,544,750 34,969,510 25,917,153 21
67,185,518 4,249,653 10,888,654 8,044,086 5,665,298 22
23
FERC FORM NO. 1 (ED. 12-96)Page 277
NOTES (Continued)
Schedule Page: 276 Line No.: 3 Column: g
Account 182.3, Other regulatory assets
Account 190, Accumulated deferred income taxes
Account 283, Accumulated deferred income taxes-other
Schedule Page: 276 Line No.: 3 Column: i
Account 182.3, Other regulatory assets
Account 190, Accumulated deferred income taxes
Account 283, Accumulated deferred income taxes-other

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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
/ /2020/Q4
Line
No.
Description and Purpose of DEBITS
CreditsAccount
(d)(c)(a)
Balance at End
of Current
Quarter/Year
(e)
Other Regulatory Liabilities Amount
(f)
Credited
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Begining
of Current
Quarter/Year
(b)
1,467,265 1,987,469 356,563 876,767DSM Balancing Account - CA 440,442,444 1
1,066,780 5,680,794 4,614,014DSM Balancing Account - ID 440,442,444 2
14,306,725 33,453,561 19,146,836DSM Balancing Account - UT 440,442,444 3
3,714,452 10,686,986 3,551,130 10,523,664DSM Balancing Account - WA 440,442,444 4
3,772,288 33,460,108 3,729,429 33,417,249Oregon Energy Conservation Charge 440,442,444 5
842,039 842,039Deferred Excess Net Power Costs - CA 6
8,739,343 24,552,560 15,813,217Deferred Excess Net Power Costs - WA 7
586,639 586,639Deferred Excess Net Power Costs - WY 8
648,863 304,395 1,658,278 1,313,810Deferred Excess RECs in Rates - UT 456 9
61,621 190,298 128,677Deferred Excess RECs in Rates - WY 10
18,007,592 16,283,171 2,008,356 283,935Decoupling Mechanism - WA 440,442 11
1,188,392 24,165 5,673,582 4,509,355Income Tax Reg. Liability - Flow Through - WA 411.1 12
1,630,571 599,544 1,031,312 285Investment Tax Credit Regulatory Liability 190 13
1,650,254,838 307,106,966 1,456,252,383 113,104,511Deferred Income Tax Electric 411.1,190,282 14
70,939,627 153,100,026 27,227,145 109,387,544Excess Income Tax Deferral 440,442,444 15
1,256,164 1,617,089 322,667 683,592Tax on Bonus Depreciation - WY (1)440,442,444 16
18,354,603 12,699,289 10,827,899 5,172,585Other Postretirement 17
3,902,859 3,902,859Postemployment Costs 18
9,183,623 9,183,623Cholla Plant Unit No. 4 Decomm - OR 19
20,444,811 20,444,811Cholla Plant Unit No. 4 Decomm - UT 20
76,877 2,039,800 150,511 2,113,434Depreciation Study Deferral - ID (1)403 21
71,096 71,096Asset Retirement Obligations Reg. Difference 230 22
3,348,606 20,416,162 5,106,931 22,174,487Greenhouse Gas Allowance Compliance - CA 456,555 23
4,131 619,099 623,230Emergency Service Resiliency Program - CA 908 24
623,230 623,230Solar Feed-In Tariff Deferral - CA 182.3 25
6,753,231 4,345,712 2,407,519Solar Incentive Program - UT 26
14,781,307 8,698,557 17,283,104 11,200,354STEP Pilot Program - UT 440,442,444,107 27
22,637 548,382 126,351 652,096Renewable Portfolio Standards Compliance - OR 555 28
107,882 705,726 597,844Deferred Independent Evaluator Costs - UT 29
608,001 608,001Alternative Rate for Energy (CARE) - CA 30
1,557,248 144,342 1,779,586 366,680Utah Home Energy Lifeline 131,142 31
637,760 159,189 749,405 270,834California Energy Savings Assistance Program 440,442,444 32
35,934,821 34,331,010 14,512,339 12,908,528FERC Rate True-up - OR (3)456 33
2,891,586 1,542,623 1,348,963BPA Balancing Account - ID 440,442 34
317,569 317,569BPA Balancing Account - WA 35
271,318 32,748 241,583 3,013Blue Sky - CA 440,442 36
2,440,526 824,950 2,346,214 730,638Blue Sky - OR 440,442 37
293,510 171,040 122,470Blue Sky - ID 440,442 38
8,663,361 1,639,015 7,126,250 101,904Blue Sky - UT 440,442 39
542,530 588,203 45,673Blue Sky - WA 40
FERC FORM NO. 1/3-Q (REV 02-04) Page 278
41 TOTAL 424,907,414 654,888,504 1,700,242,286 1,930,223,376
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
/ /2020/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)
652,536 767,981 115,445Blue Sky - WY 1
6,527,879 7,935,376 1,407,497Depreciation Deferral - OR 2
39,639,321 52,254,334 12,615,013Deferred Steam Accel. Depreciation - WA 3
3,432 3,432Merwin Fish Collector Project - WA 254 4
5,551,592 1,649,391 8,019,148 4,116,947Direct Access 5-Year Opt Out - OR (10)442 5
395,946 88,961 309,200 2,215Transportation Electrification Program - CA 440,442,444 6
3,026,020 551,170 2,474,850Oregon Clean Fuels Program 456 7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/3-Q (REV 02-04) Page 278.1
41 TOTAL 424,907,414 654,888,504 1,700,242,286 1,930,223,376
Schedule Page: 278 Line No.: 13 Column: a
Weighted average remaining life is 39 years.
Schedule Page: 278 Line No.: 14 Column: a
Amounts primarily represent income tax liabilities related to the federal tax rate change
from 35% to 21% that are probable to be passed on to customers, offset by income tax
benefits related to certain property-related basis differences and other various
differences that were previously passed on to customers and will be included in regulated
rates when the temporary differences reverse.
Schedule Page: 278 Line No.: 15 Column: a
Weighted average remaining life is approximately two years for excess income tax deferrals
in rates being amortized.
Schedule Page: 278 Line No.: 17 Column: a
Weighted average remaining life of portion being amortized is 13 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: 278 Line No.: 17 Column: c
Other postretirement costs are associated with labor and generally charged to operations
and maintenance expense and construction work in progress.

Schedule Page: 278 Line No.: 23 Column: a
Includes California Solar on Multifamily Affordable Housing
Schedule Page: 278 Line No.: 26 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Account 419, Interest and dividend income
Account 908, Customer assistance 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
2020/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
/ /2020/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
1,815,760,353(440) Residential Sales 1,961,692,056 2
(442) Commercial and Industrial Sales 3
1,547,127,608Small (or Comm.) (See Instr. 4) 1,614,104,509 4
1,316,469,104Large (or Ind.) (See Instr. 4) 1,345,785,490 5
18,198,044(444) Public Street and Highway Lighting 17,750,042 6
(445) Other Sales to Public Authorities 7
(446) Sales to Railroads and Railways 8
(448) Interdepartmental Sales 9
4,697,555,109TOTAL Sales to Ultimate Consumers 4,939,332,097 10
192,271,657(447) Sales for Resale 189,250,874 11
4,889,826,766TOTAL Sales of Electricity 5,128,582,971 12
(Less) (449.1) Provision for Rate Refunds 3,239,918 13
4,889,826,766TOTAL Revenues Net of Prov. for Refunds 5,125,343,053 14
Other Operating Revenues 15
9,415,631(450) Forfeited Discounts 7,348,688 16
8,845,804(451) Miscellaneous Service Revenues 6,952,421 17
53,658(453) Sales of Water and Water Power 7,350 18
17,459,728(454) Rent from Electric Property 18,294,555 19
(455) Interdepartmental Rents 20
28,198,210(456) Other Electric Revenues 63,833,287 21
111,912,996(456.1) Revenues from Transmission of Electricity of Others 111,710,807 22
(457.1) Regional Control Service Revenues 23
(457.2) Miscellaneous Revenues 24
25
175,886,027TOTAL Other Operating Revenues 208,147,108 26
5,065,712,793TOTAL Electric Operating Revenues 5,333,490,161 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
/ /2020/Q4
Line
No.
MEGAWATT HOURS SOLD
Previous Year (no Quarterly)Current Year (no Quarterly)
AVG.NO. CUSTOMERS PER MONTH
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)
(d) (e) (f) (g)
6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by
the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of
classification in a footnote.)
7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
9. Include unmetered sales. Provide details of such Sales in a footnote.
1
16,668,416 1,681,634 1,713,382 17,150,116 2
3
18,150,545 214,182 217,070 17,727,147 4
20,395,896 33,151 33,096 19,563,642 5
127,750 3,565 3,576 119,073 6
7
8
9
55,342,607 1,932,532 1,967,124 54,559,978 10
5,479,628 5,249,066 11
60,822,235 1,932,532 1,967,124 59,809,044 12
13
60,822,235 1,932,532 1,967,124 59,809,044 14
Page 301
Line 12, column (b) includes $ of unbilled revenues.
Line 12, column (d) includes MWH relating to unbilled revenues
253,806,000
3,114,446
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
PacifiCorp's December 31, 2019 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:
2020 2019
Account service charges - application fees,
disconnects, reconnects and returned check charges $ 5,911,936 $ 7,556,998
Customer contract flat rate billings and facility
buyout charges 1,135,646 1,272,737

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:
2020 2019
Deferral/(amortization) of Oregon retail customers'
allocated share of the incremental Open Access
Transmission Tariff revenues associated with FERC
Docket No. ER11-3643,net of amortization $ 23,787,598 $ (3,135,370)
Amortization of California greenhouse gas
allowance revenue 12,764,541 12,254,503
Wind-based ancillary services 12,605,274 9,193,455
Flyash/by-product sales 6,851,586 4,075,964
Renewable energy credit sales, including
amortization and deferrals 3,720,207 2,878,143
Net gain/(loss) on sales of materials and supplies
inventory 1,056,572 (331,617)
Revenues from generation interconnection and
transmission service request studies 854,804 400,637
Amortization of Oregon clean fuels program credits 551,170 -
Maintenance charges for work on joint-owned
transmission facilities 449,880 471,749
Steam sales 440,116 557,219
Revenues from other requested customer studies 270,719 (a)
Timber sales (a) 649,985
Revenues for assigned purchased power agreement (a) 533,333
(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
2020/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
/ /2020/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
3,381 4 06LNX00311 - LINE EXT 80%
13 1 13,000 0.1252 1,628 5 06NBLDL136 - NET BILLING LOW
16 2 8,000 0.0954 1,526 6 06NBLDN136 - NET BLNG LOW
54 5 10,800 0.1162 6,273 7 06NETBL136 - CALIFORNIA NET
2,842 519 5,476 0.0943 267,937 8 06NETMT135 - CA RES NET
254 270 941 0.2460 62,481 9 06OALT015R - OUTD AR LGT SR
171,835 17,330 9,915 0.1121 19,261,377 10 06RESD000D - RES SRVC
119,282 11,458 10,410 0.1130 13,483,762 11 06RESDDL06 - CA LOW INCOME
1,483 481 3,083 0.1964 291,242 12 06RGNSV025 - CA SMALL GEN
1 166 13 06RNM25135 - CA NET MTR, GEN
160 6 26,667 0.0954 15,268 14 06RESD0DM9 - MULTI FAMILY
1,884 20 94,200 0.0733 138,136 15 06RESD0DS8 - MULT FAM SBMET
74,734 6,906 10,822 0.1134 8,473,662 16 06RESD00DN - CA RES SRVC -
-198,529 17 REVENUE - ACCT ADJ
941,419 18 INCOME TAX DEFERRAL ADJ
1,081,117 19 DSM REVENUE - RESIDENTIAL
106,499 20 BLUE SKY REV - RESIDENTIAL
37,139 21 OTHER CUST RETAIL REVENUE
-4,781 0.2000 -956,000 22 UNBILLED REVENUE
2,000 23 UNBILLED REV - UNCOLLECTIBLE
24
25 IDAHO
1,116 26 07LNX00010 - MNTHLY 80% GUAR
2,523 27 07LNX00035 - ADV 80% MO GUAR
3,304 1,094 3,020 0.0901 297,658 28 07NETMT135 - ID RES NET
6,432 177 36,339 0.0766 492,780 29 07NMT36135 - IDAHO
10 1 10,000 0.3815 3,815 30 07OALCO007 - CUST OWN LIGHT
90 113 796 0.4130 37,173 31 07OALT07AR - SECURITY AR LG
541,400 55,625 9,733 0.1139 61,652,493 32 07RESD0001 - RES SRVC
185,552 10,817 17,154 0.0976 18,102,325 33 07RESD0036 - RES SRVC-OPTIO
343 4 85,750 0.0834 28,609 34 07RGNSV06A - ID LRG GENERAL
9,714 1,152 8,432 0.1124 1,091,452 35 07RGNSV23A - ID SMALL
273 8 34,125 0.0745 20,327 36 07RNM23135 - RES USE NET MTR
5 1 5,000 37 07UPPL000R - BASE SCH FALL
-253,766 38 REVENUE - ACCT ADJ
118,505 39 INCOME TAX DEFERRAL ADJ
2,118,823 40 DSM REVENUE - RESIDENTIAL
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
215,579 1 BLUE SKY REV - RESIDENTIAL
-6,136 0.0590 -362,000 2 UNBILLED REVENUE
-18,000 3 UNBILLED REV - UNCOLLECTIBLE
4
5 OREGON
1 6 01CHCK000R - RES CHECK MTR
5,110,020 0.0604 308,655,021 7 01COST0004 - 01RESD0004
96,397 0.0616 5,937,496 8 01COSTR023 - OR RES GEN SRV,
44,597 0.0615 2,744,693 9 01COSTR028 - OR RES GEN
60,379 0.0593 3,580,060 10 01HABIT004 - 01RESD0004
195 0.0624 12,172 11 01HABTR023 - RES GEN SVC
3,140 12 01LNX00102 - LINE EXT 80% GTY
5,648 13 01LNX00109 - REF/NREF ADV +
6,687 2,707,545 14 01NETMT135 - NET METERING
43 23,069 15 01NMTOU135 - TOU NET
1,987 2,324 855 0.1610 319,969 16 01OALTB15R - OR OUTD AR LGT
14,343 0.0621 890,771 17 01PTOU0004 - 01RESD0004
5 0.0478 239 18 01PTOU0005 - 01RESEV05T TOU
2 0.0695 139 19 01PTOURB23 - RES GEN SVC;
447,243 0.0585 26,182,524 20 01RENEW004 - 01RESD0004
692 0.0608 42,105 21 01RENWR023 - RENEW USAGE
510,631 280,998,942 22 01RESD0004 - RES SRVC
1,024 673,810 23 01RESD004T - RES TIME OPT
1 305 24 01RESEV05T - RES ELECTRIC
17,102 7,061,432 25 01RGNSB023 - SMALL GENERAL
220 1,134,896 26 01RGNSB028 - GENERAL SVC > 30
102 27 01RGNSB23T - RES GEN SVC TOU
157 59,911 28 01RNETM023 - NET METER RES
4 50,773 29 01RNETM028 - NET METER RES
2 -162 30 01UPPL000R - BASE SCH FALL
471 359,250 31 01VIR04136 - OR RES VOLUME
-3,437,110 32 REVENUE - ACCT ADJ
17,176 33 OR GAIN ON SALE OF ASSET
17,958,664 34 INCOME TAX DEFERRAL ADJ
19,864,772 35 DSM REVENUE - RESIDENTIAL
867,628 36 BLUE SKY REV - RESIDENTIAL
2,099,905 37 SOLAR FEED-IN REVENUE
228,540 38 COMMUNITY SOLAR REVENUE
-16,019 0.0529 -848,000 39 UNBILLED REVENUE
-13,000 40 UNBILLED REV - UNCOLLECTIBLE
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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
-8 2 08BLSKY01R - BLUESKY ENERGY
735 3 08CFR00001 - MTH FACILITY S
466 52 8,962 0.1132 52,756 4 08CGENR136 - UT RES
448 120 3,733 0.1182 52,958 5 08CGNSL136 - UT RES
87,305 11,365 7,682 0.1078 9,411,335 6 08CGR01136 - UTAH RESIDENTIAL
1 13 7 08CGR01137 - UT RES CUST
62 9 6,889 0.1041 6,455 8 08CGR02136 - UT RES TOU
305 38 8,026 0.1073 32,720 9 08CGR03136 - UTAH LOW INC RES
111 1 111,000 0.1124 12,476 10 08CGR06136 - RES USE, GEN SVC
129 3 43,000 0.0825 10,642 11 08CGR23136 - RES SMALL GEN
50 7 7,143 0.1198 5,988 12 08CGS23136 - RES SMALL GEN
1 13 08CHCK000R - UT RES CHECK M
66,629 -12 14 08COOLKPRR - UT COOL KEEPER
8,858 15 08LNX00001 - MTHLY 80% GUAR
396 16 08LNX00005 - MTHLY MIN GUAR
26,858 17 08LNX00013 - 80% MNTHLY MIN
1,656 18 08LNX00108 - ANN COST MTHLY
11,847 9 1,316,333 0.0757 896,570 19 08MHTP0006 - MOBILE HOME &
121 1 121,000 0.0766 9,268 20 08MHTP0023 - MOBILE HOME &
1 175 21 08NETAGFEE - >6 NET METER
127,188 29,668 4,287 0.1170 14,879,704 22 08NETMT135 - NET METERING
1,237 208 5,947 0.1084 134,064 23 08NMT03135 - LOW INCOME RES
2,176 2,216 982 0.2787 606,537 24 08OALT007R - SECURITY AR LG
1 2 500 0.1050 105 25 08PTLD000R - POST TOP LIGHT
5 0.1006 503 26 08RCG06136 - UT RES NMT GEN
133 23 5,783 0.1237 16,449 27 08RCG23136 - RES NET METER,
7,005,442 781,285 8,967 0.1077 754,358,584 28 08RESD0001 - RES SRVC
3,346 395 8,471 0.1063 355,810 29 08RESD0002 - RES SRVC-OPTIO
164,337 21,500 7,644 0.1061 17,436,143 30 08RESD0003 - LIFELINE PRGRM
6,218 410 15,166 0.0861 535,358 31 08RESD002E - RES ELCTRC
143,925 314 458,360 0.0746 10,737,839 32 08RGNSV006 - GEN SRVC-RES
904 1 904,000 0.0689 62,261 33 08RGNSV008 - UT RES GENERAL
102,730 14,258 7,205 0.1074 11,033,371 34 08RGNSV023 - GEN SRVC-RES
8,815 28 314,821 0.0847 746,202 35 08RGNSV06A - UT SMALL
31 2 15,500 0.2584 8,010 36 08RGNSV06B - UT SMALL
3,539 12 294,917 0.0820 290,347 37 08RNM06135 - UT NET MTR, GEN
1,047 439 2,385 0.1423 149,023 38 08RNM23135 - UT NET MTR, GEN
18 3 6,000 0.5169 9,304 39 08RNM6A135 - RES GEN SVC NET
911 40 08RTCVLNGA - TCV LNX GAR
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
29,569 0.1129 3,339,150 1 08SSLR0001 - RES SUBSCRB
237 24 9,875 0.1146 27,152 2 08SSLR0003 - RES LOW INC
61 17 3,588 0.1370 8,359 3 08SSLRRG23 - RES SMALL GEN
4 4 08UPPL000R - BASE SCH FALL
57,268,116 5 REVENUE - ACCT ADJ
3,706,578 6 REVENUE ADJ - DEFERRED NPC
423,156 7 INCOME TAX DEFERRAL ADJ
5,345,429 8 DSM REVENUE - RESIDENTIAL
3,530,998 9 BLUE SKY REV - RESIDENTIAL
1,593,005 10 SOLAR FEED-IN REVENUE
-14,031 0.1036 -1,454,000 11 UNBILLED REVENUE
9,000 12 UNBILLED REV - UNCOLLECTIBLE
13
14 WASHINGTON
-1 15 02BLSKY01R - BLUESKY ENERGY
921 16 02LNX00109 - REF/NREF ADV +
12,307 1,380 8,918 0.1005 1,236,934 17 02NETMT135 - WA RES NET
912 1,000 912 0.1581 144,202 18 02OALTB15R - WA OUTD AR LGT
1,459,798 102,945 14,180 0.0926 135,175,629 19 02RESD0016 - WA RES SRVC
75,290 5,080 14,821 0.0927 6,977,974 20 02RESD0017 - BILL ASSISTANC
2,126 78 27,256 0.1023 217,384 21 02RESD0018 - WA 3 PHASE RES
292 11 26,545 0.1012 29,550 22 02RESD018X - WA 3 PHASE RES
20,215 3,442 5,873 0.1189 2,403,548 23 02RGNSB024 - WA SMALL
1,515 2 757,500 0.0748 113,321 24 02RGNSB036 - RES LRG GEN SVC
183 40 4,575 0.1258 23,026 25 02RNM24135 - RES NET METER
8,062,835 26 ALT REVENUE PROGRAM ADJ
-5,413,200 27 REVENUE - ACCT ADJ
61,834 28 REVENUE ADJ - DEFERRED NPC
4,635,481 29 DSM REVENUE - RESIDENTIAL
278,046 30 BLUE SKY REV - RESIDENTIAL
5,816 -0.7106 -4,133,000 31 UNBILLED REVENUE
11,000 32 UNBILLED REV - UNCOLLECTIBLE
33
34 WYOMING
748 35 05LNX00102 - LINE EXT 80% G
2,081 257 8,097 0.1178 245,134 36 05NETMT135 - EXPERIMENTAL
807 957 843 0.1397 112,740 37 05OALT015R - OUTD AR LGT SR
907,933 102,688 8,842 0.1059 96,168,942 38 05RESD0002 - WY RES SRVC
9,141 1,568 5,830 0.1218 1,112,923 39 05RGNSV025 - WY SMALL
346,580 40 REVENUE - ACCT ADJ
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
-67,180 1 REVENUE ADJ - DEFERRED NPC
306,791 2 INCOME TAX DEFERRAL ADJ
2,621,633 3 DSM REVENUE - RESIDENTIAL
85,182 4 BLUE SKY REV - RESIDENTIAL
-38,226 0.1068 -4,084,000 5 UNBILLED REVENUE
6,000 6 UNBILLED REV - UNCOLLECTIBLE
116,441 12,638 9,214 0.1074 12,500,667 7 05RESD0002 - WY RES SRVC
513 151 3,397 0.1572 80,659 8 05RGNSV025 - WY SMALL
68 82 829 0.2331 15,851 9 09OALT207R - SECURITY AR LG
7,899 10 05LNX00109 - REF/NREF ADV +
464 48 9,667 0.1174 54,484 11 05NETMT135 - EXPERIMENTAL
24 12 05OALT015R - OUTD AR LGT SR
-1 1 -1,000 0.1060 -106 13 09RES00002
4 14 09RESD0002
155,826 15 DSM REVENUE - RESIDENTIAL
21,147 16 BLUE SKY REV - RESIDENTIAL
16,065 0.1080 1,735,000 17 UNBILLED REV - UNCOLLECTIBLE
18
-92,695 19 LESS MULTIPLE BILLINGS
20
17,150,116 1,713,382 10,010 0.1144 1,961,692,056 21 TOTAL RESIDENTIAL SALES
22
23 COMMERCIAL SALES
24 CALIFORNIA
50,030 6,467 7,736 0.1646 8,234,688 25 06GNSV0025 - CA GEN SRVC
914 85 10,753 0.1801 164,639 26 06GNSV025F - GEN SRVC-< 20
83,376 1,146 72,754 0.1406 11,721,138 27 06GNSV0A32 - GEN SRVC-20 KW
26,865 8 3,358,125 0.0933 2,505,628 28 06LGSV048T - LRG GEN SERV
2,651 1 2,651,000 0.0924 244,823 29 06NMT48135 - CA GEN SVC NET
57,555 146 394,212 0.1197 6,887,901 30 06LGSV0A36 - LRG GEN SRVC-O
2,694 31 06LNX00102 - LINE EXT 80% G
103,480 32 06LNX00109 - REF/NREF ADV +
2,194 33 06LNX00110 - REF/NREF ADV +
30,132 34 06LNX00311 - LINE EXT 80%
2,617 35 06LNX00312 - CA IRG LINE EXT
6 1 6,000 0.1287 772 36 06NBL25136 - CA NET BILL GEN
75 1 75,000 0.1270 9,525 37 06NBL32136 - CA NET BILL GEN
2,818 6 469,667 0.1258 354,526 38 06NMT36135 - CA GEN SVC NET
620 457 1,357 0.2491 154,458 39 06OALT015N - OUTD AR LGT SR
112 37 3,027 0.2093 23,439 40 06RCFL0042 - AIRWAY & ATHLE
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
226 35 6,457 0.1731 39,127 1 06NMT25135 - CA GEN SVC NET
2,083 29 71,828 0.1608 334,856 2 06NMT32135 - CA GEN SVC NET
-88,027 3 REVENUE - ACCT ADJ
615,737 4 INCOME TAX DEFERRAL ADJ
665,146 5 DSM REVENUE - COMMERCIAL
9,104 6 BLUE SKY REV - COMMERCIAL
36,162 7 OTHER CUST RETAIL REVENUE
1,389 0.1562 217,000 8 UNBILLED REVENUE
9
10 IDAHO
4,763 83 57,386 0.0850 404,961 11 07CISH0019 - COMM & IND SPA
238,357 1,044 228,311 0.0822 19,603,220 12 07GNSV0006 - GEN SRVC-LRG P
52,198 3 17,399,333 0.0630 3,288,162 13 07GNSV0009 - GEN SRVC-HI VO
159,257 7,400 21,521 0.0992 15,801,624 14 07GNSV0023 - GEN SRVC-SML P
281 2 140,500 0.0988 27,763 15 07GNSV0035 - GEN SRVCOPTION
20,358 166 122,639 0.0896 1,823,942 16 07GNSV006A - GEN SRVC-LRG P
27,926 1,275 21,903 0.0981 2,739,459 17 07GNSV023A - GEN SRVC-SML P
7 4 1,750 0.2563 1,794 18 07GNSV023F - GEN SRVC SML P
32 1 32,000 0.1371 4,387 19 07GNSV035A - GEN SRVCOPTION
20,688 20 07LNX00010 - MNTHLY 80%GUAR
252,159 21 07LNX00035 - ADV 80%MO GUAR
29,394 22 07LNX00040 - ADV+REFCHG+80%
232 165 1,406 0.3860 89,551 23 07OALT007N - SECURITY AR LG
10 11 909 0.3994 3,994 24 07OALT07AN - SECURITY AR LG
460 25 07TCVLNXGN - TCV LNX - 80%
13,129 26 07LNX00312 - ID LINE EXT
1,996 6 332,667 0.0881 175,828 27 07NMT06135 - ID NET MTR -
1,316 39 33,744 0.0812 106,820 28 07NMT23135 - ID NET MTR -
33 1 33,000 0.0834 2,752 29 07NMT6A135 - NET METERING
519 30 07LNX00015 - ANNUAL 80%GUAR
32,307 31 07LNX00311 - LINE EXT 80%
3,061 32 07LNX00300 - 80% MONTHLY MIN
-149,312 33 REVENUE - ACCT ADJ
83,332 34 INCOME TAX DEFERRAL ADJ
1,176,666 35 DSM REVENUE - COMMERCIAL
20,043 36 BLUE SKY REV - COMMERCIAL
-12,691 0.0741 -941,000 37 UNBILLED REVENUE
38
39 OREGON
976,201 0.0596 58,138,115 40 01COST0023 - OR GEN SRV, COST
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
1,269,098 0.0490 62,165,764 1 01COST0048 - 01LGSV0048
2,883 0.0630 181,632 2 01COST023F - OR GEN SRV -
24,157 0.0604 1,459,633 3 01COSTB023 - OR GEN SRV,
252 0.0621 15,654 4 01COSTEV45 - ELECT VEHICLE
1,037,815 0.0529 54,899,657 5 01COSTL030 - OR LRG GEN SRV,
1,818,036 0.0616 111,988,275 6 01COSTS028 - OR GEN SERV,
2,789 1,524,097 7 01GNSB0023 - OR GEN SRV, BPA,
289 1,683,514 8 01GNSB0028 - OR GEN SRV, BPA,
41 21,945 9 01GNSB023T - OR GEN SRV - TOU
37 24,837 10 01GNSB0723 - OR GEN SVC DIR
2 23,670 11 01GNSB0728 - OR GEN SVC DIR
18 64,406 12 01GNSEV45T - ELECT VEHICLE
59,711 49,872,708 13 01GNSV0023 - OR GEN SRV, < 30
8,981 49,760,123 14 01GNSV0028 - OR GEN SRV > 30
10,630 787 13,507 0.1534 1,630,316 15 01GNSV023F - OR GEN SRV - FLAT
123 2 61,500 0.0900 11,071 16 01GNSV023M - OR GEN SRV,
184 135,305 17 01GNSV023T - OR GEN SRV, TOU
4 7,420 18 01GNSV0723 - OR GEN SVC DIR
2,996 0.0606 181,675 19 01HABT0023 - OR HABITAT
8 0.0659 527 20 01HABTB023 - OR HABITAT
23 964,349 21 01LGSB0030 - GEN DEL SRV, > 200
626 25,169,982 22 01LGSV0030 - OR LRG GEN SRV, >
95 19,576,030 23 01LGSV0048 - 1000KW AND OVR
53,224 1 53,224,000 0.0607 3,228,733 24 01LGSV048M - LRG GEN SRVC 1
5,658 25 01LNX00100 - LINE EXT 60% G
995,563 26 01LNX00102 - LINE EXT 80% G
4,555 27 01LNX00103 - LINE EXT 80% G
12,178 28 01LNX00105 - CNTRCT $ MIN G
1,504,954 29 01LNX00109 - REF/NREF ADV +
7,625 30 01LNX00110 - REF/NREF ADV +
229,615 31 01LNX00311 - LINE EXT 80% G
8 32 01LNX00120 - LINE EXT 60% G
340,277 33 01LNX00300 - LINE EXT 80% G
2,566 34 01LNX00310 - LINE EXTENSION
28,930 5 5,786,000 0.1155 3,341,618 35 01LPRS047M - PART REQ SRVC
1 1,407 36 01NM23T135 - OR NET MTR TOU
474 363,979 37 01NMT23135 - OR NET MTR, GEN,
263 1,653,212 38 01NMT28135 - OR NET MTR, GEN,
39 1,534,771 39 01NMT30135 - OR NET MTR, GEN,
4 423,668 40 01NMT48135 - NET METERING
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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 1,070 1 01NMTEV45T - OR NET MTR, EV
5,100 2,688 1,897 0.1450 739,593 2 01OALT015N - OUTD AR LGT NR
1,340 995 1,347 0.1657 221,982 3 01OALTB15N - OR OUTD AR LGT
2,554 0.0592 151,155 4 01PTOU0023 - OR GEN SRV, TOU
353 0.0618 21,825 5 01PTOUB023 - OR GEN SRV, TOU
1,110 103 10,777 0.0980 108,737 6 01RCFL0054 - REC FIELD LGT
12,341 0.0610 753,072 7 01RENW0023 - OR RENW USAGE
244 0.0563 13,731 8 01RENWB023 - OR RENEWABLE
3,333 0.0597 198,935 9 01STDAY023 - OR DAY STD OFR,
12,339 0.0609 750,984 10 01STDAY028 - OR DAY STD OFF,
4,387 0.0537 235,473 11 01STDAY030 - OR STD DAY OFF,
125 162,999 12 01VIR23136 - OR VOLUME
90 515,664 13 01VIR28136 - OR VOLUME
4 161,684 14 01VIR30136 - OR VOLUME
1 95,356 15 01VIR48136 - OR VOLUME
20,315 16 01LGSB0048 - LG GEN SVC >
367 1 367,000 0.0982 36,057 17 01LGSV028M - OR LGSV, <1000
6 170,951 18 01GNSV0728 - OR GEN SVC DIR
14 1,697,479 19 01GNSV0730 - OR GEN SVC DIR
3 8,883,916 20 01GNSV0748 - LG GEN SVC DIR
-1,006,234 21 REVENUE - ACCT ADJ
16,237 22 OR GAIN ON SALE OF ASSET
17,028,567 23 INCOME TAX DEFERRAL ADJ
11,949,438 24 DSM REVENUE - COMMERCIAL
102 971,673 25 BLUE SKY REV - COMMERCIAL
1,977,033 26 SOLAR FEED-IN REVENUE
168,786 27 COMMUNITY SOLAR REVENUE
9,079 28 OTHER CUST RETAIL REVENUE
99,695 0.0944 9,409,000 29 UNBILLED REVENUE
30
31 UTAH
1,303 32 08ABL-NRES - APPLICANT BUILT
10,073 33 08ABTCLXGN - LINE EXT 80%
32,773 34 08CFR00051 - MTH FAC SRVCHG
2 35 08CFR00052 - ANN FAC SVCCHG
1,874 5 374,800 0.1127 211,157 36 08CGM06136 - UT NET METERING
493 25 19,720 0.1017 50,116 37 08CGM23136 - UTAH NET METER
2,857 1 2,857,000 0.0774 221,198 38 08CGN08136 - UT NET MTR GEN
19,751 48 411,479 0.0927 1,830,013 39 08CGN06136 - UT GEN SVC
2,023 99 20,434 0.0999 201,997 40 08CGN23136 - UTAH NET METER
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
3,964 8 495,500 0.0830 328,954 1 08CGN6A136 - UT GEN SVC TRAN
1,435 2 08COOLKPRN - A/C DIRECT LOAD
4,820,994 11,191 430,792 0.0821 395,758,929 3 08GNSV0006 - GEN SRVC-DISTR
819,217 40 20,480,425 0.0553 45,300,078 4 08GNSV0009 - GEN SRVC-HI VO
1,228,328 75,849 16,194 0.0976 119,861,509 5 08GNSV0023 - GEN SRVC-DISTR
239,151 1,959 122,078 0.1126 26,920,306 6 08GNSV006A - GEN SRVC-ENERG
3,354 16 209,625 0.0987 331,028 7 08GNSV006B - GEN SRVC-DEM&
1 8 08GNSV006M - MNL DIST VOLTG
22,929 2 11,464,500 0.0654 1,498,581 9 08GNSV009A - GEN SRVC HI VO
223,179 1 223,179,000 0.0558 12,449,558 10 08GNSV009M - MANL HIGH VOLT
1,301 129 10,085 0.1398 181,934 11 08GNSV023F - GEN SRVC FIXED
10 0.0668 668 12 08GNSV023M - GNSV DIST VOLT
768,277 117 6,566,470 0.0722 55,464,204 13 08GNSV0008 - UT GEN SVC TOU >
8,524 2 4,262,000 0.0718 611,716 14 08GNSV008M - UT GEN SVC TOU >
518 1 518,000 0.0969 50,194 15 08GNSV06AM - MNL ENERGY TOD
37,806 654 57,807 0.0790 2,985,779 16 08GNSV06MN - GNSV DIST VOLT
889,133 17 08LNX00002 - MTHLY 80% GUAR
73,260 18 08LNX00004 - ANNUAL 80%GUAR
2,882 19 08LNX00006 - FIXD MTHLY MIN
2,199,909 20 08LNX00014 - 80% MIN MNTHLY
326,966 21 08LNX00017 - ADV/REF&80%ANN
29,954 22 08LNX00158 - ANNUALCOST MTH
220,283 23 08LNX00300 - LINE EXT 80% PLUS
61,625 24 08LNX00310 - IRR, 80% ANNUAL
322,214 25 08LNX00311 - LINE EXT 80%
14,462 26 08LNX00312 - UT IRG LINE EXT
13,342 540 24,707 0.0724 965,978 27 08MONL0015 - MTR OUTDONIGHT
112,486 264 426,083 0.0840 9,451,140 28 08NMT06135 - UT NET METERING
53,548 11 4,868,000 0.0754 4,037,230 29 08NMT08135 - NET METERING
9,206 827 11,132 0.1046 962,762 30 08NMT23135 - UT NET MTR, GEN,
9,385 88 106,648 0.1349 1,266,495 31 08NMT6A135 - NET METERING
2,391 1 2,391,000 0.1056 252,569 32 08NMT8135M - NET METERING
7,039 3,776 1,864 0.2282 1,606,434 33 08OALT007N - SECURITY AR LG
1 148 34 08POLE0075 - POLES W/LIGHT
192,388 4 48,097,000 0.0585 11,260,383 35 08PRSV031M - BKUP MNT&SUPPL
6 2 3,000 0.0753 452 36 08PTLD000N - POST TOP LIGHT
21,100 0.0546 1,151,222 37 08REFP034M - RENEWABLE QUAL
169,428 3 56,476,000 0.0696 11,791,247 38 08REFS032M - UT RENEWABLE
4,152 9 461,333 0.0965 400,486 39 08SSLR0006 - GENERAL SVC
3,302 0.1095 361,621 40 08SSLR0023 - SMALL GEN SVC
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
45,708 334 136,850 0.0845 3,861,648 1 08SSLR006A - GEN SVC TOU
-3,536 2 08TCVLAACN - UTAH TCV LNX
1,890 3 08TCVLNAGN - UTAH LNX ANNUAL
172,329 4 08TCVLNXGN - TCV LNX - 80%
11,127 5 08TCVLXACN - GAR ADDED
3,138 1,087 2,887 0.1038 325,695 6 08TOSS0015 -TRAF &AMP; OTHER
171 20 8,550 0.0894 15,285 7 08TOSS015F - TRAFFIC SIG NM
62,009,142 8 REVENUE - ACCT ADJ
4,774,655 9 REVENUE ADJ - DEFERRED NPC
539,974 10 INCOME TAX DEFERRAL ADJ
6,821,172 11 DSM REVENUE - COMMERCIAL
753,214 12 BLUE SKY REV - COMMERCIAL
2,032,774 13 SOLAR FEED-IN REVENUE
-27,718 0.0810 -2,246,000 14 UNBILLED REVENUE
15
16 WASHINGTON
15 2 7,500 0.2259 3,388 17 02GN24EV45 - WA ELECTRIC
27,211 1,516 17,949 0.0972 2,646,009 18 02GNSB0024 - WA GEN SRVC DO
52 3 17,333 0.1279 6,650 19 02GNSB024F - GEN SRVC DOM/F
881 70 12,586 0.1481 130,517 20 02GNSB24FP - WA GEN SVC
454,838 14,599 31,155 0.0910 41,392,545 21 02GNSV0024 - WA GEN SRVC
1,173 107 10,963 0.1372 160,940 22 02GNSV024F - WA GEN SRVC-FL
47,358 87 544,345 0.0795 3,764,398 23 02LGSB0036 - LRG GEN SVC IRG
755,004 850 888,240 0.0755 57,004,286 24 02LGSV0036 - WA LRG GEN SRV
183,530 37 4,960,270 0.0751 13,783,136 25 02LGSV048T - LRG GEN SRVC 1
78,894 26 02LNX00102 - LINE EXT 80% G
51,042 27 02LNX00103 - LINE EXT 80% G
2,554 28 02LNX00105 - CNTRCT $ MIN G
289,751 29 02LNX00109 - REF/NREF ADV +
30,916 30 02LNX00110 - REF/NREF ADV +
669 31 02LNX00112 - YR INCURRED CH
7,384 32 02LNX00300 - LINE EXT 80% G
1,434 33 02LNX00310 - IRG, 80% ANNUAL
57,151 34 02LNX00311 - LINE EXT 80%
15,733 35 02LNX00312 - WA IRG LINE EXT
112 23 4,870 0.1336 14,963 36 02NMB24135 - WA NET METERING
1,405 763 1,841 0.1468 206,228 37 02OALT015N - WA OUTD AR LGT
495 462 1,071 0.1601 79,267 38 02OALTB15N - WA OUTD AR LGT
176 26 6,769 0.0957 16,838 39 02RCFL0054 - WA REC FIELD L
3,982 114 34,930 0.0966 384,745 40 02NMT24135 - WA NET METERING
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
11,845 17 696,765 0.0822 974,212 1 02NMT36135 - WA NET METER
10,027 2 5,013,500 0.0725 726,900 2 02NMT48135 - WA LG SVC NET
5,001,829 3 ALT REVENUE PROGRAM ADJ
-6,911,882 4 REVENUE - ACCT ADJ
59,795 5 REVENUE ADJ - DEFERRED NPC
3,845,918 6 DSM REVENUE - COMMERCIAL
2 37,524 7 BLUE SKY REV - COMMERCIAL
4,157 0.0488 203,000 8 UNBILLED REVENUE
9
10 WYOMING
1 11 05CHCK000N - WY NRES CHECK
220,416 18,159 12,138 0.0960 21,164,552 12 05GNSV0025 - WY GEN SRVC
805,357 3,133 257,056 0.0830 66,812,280 13 05GNSV0028 - GEN SVC > 15 KW
985 171 5,760 0.1548 152,470 14 05GNSV025F - GEN SRVC-FL RA
158,241 16 9,890,063 0.0708 11,203,344 15 05LGSV0046 - WY LRG GEN SRV
10,780 1 10,780,000 0.0704 759,034 16 05LGSV048T - LRG GENSRV TIM
15,574 17 05LNX00100 - LINE EXT 60% G
476,973 18 05LNX00102 - LINE EXT 80% G
13 19 05LNX00103 -LINE EXT 80% G
5,433 20 05LNX00105 - CNTRCT $ MIN G
307,821 21 05LNX00109 - REF/NREF ADV +
3,020 22 05LNX00110 - REF/NREF ADV +
129 23 05LNX00114 - TEMP SVC 12MO>
411 36 11,417 0.0965 39,643 24 05NMT25135 - WY NET MTR, GEN,
7,427 23 322,913 0.0877 651,472 25 05NMT28135 - NET MTR SMALL
2,490 1,547 1,610 0.1410 351,055 26 05OALT015N - OUTD AR LGT SR
737 58 12,707 0.0688 50,672 27 05RCFL0054 - WY REC FIELD L
13 28 09OALT207N - SECURITY AR LG
88,792 29 05LNX00300 - LINE EXT 80%
4,513 30 05LNX00310 - LINE EXTENSION
32,563 31 05LNX00311 - LINE EXT 80%
2,915 32 05LNX00312 - WY IRG LINE EXT
283,498 33 REVENUE - ACCT ADJ
-91,607 34 REVENUE ADJ - DEFERRED NPC
418,449 35 INCOME TAX DEFERRAL ADJ
1,069,144 36 DSM REVENUE - SM
56,700 37 DSM REVENUE - LG COMMERCIAL
6,022 38 BLUE SKY REV - COMMERCIAL
-19,260 0.0791 -1,523,000 39 UNBILLED REVENUE
29,953 2,461 12,171 0.0961 2,878,997 40 05GNSV0025 - WY GEN SRVC
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
90,015 378 238,135 0.0816 7,341,914 1 05GNSV0028 - GEN SVC > 15 KW
199 33 6,030 0.1231 24,502 2 05GNSV025F - GEN SRVC-FL RA
115,218 3 05LNX00102 - LINE EXT 80% G
-206 4 05LNX00103 - LINE EXT 80% G
118,446 5 05LNX00109 - REF/NREF ADV +
1,530 6 05LNX00110 - REF/NREF ADV +
115 5 23,000 0.0831 9,560 7 05NMT25135 - WY NET MTR, GEN,
380 2 190,000 0.0858 32,596 8 05NMT28135 - NET MTR SMALL
273 141 1,936 0.2027 55,331 9 09OALT207N - SECURITY AR LG
230 12 19,167 0.0595 13,675 10 09MONL0213 - WY MTR OUTDOOR
539 11 05LNX00300 - LINE EXT 80%
2,747 12 05LNX00311 - LINE EXT 80%
398,291 13 DSM REVENUE - SM
743 14 BLUE SKY REV - COMMERCIAL
2,204 0.0812 179,000 15 UNBILLED REVENUE
16
-23,465 17 LESS MULTIPLE BILLINGS
18
17,727,147 217,070 81,666 0.0911 1,614,104,509 19 TOTAL COMMERCIAL SALES
20
21 INDUSTRIAL SALES
22 CALIFORNIA
496 81 6,123 0.1727 85,667 23 06GNSV0025 - CA GEN SRVC
2,337 23 101,609 0.1512 353,340 24 06GNSV0A32 - GEN SRVC-20 KW
47,067 10 4,706,700 0.0961 4,524,682 25 06LGSV048T - LRG GEN SERV
5,468 13 420,615 0.1339 732,342 26 06LGSV0A36 - LRG GEN SRVC-O
685 27 REVENUE - ACCT ADJ
146,322 28 INCOME TAX DEFERRAL ADJ
136,398 29 DSM REVENUE - INDUSTRIAL
250 30 BLUE SKY REV - INDUSTRIAL
15,551 31 OTHER CUST RETAIL REVENUE
216 0.0972 21,000 32 UNBILLED REVENUE
33
34 IDAHO
2,217 35 07CFR00001 - MTH FACILITY S
17 1 17,000 0.0967 1,644 36 07CISH0019 - COMM & IND SPA
88,619 101 877,416 0.0709 6,282,611 37 07GNSV0006 - GEN SRVC-LRG P
69,065 14 4,933,214 0.0669 4,618,411 38 07GNSV0009 - GEN SRVC-HI VO
15,007 309 48,566 0.0947 1,421,187 39 07GNSV0023 - GEN SRVC-SML P
2,713 21 129,190 0.0871 236,312 40 07GNSV006A - GEN SRVC-LRG P
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
2,037 136 14,978 0.1027 209,287 1 07GNSV023A - GEN SRVC-SML P
5 1 5,000 0.1216 608 2 07GNSV023S - IDAHO TRAFFIC
1,996 3 07LNX00108 - ANN COST MTHLY
218 4 07LNX00311 - LINE EXT 80%
2 0.1330 266 5 07NMT23135 - ID NET MTR -
13 16 813 0.3788 4,925 6 07OALT007N - SECURITY AR LG
1 238 7 07OALT07AN - SECURITY AR LG
1,248,900 1 1,248,900,000 0.0630 78,646,700 8 07SPCL0001
113,694 1 113,694,000 0.0597 6,791,774 9 07SPCL0002
-52,547 10 REVENUE - ACCT ADJ
267,945 11 INCOME TAX DEFERRAL ADJ
808,706 12 DSM REVENUE - INDUSTRIAL
85 13 BLUE SKY REV - INDUSTRIAL
103,278 0.0609 6,291,000 14 UNBILLED REVENUE
15
16 OREGON
17,439 0.0598 1,042,390 17 01COST0023 - OR GEN SRV, COST
1,169,802 0.0501 58,584,834 18 01COST0048 - 01LGSV0048
1 0.0650 65 19 01COST023F - OR GEN SRV -
126 0.0573 7,219 20 01COSTB023 - OR GEN SRV,
170,827 0.0530 9,057,914 21 01COSTL030 - OR LRG GEN SRV,
82,135 0.0615 5,047,498 22 01COSTS028 - OR GEN SERV,
12 8,220 23 01GNSB0023 - OR GEN SRV, BPA,
1 5,507 24 01GNSB0028 - OR GEN SRV, BPA,
956 914,740 25 01GNSV0023 - OR GEN SRV, < 30
401 2,875,120 26 01GNSV0028 - OR GEN SRV > 30
2 2 1,000 0.3390 678 27 01GNSV023F - OR GEN SRV - FLAT
1 312 28 01GNSV023M - OR GEN SRV,
3 2,608 29 01GNSV023T - OR GEN SRV, TOU
3 1,281,490 30 01GNSV0748 - LG GEN SVC DIR
125 6,277,867 31 01LGSV0030 - OR LRG GEN SRV, >
79 20,015,282 32 01LGSV0048 - 1000KW AND OVR
94,872 4 23,718,000 0.0690 6,547,779 33 01LGSV048M - LRG GEN SRVC 1
111,130 34 01LNX00102 - LINE EXT 80% G
138 35 01LNX00109 - REF/NREF ADV +
14,144 36 01LNX00300 - LINE EXT 80%
1,606 1 1,606,000 0.6071 975,003 37 01LPRS047M - PART REQ SRVC
5 3,832 38 01NMT23135 - OR NET MTR, GEN,
6 48,586 39 01NMT28135 - OR NET MTR, GEN,
3 77,620 40 01NMT30135 - OR NET MTR, GEN,
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
248 115 2,157 0.1406 34,873 1 01OALT015N - OUTD AR LGT NR
3 3 1,000 0.1327 398 2 01OALTB15N - OR OUTD AR LGT
44 0.0622 2,738 3 01PTOU0023 - OR GEN SRV, TOU
49 0.0606 2,970 4 01RENW0023 - OR RENW USAGE
1 775 5 01VIR23136 - OR VOLUME
2 11,767 6 01VIR28136 - OR VOLUME
1 63,825 7 01VIR30136 - OR VOLUME
-1,199,794 8 REVENUE - ACCT ADJ
4,918 9 OR GAIN ON SALE OF ASSET
5,109,377 10 INCOME TAX DEFERRAL ADJ
908,860 11 DSM REVENUE - INDUSTRIAL
5 546,541 12 BLUE SKY REV - INDUSTRIAL
572,163 13 SOLAR FEED-IN REVENUE
47,225 14 COMMUNITY SOLAR REVENUE
17,984 0.0202 363,000 15 UNBILLED REVENUE
16
17 UTAH
15,229 18 08CFR00051 - MTH FAC SRVCHG
6 0.1473 884 19 08CGM23136 - UTAH NET METER
1,547 1 1,547,000 0.0780 120,702 20 08CGN06136 - UT GEN SVC
869 2 434,500 0.1589 138,071 21 08EFOP021M - ELEC FURNACE O
582,322 936 622,139 0.0849 49,415,413 22 08GNSV0006 - GEN SRVC-DISTR
971,766 97 10,018,206 0.0734 71,300,348 23 08GNSV0008 - UT GEN SVC TOU >
2,797,061 101 27,693,673 0.0549 153,513,533 24 08GNSV0009 - GEN SRVC-HI VO
51,756 3,124 16,567 0.0973 5,033,822 25 08GNSV0023 - GEN SRVC-DISTR
46,132 225 205,031 0.1187 5,477,101 26 08GNSV006A - GEN SRVC-ENERG
27,470 4 6,867,500 0.0793 2,177,840 27 08GNSV008M - UT GEN SVC TOU >
17,113 7 2,444,714 0.0908 1,553,628 28 08GNSV009A - GEN SRVC HI VO
633,036 11 57,548,727 0.0525 33,237,684 29 08GNSV009M - MANL HIGH VOLT
4 1 4,000 0.6393 2,557 30 08GNSV023F - GEN SRVC FIXED
268 2 134,000 0.1190 31,885 31 08GNSV06AM - MNL ENERGY TOD
918 21 43,714 0.0922 84,668 32 08GNSV06MN - GNSV DIST VOLT
760,010 33 08LNX00002 - MTHLY 80% GUAR
15,143 34 08LNX00014 - 80% MIN MNTHLY
638 35 08LNX00017 - ADV/REF&80%ANN
80,209 36 08LNX00300 - LINE EXT 80% PLUS
925 386 2,396 0.2106 194,781 37 08OALT007N - SECURITY AR LG
51 12 4,250 0.0970 4,945 38 08TOSS0015 - TRAF &AMP; OTHER
13 6 2,167 0.1542 2,004 39 08MONL0015 - MTR OUTDONIGHT
2,151 6 358,500 0.0927 199,334 40 08NMT06135 - UT NET METERING
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
140 17 8,235 0.1203 16,843 1 08NMT23135 - UT NET MTR, GEN,
4,247 13 326,692 0.1340 569,287 2 08NMT6A135 - NET METERING
56,322 3 18,774,000 0.0720 4,056,967 3 08PRSV031M - BKUP MNT&SUPPL
653,823 1 653,823,000 0.0516 33,706,533 4 08SPCL0001
704,448 1 704,448,000 0.0452 31,844,950 5 08SPCL0002
1,375,784 1 1,375,784,000 0.0407 56,051,770 6 08SPCL0003
685 2 342,500 0.0808 55,369 7 08SSLR0006 - GENERAL SVC
157 21 7,476 0.1659 26,050 8 08SSLR0023 - SMALL GEN SVC
13,039 31 420,613 0.0937 1,221,899 9 08SSLR006A - GEN SVC TOU
1,912 10 08TCVLNXGN - TCV LNX - 80%
63,156,718 11 REVENUE - ACCT ADJ
4,215,097 12 REVENUE ADJ - DEFERRED NPC
477,496 13 INCOME TAX DEFERRAL ADJ
6,031,778 14 DSM REVENUE - INDUSTRIAL
7 183,828 15 BLUE SKY REV - INDUSTRIAL
1,797,571 16 SOLAR FEED-IN REVENUE
54,388 0.0625 3,400,000 17 UNBILLED REVENUE
18
19 WASHINGTON
800 42 19,048 0.1080 86,401 20 02GNSB0024 - WA GEN SRVC DO
5 1 5,000 0.3716 1,858 21 02GNSB24FP - WA GEN SVC
14,381 324 44,386 0.0916 1,317,685 22 02GNSV0024 - WA GEN SRVC
33 4 8,250 0.2637 8,701 23 02GNSV024F - WA GEN SRVC-FL
88,225 91 969,505 0.0801 7,064,950 24 02LGSV0036 - WA LRG GEN SRV
84,845 0.0606 5,138,986 25 02LGSV048M - WA LRG GEN SRV
616,135 30 20,537,833 0.0646 39,773,369 26 02LGSV048T - LRG GEN SRVC 1
31,005 27 02LNX00103 - LINE EXT 80% G
27,781 28 02LNX00300 - LINE EXT 80% G
21 2 10,500 0.1114 2,340 29 02NMT24135 - WA NET METERING
91 37 2,459 0.1327 12,075 30 02OALT015N - WA OUTD AR LGT
27 14 1,929 0.1527 4,122 31 02OALTB15N - WA OUTD AR LGT
1,326 1 1,326,000 0.1983 262,980 32 02PRSV47TM - LRG PART REQMT
1,238 9 137,556 0.1316 162,900 33 02LGSB0036 - LRG GEN SVC IRG
-871,939 34 ALT REVENUE PROGRAM ADJ
-88,802 35 REVENUE - ACCT ADJ
30,293 36 REVENUE ADJ - DEFERRED NPC
1,713,756 37 DSM REVENUE - INDUSTRIAL
20 38 BLUE SKY REV - INDUSTRIAL
-6,294 0.0821 -517,000 39 UNBILLED REVENUE
40
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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
15,054 1,120 13,441 0.0951 1,430,965 2 05GNSV0025 - WY GEN SRVC
220,156 428 514,383 0.0736 16,206,268 3 05GNSV0028 - GEN SVC > 15 KW
26 8 3,250 0.1609 4,183 4 05GNSV025F - GEN SRVC-FL RA
1,596,865 61 26,178,115 0.0661 105,572,964 5 05LGSV0046 - WY LRG GEN SRV
8,108 1 8,108,000 0.0787 638,432 6 05LGSV046M - WY LRG GEN SRV
208,620 1 208,620,000 0.0562 11,731,726 7 05LGSV048M - TOU>1000KW MAN
1,728,733 11 157,157,545 0.0559 96,679,860 8 05LGSV048T - LRG GENSRV TIM
72,147 9 05LNX00100 - LINE EXT 60% G
1,014,590 10 05LNX00102 - LINE EXT 80% G
43,369 11 05LNX00105 - CNTRCT $ MIN G
157,374 12 05LNX00109 - REF/NREF ADV +
186 13 05LNX00110 - REF/NREF ADV +
169,311 14 05LNX00300 - LINE EXT 80%
13,994 15 05LNX00311 - LINE EXT 80%
66 38 1,737 0.1285 8,481 16 05OALT015N - OUTD AR LGT SR
1,022,840 10 102,284,000 0.0697 71,342,754 17 05PRSV033M - PART SERV REQ
-3,120,823 18 REVENUE - ACCT ADJ
-460,994 19 REVENUE ADJ - DEFERRED NPC
2,105,565 20 INCOME TAX DEFERRAL ADJ
137,193 21 DSM REVENUE - SM INDUSTRIAL
1,090,300 22 DSM REVENUE - LG INDUSTRIAL
40 23 BLUE SKY REV - INDUSTRIAL
64,287 0.0700 4,498,000 24 UNBILLED REVENUE
3,187 280 11,382 0.0984 313,713 25 05GNSV0025 - WY GEN SRVC
64,127 68 943,044 0.0705 4,521,241 26 05GNSV0028 - GEN SVC > 15 KW
4,447 3 1,482,333 0.0600 266,778 27 05GNSV028M - GEN SVC > 15 KW
16,281 2 8,140,500 0.0681 1,108,325 28 05LGSV0046 - WY LRG GEN SRV
98,136 2 49,068,000 0.0609 5,980,883 29 05LGSV048M - TOU>1000KW MAN
934,655 13 71,896,538 0.0617 57,666,072 30 05LGSV048T - LRG GENSRV TIM
1,138,364 31 05LNX00102 - LINE EXT 80% G
1,352,123 32 05LNX00109 - REF/NREF ADV +
1,406 33 05LNX00300 - LINE EXT 80%
36 1 36,000 0.0818 2,944 34 05NMT25135 - WY NET MTR, GEN,
22,298 1 22,298,000 0.0690 1,539,033 35 05PRSV033M - PART SERV REQ
5 3 1,667 0.1694 847 36 09OALT207N - SECURITY AR LG
197,975 37 DSM REVENUE - SM INDUSTRIAL
545,804 38 DSM REVENUE - LG INDUSTRIAL
6 39 BLUE SKY REV - INDUSTRIAL
-20,308 0.0586 -1,190,000 40 UNBILLED REVENUE
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
-828 1 LESS MULTIPLE BILLINGS
2
18,038,965 9,275 1,944,902 0.0664 1,198,036,809 3 TOTAL INDUSTRIAL SALES
4
5 IRRIGATION SALES
6 CALIFORNIA
12,184 775 15,721 0.1252 1,525,451 7 06APSV0020 - AG PMP SRVC
13 2 6,500 0.1375 1,788 8 06APSV0115 - CA AGRI PUMP TOU
59,645 559 106,699 0.1230 7,335,950 9 06APSV020L - AG PMP SRVC-NO
936 9 104,000 0.1103 103,245 10 06APSV115L - CA AGRI PUMP
224 1 224,000 0.2556 57,251 11 06LGSV048T - LRG GEN SERV
987 12 06LNX00103 - LINE EXT 80% G
21,426 13 06LNX00110 - REF/NREF ADV +
28,504 14 06LNX00312 - CA IRG LINE EXT
1,908 30 63,600 0.1818 346,862 15 06NML20135 - AGRI PUMP-NET
139 13 10,692 0.1560 21,683 16 06NMT20135 - AGRICULTURAL
7,466 265 28,174 0.1189 887,764 17 06USBR0020 - KLAM IRG ONPRJ
6 2 3,000 0.4503 2,702 18 06USBR0115 - CA AGR PMP TOU
22,128 348 63,586 0.1414 3,128,304 19 06USBR020L - KLAM IRG
547 7 78,143 0.1237 67,648 20 06USBR115L - CA AGR PMP TOU
-59,571 21 REVENUE - ACCT ADJ
211,389 22 INCOME TAX DEFERRAL ADJ
257,641 23 DSM REVENUE - IRRIGATION
84 24 BLUE SKY REV - IRRIGATION
4,040 25 OTHER CUST RETAIL REVENUE
-257 0.0117 -3,000 26 UNBILLED REVENUE
27
28 IDAHO
361,510 2,302 157,042 0.0920 33,248,290 29 07APSA010L - IRG & PUMP LARGE
6,233 325 19,178 0.1066 664,678 30 07APSA010S - IRG & PUMP SMALL
242,156 1,904 127,183 0.0935 22,635,665 31 07APSAL10X - IRG & PUMP -
8,364 555 15,070 0.1103 922,674 32 07APSAS10X - IRG & PUMP -
480 1 480,000 0.0876 42,066 33 07APSV006A - LRG POWER
91 4 22,750 0.1045 9,505 34 07APSV023A - SMALL POWER
13,989 36 388,583 0.0834 1,166,588 35 07APSVCNLL - LRG LOAD CANAL
28 11 2,545 0.1660 4,648 36 07APSVCNLS - SML LOAD CANAL
82 1 82,000 0.0929 7,621 37 07GNSV023A - GEN SRVC-SML P
66,631 38 07LNX00015 - ANNUAL 80%GUAR
1,406 39 07LNX00035 - ADV 80%MO GUAR
94,002 40 07LNX00040 - ADV+REFCHG+80%
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
2,915 1 07LNX00310 - 80% ANNUAL
27,896 2 07LNX00312 - ID LINE EXT
8,363 36 232,306 0.0899 751,650 3 07APSN010L - ID LG IRR & PUMP
17 3 5,667 0.1544 2,625 4 07APSN010S - IRRIGATION,
241 16 15,063 0.1200 28,921 5 07APSNS10X - IRRIGATION,
-182,635 6 REVENUE - ACCT ADJ
100,043 7 INCOME TAX DEFERRAL ADJ
1,570,506 8 DSM REVENUE - IRRIGATION
508 9 BLUE SKY REV - IRRIGATION
11,530 0.1469 1,694,000 10 UNBILLED REVENUE
11
12 OREGON
2,405 1,158,509 13 01APSV0041 - AG PMP SRVC BP
11 27,502 14 01APSV0215 - OR IRRIGATION
641 1,704,875 15 01APSV041L - OR PUMPING SERV
51 27,632 16 01APSV041T - AGR PUMP
2,551 1,136,975 17 01APSV041X - AG PMP SRVC
466 1,753,261 18 01APSV41XL - OR PUMPING SERV
122,085 0.0604 7,372,203 19 01COST0041 -
65,278 0.0513 3,349,349 20 01COST0048 - 01LGSV0048
5,876 0.0497 291,996 21 01COST0215 - OR TOU PILOT
79,925 0.0603 4,822,737 22 01CSTUSB41 - USBR IRRIGATION
1 801 23 01GNSV023T - OR GEN SRV, TOU
5 0.0654 327 24 01HABIT041 - 01APSV0041 AG
3 867,267 25 01LGSB0048 - LG GEN SVC >
2 501,648 26 01LGSV0048 - 1000KW AND OVR
31,089 27 01LNX00103 - LINE EXT 80% G
152 28 01LNX00109 - REF/NREF ADV +
106,400 29 01LNX00110 - REF/NREF ADV +
10,198 30 01LNX00310 - LINE EXTENSION
27,821 31 01LNX00312 - OR IRG LINE EXT
121 32 01LNX00316 - LINE EXTENTION
37 39,821 33 01NMT41135 - NETMTR AG PMP
12 32,947 34 01NMU41135 - OR NET MTR -
30 35 01NMU41215 - IRG TOU PILOT
16 0.0573 917 36 01PTOU0023 - OR GEN SRV, TOU
555 0.0590 32,750 37 01PTOU0041 - 01APSV0041 AG
129 0.0609 7,855 38 01RENEW041 - 01APSV0041 AG
160 0.0621 9,935 39 01STDAY041 - DAILY STANDARD
70 179,813 40 01USBR0215 - OR IRG TOU PILOT
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
9 54,287 1 01USBRGV41 - IRG TOU W/O BPA
481 1,346,750 2 01USBROF41 - KLAMATH BASIN
1,114 1,761,697 3 01USBRON41 - KLAMATH BASIN
26 51,754 4 01VIR41136 - OR VOLUME
104 375,393 5 01VRU41136 - OR VOL INCENTIVE
6 39,412 6 01VRU41215 - OR VOL INCENTIVE
-136,260 7 REVENUE - ACCT ADJ
120 8 OR GAIN ON SALE OF ASSET
896,180 9 INCOME TAX DEFERRAL ADJ
688,938 10 DSM REVENUE - IRRIGATION
467 11 BLUE SKY REV - IRRIGATION
91,380 12 SOLAR FEED-IN REVENUE
8,283 13 COMMUNITY SOLAR REVENUE
274 -4.7774 -1,309,000 14 UNBILLED REVENUE
15
16 UTAH
229,408 3,084 74,387 0.0726 16,653,597 17 08APSV0010 - IRR & SOIL DRA
42,249 305 138,521 0.0680 2,873,885 18 08APSV10NS - IRG SOIL DRAIN
70 1 70,000 0.0734 5,135 19 08CGN10136 - UT IRG AND SOIL
205 20 08LNX00002 - MTHLY 80% GUAR
6,909 21 08LNX00004 - ANNUAL 80%GUAR
3,061 22 08LNX00014 - 80% MIN MNTHLY
129,451 23 08LNX00017 - ADV/REF&80%ANN
21,255 24 08LNX00310 - IRR, 80% ANNUAL
2,677 25 08LNX00311 - LINE EXT 80%
8,874 26 08LNX00312 - UT IRG LINE EXT
300 4 75,000 0.0922 27,648 27 08NMT010NS - IRR & SOIL DRAIN
8,786 69 127,333 0.0791 695,070 28 08NMT10135 - UT IRR_SOIL DRNG
324 29 08TCVLAACN - UTAH TCV LNX
16,494 30 08TCVLNAGN - UTAH LNX ANNUAL
65 31 08TCVLNXGN - TCV LNX - 80%
4,585,854 32 REVENUE - ACCT ADJ
12,335 33 INCOME TAX DEFERRAL ADJ
141,481 34 REVENUE ADJ - DEFERRED NPC
156,407 35 DSM REVENUE - IRRIGATION
36 36 BLUE SKY REV - IRRIGATION
46,435 37 SOLAR FEED-IN REVENUE
-558 0.0645 -36,000 38 UNBILLED REVENUE
39
40
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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
98,521 2,622 37,575 0.0843 8,307,614 2 02APSV0040 - WA AG PMP SRVC
77,758 2,519 30,869 0.0845 6,574,325 3 02APSV040X - WA AG PMP SRVC
2,586 4 02LNX00102 - LINE EXT 80% G
12,344 5 02LNX00103 - LINE EXT 80% G
80 6 02LNX00105 - CNTRCT $ MIN G
258 7 02LNX00109 - REF/NREF ADV +
109,243 8 02LNX00110 - REF/NREF ADV +
1,049 9 02LNX00310 - IRG, 80% ANNUAL
27,160 10 02LNX00312 - WA IRG LINE EXT
221 9 24,556 0.0896 19,808 11 02NMT40135 - WA NET
37 9 4,111 0.2098 7,764 12 02NMX40135 - WA NET
-1,223,594 13 ALT REVENUE PROGRAM ADJ
-266,765 14 REVENUE - ACCT ADJ
6,100 15 REVENUE ADJ - DEFERRED NPC
477,676 16 DSM REVENUE - IRRIGATION
1,765 17 BLUE SKY REV - IRRIGATION
2,647 0.5723 1,515,000 18 UNBILLED REVENUE
19
20 WYOMING
24,237 725 33,430 0.0769 1,864,520 21 05APS00040 - AG PUMPING SVC
2,133 30 71,100 0.0780 166,370 22 05APSNS040 - AG PUMPING SVC -
383 23 05LNX00103 - LINE EXT 80% G
-411 24 05LNX00109 - REF/NREF ADV +
23,647 25 05LNX00110 - REF/NREF ADV +
741 26 05LNX00310 - LINE EXTENSION
4,289 27 05LNX00312 - WY IRG LINE EXT
12 1 12,000 0.1226 1,471 28 09APSNS210 - IRR & SOIL DRA -
-1,393 0.0510 -71,000 29 UNBILLED REVENUE
3,527 30 REVENUE - ACCT ADJ
8,151 31 INCOME TAX DEFERRAL ADJ
-1,785 32 REVENUE ADJ - DEFERRED NPC
18,849 33 DSM REVENUE - IRRIGATION
-8 34 BLUE SKY REV - IRRIGATION
306 8 38,250 0.0796 24,369 35 05APS00040 - AG PUMPING SVC
5,468 36 05LNX00110 - REF/NREF ADV +
214 37 05LNX00312 - WY IRG LINE EXT
552 5 110,400 0.0856 47,242 38 09APSNS210 - IRR & SOIL DRA -
7,094 99 71,657 0.0765 542,915 39 09APSV0210 - IRR & SOIL DRA
23,435 40 DSM REVENUE - IRRIGATION
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
-29 0.0690 -2,000 1 UNBILLED REVENUE
2
-864 3 LESS MULTIPLE BILLINGS
4
1,524,677 23,821 64,006 0.0969 147,748,681 5 TOTAL IRRIGATION SALES
6
7 PUBLIC STREET & HWY LIGHTING
8 CALIFORNIA
1,061 107 9,916 0.1482 157,191 9 06CUSL053E - SPECIAL CUST O
52 20 2,600 0.1755 9,126 10 06CUSL058F - CUST OWND STR
659 77 8,558 0.2863 188,641 11 06SLCO0051 - COMPANY OWNED
1 174 12 06OALT015N - OUTD AR LGT SR
-2,218 13 REVENUE - ACCT ADJ
4,380 14 INCOME TAX DEFERRAL ADJ
6,356 15 DSM REVENUE - PSHL
200 16 OTHER CUST RETAIL REVENUE
28 0.1071 3,000 17 UNBILLED REVENUE
18
19 IDAHO
146 23 6,348 0.1205 17,596 20 07GNSV023S - IDAHO TRAFFIC
170 59 2,881 0.4774 81,152 21 07SLCO0011 - STR LGT CO-OWN
465 56 8,304 0.1100 51,147 22 07SLCU012E - ENGY STR
1,775 182 9,753 0.1990 353,211 23 07SLCU012F - FULL MNT STR
193 16 12,063 0.1455 28,074 24 07SLCU012P - PART MNT STR LGT
-2,563 25 REVENUE - ACCT ADJ
439 26 INCOME TAX DEFERRAL ADJ
12,958 27 DSM REVENUE - PSHL
-37 0.1622 -6,000 28 UNBILLED REVENUE
29
30 OREGON
261 32 8,156 0.1512 39,457 31 01COSL0052 - STR LGT SRVC C
597 0.0631 37,687 32 01COST023F - OR GEN SRV -
476 71 6,704 0.0722 34,358 33 01CUSL0053 - CUS-OWNED MTRD
14 104,181 34 01GNSV023F - OR GEN SRV - FLAT
10,749 231 46,532 0.0725 779,032 35 01CUSL053E - STR LGT SVC
116 9 12,889 0.0946 10,971 36 01CUSL053F - STR LGT SRVC C
4 2 2,000 0.0798 319 37 01CUSL53E2 - STR LGT SVC
18,129 748 24,237 0.2065 3,743,223 38 01HPSV0051 - HI PRESSURE SO
1,192 87 13,701 0.3451 411,401 39 01LEDSL051 - OR LED PILOT
7,138 207 34,483 0.1296 925,343 40 01MVSL0050 - MERC VAPSTR LG
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
41 22 1,864 0.1826 7,488 1 01OALT015N - OUTD AR LGT NR
13 12 1,083 0.1892 2,460 2 01OALTB15N - OR OUTD AR LGT
293 39 7,513 0.2372 69,493 3 01SLCO0051 - OR COMPANY
-20,379 4 REVENUE - ACCT ADJ
884 5 OR GAIN ON SALE OF ASSET
129,215 6 INCOME TAX DEFERRAL ADJ
180,756 7 DSM REVENUE - PSHL
13,875 8 SOLAR FEED-IN REVENUE
878 9 COMMUNITY SOLAR REVENUE
-2,345 0.1565 -367,000 10 UNBILLED REVENUE
11
12 UTAH
54 13 08CFR00012 - STR LGTS (CONV
4,529 14 08CFR00051 - MTH FAC SRVCHG
86 15 08CFR00062 - STREET LIGHTS
426 234 1,821 0.2621 111,661 16 08OALT007N - SECURITY AR LG
1,152 121 9,521 0.0880 101,357 17 08TOSS015F - TRAFFIC SIG NM
13,456 719 18,715 0.3024 4,069,574 18 08SLCO0011 - STR LGT CO-OWN
3,309 1,449 2,284 0.1097 363,144 19 08TOSS0015 - TRAF & AMP;
879 101 8,703 0.0809 71,137 20 08MONL0015 - MTR OUTDONIGHT
2,915 164 17,774 0.1234 359,598 21 08SLCU012P - STR LGT CUST-O
922 63 14,635 0.1341 123,613 22 08SLCU012F - STR LGT CUST-O
40,276 1,022 39,409 0.0638 2,570,104 23 08SLCU012E - DECOR CUST-OWN
469,931 24 REVENUE - ACCT ADJ
36,053 25 REVENUE ADJ - DEFERRED NPC
46,002 26 DSM REVENUE - PSHL
3,698 27 INCOME TAX DEFERRAL ADJ
13,920 28 SOLAR FEED-IN REVENUE
-880 0.1227 -108,000 29 UNBILLED REVENUE
30
31 WASHINGTON
91 32 02CFR00012 - STR LGTS (CONV
11 3 3,667 0.1104 1,214 33 02COSL0052 - WA STR LGT SRV
1,929 119 16,210 0.0718 138,418 34 02CUSL053F - WA STR LGT SRV
723 110 6,573 0.0718 51,929 35 02CUSL053M - WA STR LGT SRV
2,390 221 10,814 0.3014 720,293 36 02SLCO0051 - WA COMPANY
342 3 114,000 0.1317 45,043 37 02MVSL0057 - WA MERC VAPSTR
-37,808 38 REVENUE - ACCT ADJ
14,156 39 DSM REVENUE - PSHL
-975 0.1662 -162,000 40 UNBILLED REVENUE
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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
206 15 13,733 0.1833 37,753 2 05COSL0057 - CO-OWND STR LG
46 10 4,600 0.0557 2,560 3 05CUSL0058 - CUST OWND STR
1,064 33 32,242 0.0553 58,865 4 05CUSL0E58 - WY CUST OWNED
44 3 14,667 0.0680 2,990 5 05CUSL0M58 - CUST OWNED
2,578 78 33,051 0.1819 468,830 6 05HPSV0051 - HI PRESSURE SO
3,413 237 14,401 0.1120 382,262 7 05MVS00053 - MERCURY VAPOR
40 5 8,000 0.1150 4,599 8 05OALT015N - OUTD AR LGT SR
2,967 109 27,220 0.1812 537,502 9 05SLCO0051 - WY STREET LIGHT
5,738 10 REVENUE - ACCT ADJ
-838 11 REVENUE ADJ - DEFERRED NPC
3,828 12 INCOME TAX DEFERRAL ADJ
14,048 13 DSM REVENUE - PSHL
-1,085 0.1465 -159,000 14 UNBILLED REVENUE
2 0.1220 244 15 05HPSV0051 - HI PRESSURE SO
2 1 2,000 0.1245 249 16 05SLCO0051 - WY STREET LIGHT
22 1 22,000 0.1075 2,364 17 09MONL0213 - WY MTR OUTDOOR
1,495 51 29,314 0.2165 323,656 18 09SLCO0211 - STR LGT CO-OWN
34 5 6,800 0.1406 4,782 19 09SLCUP212 - CUST OWNED
49 15 3,267 0.0503 2,466 20 09TOSS0213 - WY TRAFFIC &
12,841 21 DSM REVENUE - PSHL
145 0.2069 30,000 22 UNBILLED REVENUE
23
-3,331 24 LESS MULTIPLE BILLINGS
25
119,073 3,576 33,298 0.1491 17,750,042 26 TOTAL PUBLIC STREET & HWY LT
27
28 FORFEITED DISCOUNTS
29 CALIFORNIA
45,477 30 06LPAY0300 - RES-LATEFEE
11,941 31 06LPAY0300 - COM-LATEFEE
11,434 32 06LPAY0300 - IND-LATEFEE
-219 33 06LPAY0300 - OTHER-LATEFEE
34
35 IDAHO
288,225 36 07LPAY0300 - RES-LATEFEE
35,264 37 07LPAY0300 - COM-LATEFEE
125,314 38 07LPAY0300 - IND-LATEFEE
2,281 39 07LPAY0300 - OTHER-LATEFEE
40
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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
743,584 2 01LPAY0300 - RES-LATEFEE
174,571 3 01LPAY0300 - COM-LATEFEE
42,171 4 01LPAY0300 - IND-LATEFEE
904 5 01LPAY0300 - OTHER-LATEFEE
6
7 UTAH
3,198,100 8 08LPAY0300 - RES-LATEFEE
879,515 9 08LPAY0300 - COM-LATEFEE
319,077 10 08LPAY0300 - IND-LATEFEE
90,938 11 08LPAY0300 - OTHER-LATEFEE
556 12 OTHER FORFEITED DISCOUNTS
13
14 WASHINGTON
145,597 15 02LPAY0300 - RES-LATEFEE
28,783 16 02LPAY0300 - COM-LATEFEE
4,639 17 02LPAY0300 - IND-LATEFEE
460 18 02LPAY0300 - OTHER-LATEFEE
19
20 WYOMING
646,913 21 05LPAY0300 - RES-LATEFEE
156,289 22 05LPAY0300 - COM-LATEFEE
394,709 23 05LPAY0300 - IND-LATEFEE
2,165 24 05LPAY0300 - OTHER-LATEFEE
25
7,348,688 26 TOTAL FORFEITED DISCOUNTS
27
28 MISC SERVICE REVENUE
29 CALIFORNIA
1,706 30 06APSV0020 - AG PMP SRVC
-4 31 06APSV020L - AG PMP SRVC-NO
1,454 32 06CFR00003 - MTH MAINTENANC
4,200 33 06CGENAFCA - CUST
5,905 34 06CONN0300 - CA RECONNECTIO
58,942 35 06FCBUYOUT
15,249 36 06GNSV0025 - CA GEN SRVC
71 37 06GNSV0A32 - GEN SRVC-20 KW
-5 38 06LGSV048T - LRG GEN SERV
25 39 06NBL25136 - CA NET BILL GEN
18 40 06NBLDL136 - NET BILLING LOW
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
525 1 06NEMAGG35 - CALIF NET METER
165 2 06NETBL136 - CA NET BILLING
6,950 3 06NETMT135 - CA RES NET
645 4 06NML20135 - AGRI PUMP-NET
620 5 06NMT20135 - AGRI PUMP-NET
852 6 06NMT25135 - CA GEN SVC NET
184 7 06NMT32135 - CA GEN SVC NET
2,055 8 06NSMTR300 - NON-STND MTR
8,856 9 06RCHK0300 - CA RET CHK CHR
253,085 10 06RESD000D - RES SRVC
27,973 11 06RESD00DN - CA RES SRVC -
240 12 06RESD0DS8 - MULT FAM SBMET
137,972 13 06RESDDL06 - CA LOW INCOME
1,936 14 06RGNSV025 - CA SMALL
60 15 06RNM25135 - CA NET MTR, GEN
150 16 06TAMP0300 - CA TAMP & UNAU
1,360 17 06TEMP0300 - CA TEMP SRVC C
93 18 06XMTRTAMP - TAMPERING -
19
20 IDAHO
-22 21 07APSA010L - IRG & PUMP LG
-33 22 07APSAL10X - IRG & PUMP LG
-19 23 07APSAS10X - IRG & PUMP SM
1,221 24 07CFR00001 - MTH FAC SRVCHG
7,140 25 07CGENAFIDJ - CUSTOMER
7,595 26 07CONN0300 - ID RECONNECTIO
4,376 27 07FCBUYOUT - FAC CHG BUYOUT
-5 28 07GNSV0006 - GEN SRVC-LRG P
-134 29 07GNSV0023 - GEN SRVC-SML P
-10 30 07GNSV006A - GEN SRVC-LRG P
-24 31 07GNSV023A - GEN SRVC-SML P
-72 32 07NETMT135 - ID RES NET
32,820 33 07RCHK0300 - ID RET CHK CHR
-3,378 34 07RESD0001 - RES SRVC
-285 35 07RESD0036 - RES SRVC-OPTIO
-13 36 07RGNSV23A - ID SMALL
32,555 37 07TEMP0014 - TEMP SRVC CONN
785 38 OTHER MISC SVC REVENUE
39
40
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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
-16,927 2 01ADMINFEE - SCH 272 ANNUAL
838 3 01APSV0041 - AG PMP SRVC BP
60 4 01APSV041T - AGR PUMP
1,903 5 01APSV041X - AG PMP SRVC
120,338 6 01CFR00001 - MTH FACILITY S
17,532 7 01CFR00003 - MTH MAINTENANC
25,177 8 01CFR00004 - EMRGNCY ST&BY
37,087 9 01CFR00005 - INTERMTNT SRVC
51,158 10 01CFR00013 - MTH MISC CHRG
7,572 11 01CGENAFOR - CUSTOMER GEN
35,900 12 01CONN0300 - RECONNECTION C
22,702 13 01CONTSERV - OR 3RD PARTY
1,990 14 01ESSC0600 - ESS CHARGES
238,380 15 01FCBUYOUT - FAC CHG BUYOUT
4,190 16 01GNSB0023 - OR GEN SRV, BPA,
33,475 17 01GNSV0023 - OR GEN SRV, < 30
3,069 18 01GNSV0028 - OR GEN SRV > 30
-12,758 19 01GNSV023F - OR GEN SRV - FLAT
116 20 01GNSV023T - OR GEN SRV, TOU
115 21 01LGSV0030 - OR LRG GEN SRV, >
-10 22 01LGSV0048 - 1000KW AND OVR
-5 23 01LNX00109 - REF/NREF ADV +
-4 24 01LNX00110 - REF/NREF ADV +
13,562 25 01NETMT135 - NET METERING
1,175 26 01NMT23135 - OR NET MTR, GEN,
106 27 01NMT28135 - OR NET MTR, GEN,
120 28 01NMTOU135 - TOU NET
28,054 29 01NSMTR300 - OR STANDARD
-4 30 01OALT015N - OUTD AR LGT NR
241,868 31 01RCHK0300 - RETURNED CHECK
606,539 32 01RESD0004 - RES SRVC
1,579 33 01RESD004T - RES TIME OPTION
21,879 34 01RGNSB023 - SMALL GENERAL
180 35 01RGNSB028 - GENERAL SVC > 30
481 36 01RNETM023 - NET METER RES
3,600 37 01TAMP0300 - TAMP & UNAUTH
173,443 38 01TEMP0300 - TEMP SRVC CHRG
-5 39 01USBROF41 - KLAMATH BASIN
235 40 01USBRON41 - KLAMATH BASIN
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
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
/ /2020/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.
812 1 01VIR04136 - OR RES VOLUME
-4 2 01VIR28136 - OR VOLUME
553 3 01XMTRTAMP - TAMPERING -
1,054 4 01XTHEFREV - THEFT OF
-82,418 5 OTHER MISC SVC REVENUE
6
7 UTAH
10,000 8 08APPFEE34 - UT SCH 34
-27 9 08APSV0010 - IRR & SOIL DRA
84,500 10 08CFR00051 - MTH FAC SRVCHG
424 11 08CFR00052 - ANN FAC SVCCHG
13,317 12 08CFR00053 - MTHLY MAINTFEE
4,976 13 08CFR00054 - NRES EMERGENCY
305 14 08CFR00055 - NON RES
2,373 15 08CFR00063 - MTH MISC CHARG
6,660 16 08CFR00064 - ANN MISC CHARG
37,666 17 08CGENFEEN - NRES CSTMR
621,158 18 08CGENFEER - RES CSTMR
-4 19 08CGN06136 - UT GEN SVC
-5 20 08CGN23136 - UTAH NET METER
-783 21 08CGR01136 - UTAH RESIDENTIAL
-4 22 08CGR03136 - UTAH LOW INC RES
78,240 23 08CONN0300 -
117,000 24 08CONTSERV - 3RD PARTY O/S
598,217 25 08FCBUYOUT - FAC CHG BUYOUT
-269 26 08GNSV0006 - GEN SRVC-DISTR
-10 27 08GNSV0008 - UT GEN SVC TOU >
-2,142 28 08GNSV0023 - GEN SRVC-DISTR
-22 29 08GNSV006A - GEN SRVC-ENERG
-13 30 08LNX00014 - 80% MIN MNTHLY
1,155 31 08NCON0300 - UT FEE NRES RE
-1,607 32 08NETMT135 - NET METERING
-20 33 08NMT03135 - LOW INCOME RES
-10 34 08NMT06135 - UT NET METERING
-23 35 08NMT23135 - UT NET MTR, GEN,
849 36 08NSMTR300 - UT NON
-36 37 08OALT007N - SECURITY AR LG
483,749 38 08RCHK0300 - UT RET CHK CHR
1,879,310 39 08RCON0001 - CONNECT FEE
-40,223 40 08RESD0001 - RES SRVC
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
FERC FORM NO. 1 (ED. 12-95) Page 304.26
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2020/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
-4 1 08RESD0002 - RES SRVC-OPTIO
-881 2 08RESD0003 - LIFELINE PRGRM
-22 3 08RESD002E - RES ELCTRC
-15 4 08RGNSV006 - GEN SRVC-RES
-180 5 08RGNSV023 - GEN SRVC-RES
-5 6 08RNM23135 - UT NET MTR, GEN
-4 7 08SLCO0011 - STR LGT CO-OWN
-5 8 08SLCU012E - DECOR CUST-OWN
1,850 9 08SOLRXFEE - SUBSCRI SOLAR
5,000 10 08SPCL0003
118 11 08SSLR0001 - RESIDENTIAL
-9 12 08SSLR0003 - RES LOW INC
975 13 08TAMP0300 - TAMPERING&UNAU
751,950 14 08TEMP0014 - TEMP SRVC CONN
17,310 15 08VISIT300 - UT VISIT SRV CALL
150 16 ENERGY FINANWSER NEW COME
-288,195 17 OTHER MISC SVC REVENUE
18
19 WASHINGTON
-24 20 02APSV0040 - WA AG PMP SRVC
-52 21 02APSV040X - WA AG PMP SRVC
-5 22 02BLSKY01N - BLUESKY ENERGY
1,320 23 02CFR00003 - MTH MAINTENANC
5,892 24 02CFR00004 - EMRGNCY ST&BY
4,302 25 02CFR00005 - INTERMTNT SRVC
30,800 26 02CGENAMWA - CUST GEN APP &
9,100 27 02CONN0300 - WA RECONNECTIO
41,045 28 02FCBUYOUT - FAC CHG BUYOUT
-14 29 02GNSB0024 - WA GEN SRVC DO
-282 30 02GNSV0024 - WA GEN SRVC
-14 31 02LGSV0036 - WA LRG GEN SRV
-103 32 02NETMT135 - WA RES NET
240 33 02NSMTR300 - WA STANDARD
52,896 34 02RCHK0300 - WA RET CHK CHR
-4,228 35 02RESD0016 - WA RES SRVC
-103 36 02RESD0017 - BILL ASSISTANC
-14 37 02RESD0018 - WA 3 PHASE RES
-54 38 02RGNSB024 - WA SMALL
375 39 02TAMP0300 - WA TAMP & UNAU
20,022 40 02TEMP0300 - WA TEMP SRVC C
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
FERC FORM NO. 1 (ED. 12-95) Page 304.27
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2020/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
-15,200 1 OTHER MISC SVC REVENUE
2
3 WYOMING
1,768 4 05CFR00003 - MTH MAINTENANC
18,137 5 05CFR00004 - EMRGNCY ST&BY
9,832 6 05CFR00005 - INTERMTNT SRVC
3,186 7 05CFR00013 - MTH MISC CHRG
28,892 8 05CONN0300 - WY RECONNECTIO
29,071 9 05FCBUYOUT - FAC CHG BUYOUT
-363 10 05GNSV0025 - WY GEN SRVC
-74 11 05GNSV0028 - GEN SVC > 15 KW
-5 12 05LGSV0046 - WY LRG GEN SRV
75 13 05METR0300 - WY FEE MTR TES
-5 14 05NMT25135 - WY NET MTR, GEN,
-5 15 05OALT015R - OUTD AR LGT SR
75,330 16 05RCHK0300 - WY RET CHK CHR
-4,240 17 05RESD0002 - WY RES SRVC
-15 18 05RGNSV025 - WY SMALL
375 19 05TAMP0300
41,820 20 05TEMP0300 - WY TEMP SRVC C
105 21 05XMTRTAMP - TAMPERING -
339 22 09CFR00005 - INTERMTNT SRVC
-501 23 OTHER MISC SVC REVENUE
4,056 24 05CONN0300 - WY RECONNECTIO
4,926 25 05FCBUYOUT - FAC CHG BUYOUT
-91 26 05GNSV0025 - WY GEN SRVC
-19 27 05GNSV0028 - GEN SVC > 15 KW
-4 28 05NETMT135 - EXPERIMENTAL
8,310 29 05RCHK0300 - WY RET CHK CHR
-639 30 05RESD0002 - WY RES SRVC
-14 31 05RGNSV025 - WY SMALL
-5 32 09APSV0210 - IRR & SOIL DRA
5,067 33 09CFR00001 - MTH FAC SRVCHG
3 34 09CFR00014 - YR MISC CHRG
-10 35 09OALT207R - SECURITY AR LG
36
6,952,421 37 TOTAL MISC SERVICE REVENUE
38
39
40
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
FERC FORM NO. 1 (ED. 12-95) Page 304.28
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2020/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 SALES OF WATER & WATER PWR
7,350 2 WYOMING
3 WATER & WATER PWR SALES
4
7,350 5 TOTAL SALES OF WATER &
6
7 RENT FROM ELEC PROPERTIES
8 CALIFORNIA
1,710 9 06CFR00006 - MTH RNTAL CHRG
38,250 10 RENT REVENUE - COMMON
539,947 11 JOINT USE
12
13 IDAHO
778 14 07CFR00009 - YR LSE CHRG-EQ
151 15 07INVCHG00 - INVEST MNT CHG
264 16 07POLE0075 - STEEL POLES US
57,743 17 RENT REVENUE - COMMON
176,325 18 JOINT USE
19
20 OREGON
850,903 21 01CFR00006 - MTH RNTAL CHRG
713,129 22 RENT REVENUE - COMMON
155,967 23 RENT REVENUE - TRANSMISSION
3,353,375 24 MCI FOGWIRE REVENUE
3,569,000 25 JOINT USE
26
27 UTAH
33 28 08CFR00056 - MTH EQUIP RENT
534,384 29 08CFR00058 - MTH EQUIP LEAS
3,509 30 08INVCHG0N - INVEST MNT CHG
192 31 08INVCHG0R - INVEST MNT CHG
50,915 32 08POLE0075 - STEEL POLES US
2,756,605 33 RENT REVENUE - COMMON
500 34 RENT REVENUE - DISTRIBUTION
15,820 35 RENT REVENUE - GENERAL
3,700 36 RENT REVENUE - STEAM
251,313 37 RENT REVENUE - TRANSMISSION
714,340 38 RENT REVENUE - SUBLEASES
2,251,111 39 JOINT USE
40
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
FERC FORM NO. 1 (ED. 12-95) Page 304.29
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
/ /2020/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
8,821 3 02CFR00006 - MTH RNTAL CHRG
562,881 4 RENT REVENUE - COMMON
854,363 5 JOINT USE
6
7 WYOMING
11,524 8 05CFR00001 - MTH FACILITY S
2,482 9 05CFR00006 - MTH RNTAL CHRG
170,285 10 RENT REVENUE - COMMON
2,500 11 RENT REVENUE - STEAM
261,705 12 RENT REVENUE - SUBLEASES
339,992 13 JOINT USE
18,313 14 09POLE0075 - STEEL POLES US
19,621 15 RENT REVENUE - COMMON
16
18,294,555 17 TOTAL RENT FROM ELEC
18
19 OTHER ELECTRIC REVENUE
20 GENERAL
3,222,885 21 M&S INVENTORY REVENUE
-15,271 22 MISC OTHER REVENUE
87,755 23 ELECTRIC INCOME - OTHER
125,002 24 NON-WHEELING SYSTEM REV
3,720,207 25 RENEWABLE ENERGY CREDITS
12,605,274 26 WIND BASED ANCILLARY SVC
27
28 CALIFORNIA
49,984 29 3RD PARTY TRANS O&M
12,764,541 30 CA GHG ALLOW REV AMORT
8,232 31 FISH, WILDLIFE, RECR
32
33 OREGON
138,620 34 3RD PARTY TRANS O&M
551,170 35 CLEAN FUELS PROGRAM
15,465 36 EIM REVENUE
23,787,598 37 FERC TRANSMISSION REFUND
1,125,523 38 SERVICE REQUEST STUDIES
12,574 39 MISC OTHER REVENUE
40
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
FERC FORM NO. 1 (ED. 12-95) Page 304.30
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
/ /2020/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
189,255 2 3RD PARTY TRANS O&M
18,203 3 ELECTRIC INCOME - OTHER
1,960 4 FISH, WILDLIFE, RECR
464,484 5 FLYASH SALES
6
7 WASHINGTON
143,715 8 TIMBER SALES - UTILITY
-52,188 9 WASH COLSTRIP 3
10
11 WYOMING
72,021 12 3RD PARTY TRANS O&M
6 13 ELECTRIC INCOME - OTHER
6,387,102 14 FLYASH SALES
135,367 15 WY REG RECOVERY FEE
16
65,559,484 17 TOTAL OTHER ELEC REVENUE
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
54,559,978 5,037,494,595 1,967,124 27,736 0.0923
211,080 9,078,000 0 0 0.0430
54,348,898 5,028,416,595 1,967,124 27,629 0.0925
FERC FORM NO. 1 (ED. 12-95) Page 304.31
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 / /2020/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 293030T-12RQ 4
Navajo Tribal Util. Auth. (Mexican Hat)000T-6RQ 5
Navajo Tribal Util. Auth. (Red Mesa)112T-6RQ 6
Accrual NANANANARQ 7
8
Non-Requirement Sales: 9
Arizona Electric Power Cooperative, Inc NANANAT-12SF 10
Arizona Public Service Company NANANAT-12SF 11
Arizona Public Service Company NANANAWSPP-QSF 12
Avangrid Renewables, LLC NANANAT-12SF 13
Avangrid Renewables, LLC NANANAT-13SF 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 / /2020/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
118,383 135,011 253,394 6,699 2
64,342 73,390 137,732 3,640 3
8,160,576 4,825,789 -902,421 12,083,944 251,866 4
15,598 16,216 31,814 895 5
166,608 143,380 309,988 9,565 6
51,812 51,812 -5,522 7
8
9
1,541,280 1,541,280 59,670 10
6,678,675 6,678,675 87,316 11
11,200 11,200 1,600 12
9,225,194 9,225,194 173,918 13
1,068 1,068 90 14
FERC FORM NO. 1 (ED. 12-90) Page 311
8,525,507
308,047,406
316,572,913
267,143
4,981,923
5,249,066
-850,609 12,868,684
-132,611,515
-133,462,124
176,382,190
189,250,874
5,193,786
946,299
6,140,085
Name 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 / /2020/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
Basin Electric Power Cooperative, Inc.NANANAT-12SF 3
Black Hills Power, Inc.455450441LF 4
Black Hills Power, Inc.NANANAT-12SF 5
Bonneville Power Administration NANANAT-12SF 6
Bonneville Power Administration NANANAT-13SF 7
Bonneville Power Administration NANANAWSPP-QSF 8
BP Energy Company NANANAT-12AD 9
BP Energy Company NANANAT-12SF 10
British Columbia Hydro and Power NANANAT-13SF 11
Brookfield Renewable Trading NANANAT-12SF 12
California Independent System Operator NANANAT-12SF 13
Calpine Energy Services, 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 / /2020/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.
624,494 624,494 31,552 1
1,559 1,559 63 2
987,556 987,556 16,978 3
5,474,144 946,299 6,420,443 269,092 4
1,689,485 1,689,485 75,850 5
1,431,080 1,431,080 58,139 6
1,895 1,895 125 7
78,800 78,800 2,600 8
11,967 11,967 423 9
3,604,421 3,604,421 126,999 10
918 918 40 11
1,996,206 1,996,206 49,712 12
26,104 26,104 886 13
292,505 292,505 10,428 14
FERC FORM NO. 1 (ED. 12-90) Page 311.1
8,525,507
308,047,406
316,572,913
267,143
4,981,923
5,249,066
-850,609 12,868,684
-132,611,515
-133,462,124
176,382,190
189,250,874
5,193,786
946,299
6,140,085
Name 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 / /2020/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.
Citigroup Energy, Inc.NANANAT-12SF 1
City of Burbank NANANAT-12SF 2
City of Glendale NANANAT-12SF 3
City of Hurricane NANANA560IF 4
City of Redding NANANAT-12SF 5
City of Roseville NANANAT-12SF 6
Clatskanie People's Utility District NANANAT-12SF 7
ConocoPhillips Company NANANAT-12SF 8
CP Energy Marketing (US) Inc.NANANAT-12SF 9
Direct Energy Business Marketing, LLC NANANAT-12SF 10
DTE Energy Trading, Inc.NANANAT-12AD 11
DTE Energy Trading, Inc.NANANAT-12SF 12
EDF Trading North America, LLC NANANAT-12AD 13
EDF Trading North America, LLC NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.2
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 / /2020/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.
53,503,947 53,503,947 1,531,516 1
559,428 559,428 16,058 2
6,146 6,146 279 3
1,948 1,948 41 4
223,600 223,600 10,400 5
1,635,035 1,635,035 64,144 6
15,814 15,814 648 7
4,334,728 4,334,728 143,994 8
2,148 2,148 72 9
6,732 6,732 198 10
30 30 11
16,021,788 16,021,788 433,205 12
5,047 5,047 13
2,956,707 2,956,707 82,425 14
FERC FORM NO. 1 (ED. 12-90) Page 311.2
8,525,507
308,047,406
316,572,913
267,143
4,981,923
5,249,066
-850,609 12,868,684
-132,611,515
-133,462,124
176,382,190
189,250,874
5,193,786
946,299
6,140,085
Name 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 / /2020/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.
EDF Trading North America, LLC NANANAWSPP-QSF 1
El Paso Electric Company NANANAT-12SF 2
Energy Keepers, Inc.NANANAT-12SF 3
Eugene Water & Electric Board NANANAT-12SF 4
Exelon Generation Company, LLC NANANAT-12AD 5
Exelon Generation Company, LLC NANANAT-12SF 6
Gridforce Energy Management, LLC NANANAT-13SF 7
Idaho Power Company NANANAT-12SF 8
Idaho Power Company NANANAT-13SF 9
Idaho Power Company NANANAWSPP-QSF 10
Imperial Irrigation District NANANAT-12SF 11
Los Angeles Dept. of Water and Power NANANAT-12AD 12
Los Angeles Dept. of Water and Power NANANAT-12SF 13
Macquarie Energy LLC NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.3
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
11,040 11,040 184 1
142,256 142,256 3,710 2
24,248 24,248 551 3
164,832 164,832 7,325 4
-65 -65 5
30,852,291 30,852,291 906,978 6
6,301 6,301 278 7
17,521 17,521 979 8
837 837 32 9
404,792 404,792 15,600 10
142,252 142,252 4,797 11
-186 -186 12
245,950 245,950 7,920 13
18,172,176 18,172,176 483,638 14
FERC FORM NO. 1 (ED. 12-90) Page 311.3
8,525,507
308,047,406
316,572,913
267,143
4,981,923
5,249,066
-850,609 12,868,684
-132,611,515
-133,462,124
176,382,190
189,250,874
5,193,786
946,299
6,140,085
Name 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 / /2020/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.
Macquarie Energy LLC NANANAWSPP-QSF 1
Modesto Irrigation District NANANAT-12SF 2
Morgan Stanley Capital Group, Inc.NANANAT-12SF 3
Morgan Stanley Capital Group, Inc.NANANAWSPP-QSF 4
NaturEner Power Watch, LLC NANANAT-13SF 5
Nevada Power Company NANANAWSPP-QSF 6
NextEra Energy Marketing, LLC NANANAT-12SF 7
NorthWestern Energy NANANAT-12SF 8
NorthWestern Energy NANANAT-13SF 9
NorthWestern Energy NANANAWSPP-QSF 10
Portland General Electric Company NANANAT-12SF 11
Portland General Electric Company NANANAT-13SF 12
Powerex Corporation NANANAT-12SF 13
Public Service Company of Colorado NANANAT-12AD 14
FERC FORM NO. 1 (ED. 12-90) Page 310.4
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2020/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.
395,254 395,254 13,116 1
4,000,650 4,000,650 146,329 2
46,704,034 46,704,034 1,762,426 3
143,061 143,061 4,141 4
4,078 4,078 234 5
967,142 967,142 6,020 6
910,924 910,924 31,357 7
4,370 4,370 185 8
4,164 4,164 155 9
251,516 251,516 8,597 10
1,701,896 1,701,896 36,139 11
1,399 1,399 40 12
1,201,500 1,201,500 64,974 13
12,068 12,068 447 14
FERC FORM NO. 1 (ED. 12-90) Page 311.4
8,525,507
308,047,406
316,572,913
267,143
4,981,923
5,249,066
-850,609 12,868,684
-132,611,515
-133,462,124
176,382,190
189,250,874
5,193,786
946,299
6,140,085
Name 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 / /2020/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.
Public Service Company of Colorado NANANAT-12SF 1
Public Service Company of Colorado NANANAT-13SF 2
Public Service Company of New Mexico NANANAT-12SF 3
PUD No. 1 of Chelan County NANANAT-13SF 4
PUD No. 1 of Douglas County NANANAT-12SF 5
PUD No. 1 of Douglas County NANANAT-13SF 6
PUD No. 1 of Snohomish County NANANAT-12SF 7
PUD No. 2 of Grant County NANANAT-13SF 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 / /2020/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.
23,018,936 23,018,936 882,984 1
3,045 3,045 120 2
3,120,130 3,120,130 71,113 3
101 101 12 4
14,000 14,000 375 5
17 17 5 6
51,776 51,776 2,170 7
36 36 8
484,634 484,634 20,566 9
444 444 18 10
902,502 902,502 28,651 11
34,800 34,800 1,200 12
755,333 755,333 28,740 13
478 478 18 14
FERC FORM NO. 1 (ED. 12-90) Page 311.5
8,525,507
308,047,406
316,572,913
267,143
4,981,923
5,249,066
-850,609 12,868,684
-132,611,515
-133,462,124
176,382,190
189,250,874
5,193,786
946,299
6,140,085
Name 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 / /2020/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-12SF 1
Seattle City Light NANANAT-12SF 2
Seattle City Light NANANAT-13SF 3
Sempra Gas & Power Marketing, LLC NANANAT-12SF 4
Shell Energy North America (US), L.P.NANANAT-12AD 5
Shell Energy North America (US), L.P.NANANAT-12SF 6
Shell Energy North America (US), L.P.NANANAWSPP-QSF 7
Sierra Pacific Power Company NANANAT-13SF 8
Southern California Edison Company NANANAT-12SF 9
Tacoma Power NANANAT-12SF 10
Tacoma Power NANANAT-13SF 11
Tenaska Power Services Co.NANANAT-12SF 12
Tenaska Power Services Co.NANANAWSPP-QSF 13
The Energy Authority, Inc.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 / /2020/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.
3,961,116 3,961,116 29,644 1
154,425 154,425 7,275 2
3,366 3,366 116 3
11,547,366 11,547,366 468,646 4
-87,285 -87,285 5
10,204,641 10,204,641 405,204 6
1,678,531 1,678,531 61,564 7
27,499 27,499 578 8
722,100 722,100 22,800 9
19,150 19,150 935 10
38 38 2 11
5,599,611 5,599,611 183,385 12
2,659,150 2,659,150 99,103 13
590,041 590,041 22,110 14
FERC FORM NO. 1 (ED. 12-90) Page 311.6
8,525,507
308,047,406
316,572,913
267,143
4,981,923
5,249,066
-850,609 12,868,684
-132,611,515
-133,462,124
176,382,190
189,250,874
5,193,786
946,299
6,140,085
Name 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 / /2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
TransAlta Energy Marketing (U.S.) Inc.NANANAT-12SF 1
TransCanada Energy Sales Ltd.NANANAT-12SF 2
Tri-State Gen and Trans NANANAT-12SF 3
Tucson Electric Power Company NANANAT-12SF 4
Tucson Electric Power Company NANANAWSPP-QSF 5
Turlock Irrigation District NANANAT-12SF 6
Uniper Global Commodities NANANAT-12SF 7
UNS Electric, Inc.NANANAT-12SF 8
Utah Associated Municipal Power Systems NANANAT-12SF 9
Utah Associated Municipal Power Systems NANANAWSPP-QSF 10
Utah Municipal Power Agency NANANAT-12SF 11
Utah Municipal Power Agency NANANAWSPP-QSF 12
Vitol Inc.NANANAT-12SF 13
Western Area Power Adm CO MO 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 / /2020/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.
2,539,590 2,539,590 103,153 1
12,000 12,000 400 2
118,932 118,932 4,950 3
3,973,500 3,973,500 123,703 4
4,475 4,475 105 5
4,549,685 4,549,685 180,843 6
485,130 485,130 7,000 7
1,179,593 1,179,593 32,583 8
1,988 1,988 71 9
966,158 966,158 34,900 10
205,216 205,216 8,208 11
27,600 27,600 1,083 12
103,656 103,656 4,400 13
3,457,944 3,457,944 98,958 14
FERC FORM NO. 1 (ED. 12-90) Page 311.7
8,525,507
308,047,406
316,572,913
267,143
4,981,923
5,249,066
-850,609 12,868,684
-132,611,515
-133,462,124
176,382,190
189,250,874
5,193,786
946,299
6,140,085
Name 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 / /2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Western Area Power Adm CO MO NANANAT-13SF 1
Western Area Power Adm Lower CO NANANAT-12SF 2
Western Area Power Adm Sierra Nevada NANANAT-12SF 3
Western Area Power Adm Upper CO NANANAT-12SF 4
Transmission Loss Sales Revenue NANANAT-11AD 5
Transmission Loss Sales Revenue NANANAT-11OS 6
Test Generation NANANANA 7
Netting - Bookouts NANANANA 8
Netting - Trading NANANANA 9
Accrual NANANANA 10
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 / /2020/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.
22,050 22,050 527 1
71,400 71,400 1,225 2
502,186 502,186 23,574 3
4,943,241 4,943,241 132,653 4
5,900 5,900 14 5
6,058,472 6,058,472 254,093 6
-2,908,317 -2,908,317 -161,667 7
-134,256,359 -134,256,359 -4,947,283 8
-937,097 -937,097 9
-594,983 -594,983 -13,517 10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 311.8
8,525,507
308,047,406
316,572,913
267,143
4,981,923
5,249,066
-850,609 12,868,684
-132,611,515
-133,462,124
176,382,190
189,250,874
5,193,786
946,299
6,140,085
Schedule Page: 310 Line No.: 4 Column: j
$ (703,781) Load retention
(198,640) Customer service charges related to:
- Schedule 94, Utah Energy Balancing Account
- Schedule 98, Utah Renewable Energy Credits Revenue Adjustment
- Schedule 196, Utah Sustainable Transportation and Energy Plan Cost
Adjustment Pilot Program
- Schedule 197, Utah Federal Tax Act Adjustment
$ (902,421)
Schedule Page: 310 Line No.: 5 Column: a
Complete name is Navajo Tribal Utility Authority (Mexican Hat).
Schedule Page: 310 Line No.: 6 Column: a
Complete name is Navajo Tribal Utility Authority (Red Mesa).
Schedule Page: 310 Line No.: 7 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.: 14 Column: j
Reserve share.
Schedule Page: 310.1 Line No.: 2 Column: j
Reserve share.
Schedule Page: 310.1 Line No.: 4 Column: b
Black Hills Power, Inc. - contract termination date: December 31, 2023.
Schedule Page: 310.1 Line No.: 7 Column: j
Reserve share.
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.: 11 Column: a
Complete name is British Columbia Hydro and Power Authority.
Schedule Page: 310.1 Line No.: 11 Column: j
Reserve share.
Schedule Page: 310.1 Line No.: 12 Column: a
Complete name is Brookfield Renewable Trading and Marketing LP.
Schedule Page: 310.1 Line No.: 13 Column: a
Complete name is California Independent System Operator Corporation.
Schedule Page: 310.2 Line No.: 11 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 310.2 Line No.: 11 Column: j
Settlement adjustment.
Schedule Page: 310.2 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 310.2 Line No.: 13 Column: j
Settlement adjustment.
Schedule Page: 310.3 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 310.3 Line No.: 5 Column: j
Settlement adjustment.
Schedule Page: 310.3 Line No.: 7 Column: j
Reserve share.
Schedule Page: 310.3 Line No.: 9 Column: j
Reserve share.
Schedule Page: 310.3 Line No.: 12 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: 310.3 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 310.3 Line No.: 12 Column: j
Settlement adjustment.
Schedule Page: 310.4 Line No.: 5 Column: j
Reserve share.
Schedule Page: 310.4 Line No.: 6 Column: a
Nevada Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect
wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
company.
Schedule Page: 310.4 Line No.: 9 Column: j
Reserve share.
Schedule Page: 310.4 Line No.: 12 Column: j
Reserve share.
Schedule Page: 310.4 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 310.4 Line No.: 14 Column: j
Settlement adjustment.
Schedule Page: 310.5 Line No.: 2 Column: j
Reserve share.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 310.5 Line No.: 4 Column: a
Complete name is Public Utility District No. 1 of Chelan County.
Schedule Page: 310.5 Line No.: 4 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 5 Column: a
This footnote applies to all occurrences of "PUD No. 1 of Douglas County" on pages
310-311. Complete name is Public Utility District No. 1 of Douglas County.
Schedule Page: 310.5 Line No.: 6 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 7 Column: a
Complete name is Public Utility District No. 1 of Snohomish County.
Schedule Page: 310.5 Line No.: 8 Column: a
Complete name is Public Utility District No. 2 of Grant County.
Schedule Page: 310.5 Line No.: 8 Column: j
Reserve share.
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.: 3 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.: 8 Column: a
Sierra Pacific Power Company is a principal subsidiary of NV Energy, Inc., which is an
indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's
indirect parent company.
Schedule Page: 310.6 Line No.: 8 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 11 Column: j
Reserve share.
Schedule Page: 310.7 Line No.: 3 Column: a
Complete name is Tri-State Generation and Transmission Association, Inc.
Schedule Page: 310.7 Line No.: 7 Column: a
Complete name is Uniper Global Commodities North America 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 310.7 Line No.: 14 Column: a
This footnote applies to all occurrences of "Western Area Power Adm CO MO" on pages
310-311. Complete name is Western Area Power Administration - Colorado Missouri.
Schedule Page: 310.8 Line No.: 1 Column: j
Reserve share.
Schedule Page: 310.8 Line No.: 2 Column: a
Complete name is Western Area Power Administration - Lower Colorado.
Schedule Page: 310.8 Line No.: 3 Column: a
Complete name is Western Area Power Administration - Sierra Nevada.
Schedule Page: 310.8 Line No.: 4 Column: a
Complete name is Western Area Power Administration - Upper Colorado.
Schedule Page: 310.8 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 310.8 Line No.: 5 Column: j
Settlement adjustment.
Schedule Page: 310.8 Line No.: 6 Column: b
Transmission loss sales revenues collected from PacifiCorp's third-party transmission
service customers.
Schedule Page: 310.8 Line No.: 6 Column: j
Transmission loss sales revenues collected from PacifiCorp's third-party transmission
service customers.
Schedule Page: 310.8 Line No.: 7 Column: j
The negative revenue reported on this line reflects test energy generated that was
transferred to Account 107, Construction work in progress for the following wind-powered
generating facilities: Cedar Springs II, Dunlap Ranch 1, Ekola Flats, Marengo, Marengo II,
Pryor Mountain and TB Flats.
Energy generated during testing was delivered to PacifiCorp's electric system for sale as
accounted for under the guidance in 18 C.F.R., Part 101, Electric Plant Instructions
3(18)(a). Test energy is a component of construction work in progress and is reported at
the fair value of the energy delivered.
Schedule Page: 310.8 Line No.: 8 Column: j
Reflects transactions that did not physically settle.
Schedule Page: 310.8 Line No.: 9 Column: j
Reflects transactions that were categorized as trading activities.
Schedule Page: 310.8 Line No.: 10 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
2020/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
/ /2020/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 17,825,121 16,129,284
(501) Fuel 5 757,097,162 681,801,669
(502) Steam Expenses 6 80,249,325 76,240,280
(503) Steam from Other Sources 7 4,836,772 6,509,105
(Less) (504) Steam Transferred-Cr. 8
(505) Electric Expenses 9 1,532,522 1,537,510
(506) Miscellaneous Steam Power Expenses 10 27,042,769 60,013,889
(507) Rents 11 492,466 471,449
(509) Allowances 12
TOTAL Operation (Enter Total of Lines 4 thru 12) 13 889,076,137 842,703,186
Maintenance 14
(510) Maintenance Supervision and Engineering 15 7,293,482 8,206,527
(511) Maintenance of Structures 16 27,614,737 31,374,467
(512) Maintenance of Boiler Plant 17 89,039,742 70,714,383
(513) Maintenance of Electric Plant 18 39,509,020 26,678,095
(514) Maintenance of Miscellaneous Steam Plant 19 10,456,723 9,600,799
TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 173,913,704 146,574,271
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 1,062,989,841 989,277,457
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 9,462,766 9,728,617
(536) Water for Power 45 36,194 155,554
(537) Hydraulic Expenses 46 4,073,308 4,805,592
(538) Electric Expenses 47
(539) Miscellaneous Hydraulic Power Generation Expenses 48 18,007,655 16,386,285
(540) Rents 49 1,696,372 1,781,762
TOTAL Operation (Enter Total of Lines 44 thru 49) 50 33,276,295 32,857,810
C. Hydraulic Power Generation (Continued) 51
Maintenance 52
(541) Mainentance Supervision and Engineering 53 381 394
(542) Maintenance of Structures 54 646,717 696,412
(543) Maintenance of Reservoirs, Dams, and Waterways 55 1,770,311 1,417,042
(544) Maintenance of Electric Plant 56 2,013,122 1,680,183
(545) Maintenance of Miscellaneous Hydraulic Plant 57 4,378,310 37,153,349
TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 8,808,841 40,947,380
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 42,085,136 73,805,190
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
/ /2020/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 62 355,808 350,785
(547) Fuel 63 280,208,082 252,620,782
(548) Generation Expenses 64 17,253,968 19,594,249
(549) Miscellaneous Other Power Generation Expenses 65 7,815,446 8,625,877
(550) Rents 66 3,234,050 5,102,234
TOTAL Operation (Enter Total of lines 62 thru 66) 67 308,867,354 286,293,927
Maintenance 68
(551) Maintenance Supervision and Engineering 69
(552) Maintenance of Structures 70 2,374,413 4,362,235
(553) Maintenance of Generating and Electric Plant 71 12,239,103 16,030,141
(554) Maintenance of Miscellaneous Other Power Generation Plant 72 2,982,747 2,900,157
TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 17,596,263 23,292,533
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 326,463,617 309,586,460
E. Other Power Supply Expenses 75
(555) Purchased Power 76 633,195,384 707,124,705
(556) System Control and Load Dispatching 77 770,619 677,650
(557) Other Expenses 78 44,593,260 41,143,081
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 678,559,263 748,945,436
TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 2,110,097,857 2,121,614,543
2. TRANSMISSION EXPENSES 81
Operation 82
(560) Operation Supervision and Engineering 83 7,360,740 8,359,068
84
(561.1) Load Dispatch-Reliability 85
(561.2) Load Dispatch-Monitor and Operate Transmission System 86 7,813,567 7,719,651
(561.3) Load Dispatch-Transmission Service and Scheduling 87
(561.4) Scheduling, System Control and Dispatch Services 88 1,250,888 1,198,333
(561.5) Reliability, Planning and Standards Development 89 1,962,101 2,375,511
(561.6) Transmission Service Studies 90 82,323 139,663
(561.7) Generation Interconnection Studies 91 504,815 829,798
(561.8) Reliability, Planning and Standards Development Services 92 8,800,994 4,780,276
(562) Station Expenses 93 3,124,100 3,412,615
(563) Overhead Lines Expenses 94 1,089,585 1,038,503
(564) Underground Lines Expenses 95
(565) Transmission of Electricity by Others 96 145,825,268 141,188,225
(566) Miscellaneous Transmission Expenses 97 3,006,329 3,041,748
(567) Rents 98 2,244,063 2,217,342
TOTAL Operation (Enter Total of lines 83 thru 98) 99 183,064,773 176,300,733
Maintenance 100
(568) Maintenance Supervision and Engineering 101 1,304,375 939,674
(569) Maintenance of Structures 102 105,140 90,224
(569.1) Maintenance of Computer Hardware 103
(569.2) Maintenance of Computer Software 104 951,021 838,778
(569.3) Maintenance of Communication Equipment 105 4,732,027 4,700,965
(569.4) Maintenance of Miscellaneous Regional Transmission Plant 106
(570) Maintenance of Station Equipment 107 11,796,851 11,205,549
(571) Maintenance of Overhead Lines 108 16,201,425 16,393,049
(572) Maintenance of Underground Lines 109 57,535 229,967
(573) Maintenance of Miscellaneous Transmission Plant 110 153,479 192,730
TOTAL Maintenance (Total of lines 101 thru 110) 111 35,301,853 34,590,936
TOTAL Transmission Expenses (Total of lines 99 and 111) 112 218,366,626 210,891,669
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
/ /2020/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
3. REGIONAL MARKET EXPENSES 113
Operation 114
(575.1) Operation Supervision 115
(575.2) Day-Ahead and Real-Time Market Facilitation 116
(575.3) Transmission Rights Market Facilitation 117
(575.4) Capacity Market Facilitation 118
(575.5) Ancillary Services Market Facilitation 119
(575.6) Market Monitoring and Compliance 120
(575.7) Market Facilitation, Monitoring and Compliance Services 121
(575.8) Rents 122
Total Operation (Lines 115 thru 122) 123
Maintenance 124
(576.1) Maintenance of Structures and Improvements 125
(576.2) Maintenance of Computer Hardware 126
(576.3) Maintenance of Computer Software 127
(576.4) Maintenance of Communication Equipment 128
(576.5) Maintenance of Miscellaneous Market Operation Plant 129
Total Maintenance (Lines 125 thru 129) 130
TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 131
4. DISTRIBUTION EXPENSES 132
Operation 133
(580) Operation Supervision and Engineering 134 9,520,507 9,310,152
(581) Load Dispatching 135 12,160,239 12,577,822
(582) Station Expenses 136 4,707,948 4,767,498
(583) Overhead Line Expenses 137 9,956,347 9,423,680
(584) Underground Line Expenses 138 621 417
(585) Street Lighting and Signal System Expenses 139 224,138 276,304
(586) Meter Expenses 140 2,526,289 2,835,348
(587) Customer Installations Expenses 141 15,268,629 16,782,395
(588) Miscellaneous Expenses 142 649,377 510,308
(589) Rents 143 2,874,305 3,335,443
TOTAL Operation (Enter Total of lines 134 thru 143) 144 57,888,400 59,819,367
Maintenance 145
(590) Maintenance Supervision and Engineering 146 6,381,190 5,561,808
(591) Maintenance of Structures 147 2,358,542 1,806,802
(592) Maintenance of Station Equipment 148 9,665,348 9,853,811
(593) Maintenance of Overhead Lines 149 88,649,749 98,989,449
(594) Maintenance of Underground Lines 150 27,326,536 27,804,232
(595) Maintenance of Line Transformers 151 1,003,084 1,002,821
(596) Maintenance of Street Lighting and Signal Systems 152 2,503,642 2,100,061
(597) Maintenance of Meters 153 529,287 696,559
(598) Maintenance of Miscellaneous Distribution Plant 154 6,497,561 7,655,412
TOTAL Maintenance (Total of lines 146 thru 154) 155 144,914,939 155,470,955
TOTAL Distribution Expenses (Total of lines 144 and 155) 156 202,803,339 215,290,322
5. CUSTOMER ACCOUNTS EXPENSES 157
Operation 158
(901) Supervision 159 2,282,185 2,273,700
(902) Meter Reading Expenses 160 14,595,821 12,950,694
(903) Customer Records and Collection Expenses 161 46,565,556 42,975,871
(904) Uncollectible Accounts 162 13,068,251 18,138,836
(905) Miscellaneous Customer Accounts Expenses 163 347,870 30,955
TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 76,859,683 76,370,056
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
/ /2020/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 6,737 670
(908) Customer Assistance Expenses 168 95,221,065 104,747,958
(909) Informational and Instructional Expenses 169 6,310,516 5,453,497
(910) Miscellaneous Customer Service and Informational Expenses 170 4,533 1,747
TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 101,542,851 110,203,872
7. SALES EXPENSES 172
Operation 173
(911) Supervision 174
(912) Demonstrating and Selling Expenses 175
(913) Advertising Expenses 176
(916) Miscellaneous Sales Expenses 177
TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 178
8. ADMINISTRATIVE AND GENERAL EXPENSES 179
Operation 180
(920) Administrative and General Salaries 181 76,578,659 79,083,452
(921) Office Supplies and Expenses 182 9,594,354 11,377,137
(Less) (922) Administrative Expenses Transferred-Credit 183 34,578,091 37,851,096
(923) Outside Services Employed 184 22,040,045 20,941,909
(924) Property Insurance 185 14,929,761 16,363,750
(925) Injuries and Damages 186 8,096,669 149,445,957
(926) Employee Pensions and Benefits 187 102,224,372 118,191,960
(927) Franchise Requirements 188
(928) Regulatory Commission Expenses 189 25,605,836 25,986,830
(929) (Less) Duplicate Charges-Cr. 190 130,646,461 122,425,535
(930.1) General Advertising Expenses 191 55,028 14,951
(930.2) Miscellaneous General Expenses 192 2,244,072 2,242,565
(931) Rents 193 2,541,299 3,449,336
TOTAL Operation (Enter Total of lines 181 thru 193) 194 98,685,543 266,821,216
Maintenance 195
(935) Maintenance of General Plant 196 24,451,060 25,099,866
TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 123,136,603 291,921,082
TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 2,832,806,959 3,026,291,544
FERC FORM NO. 1 (ED. 12-93) Page 323
Schedule Page: 320 Line No.: 185 Column: b
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Account
(a)
Ref.
Line No.
(Column)
Amount for
Current Year
(b)
(924) Property Insurance 185(b) $ 16,363,750
Less: Situs property loss reserves, net of reimbursements(1) 11,869,459
Revised (924) Property Insurance $ 4,494,291
(1) To adjust PacifiCorp's formula rate, per FERC Docket No. FA16-4-000 for situs property
loss reserves, net of reimbursements.
Schedule Page: 320 Line No.: 187 Column: b
As required by Commission regulations, the cost of pensions, postretirement other than
pensions and other employee benefits are reported in Account 926, Employee pensions and
benefits. Pensions and benefits expense is associated with labor and generally charged to
operations and maintenance expense and construction work in progress, therefore, pursuant
to FERC Docket No. FA16-4-000, these pensions and benefits are offset in Account 929,
Duplicate charges-credit.
In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No.
ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations should
be excluded from the calculation of the wholesale transmission revenue requirement and
charges under the wholesale formula rates, unless approved by the Commission. During the
year ended December 31, 2020, pension and postretirement regulatory asset amortization was
$4,774,488.
Schedule Page: 320 Line No.: 190 Column: b
Includes the offset of pensions and benefits in Account 926, Employee pensions and
benefits, pursuant to FERC Docket No. FA16-4-000.
Schedule Page: 320 Line No.: 197 Column: b
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Account
(a)
Ref.
Line No.
(Column)
Amount for
Current Year
(b)
TOTAL Administrative & General Expenses 197(b) $ 291,921,082
Less: Situs property loss reserves, net of reimbursements(1) 11,869,459
Less: Pension and postretirement regulatory asset amort. (2) 4,774,488
Revised TOTAL Administrative & General Expenses $ 275,277,135
(1) To adjust Account 924, Property insurance. Refer to footnote on page 320,
line no. 185, column (b)
(2) To adjust Account 926, Employee pensions and benefits. Refer to footnote on page 320,
line no. 187, 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
2020/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 / /2020/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
NANANAAdams Solar Center LLC LU 2
NANANAAirport Solar LLC OS 3
NANANAAmor IX LLC LU 4
NANANAApple, Inc. LU 5
NANANAArizona Electric Power Cooperative,Inc SF 6
NANANAArizona Public Service Company LF 7
NANANAArizona Public Service Company SF 8
NANANAArizona Public Service Company AD 9
NANANAAvangrid Renewables, LLC SF 10
NANANAAvista Corporation SF 11
NANANABasin Electric Power Cooperative, Inc. SF 12
NANANABC Solar, LLC LU 13
NANANABear Creek Solar Center, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
1
1,489,984 31,101 1,521,085 2 22,815
310,849 310,849 3
6,994,636 15,000 7,009,636 4 128,773
387,384 387,384 5 4,869
359,185 359,185 6 8,250
381,642 381,642 7 15,000
1,794,273 1,794,273 8 85,998
7,472 7,472 9 -33,816
36,090,266 720 36,090,986 10 1,121,911
3,287,363 2,114 3,289,477 11 98,718
2,223,236 2,223,236 12 28,283
1,189,326 1,189,326 13 18,153
33,356 33,356 14
FERC FORM NO. 1 (ED. 12-90) Page 327
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/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.
NANANABear Creek Solar Center, LLC LU 1
NANANABeaver City Corporation LF 2
NANANABell Mountain Hydro, LLC LU 3
133Beryl Solar, LLC LU 4
NANANABig Top, LLC LU 5
NANANABiomass One, L.P. LU 6
NANANABirch Power Company, Inc. LU 7
NANANABlack Cap Solar, LLC LU 8
NANANABlack Hills Power, Inc. SF 9
NANANABly Solar Center, LLC LU 10
NANANABly Solar Center, LLC LU 11
NANANABonneville Power Administration LF 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 / /2020/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.
1,573,387 1,573,387 1 24,050
2,416 2,416 2 21
47,923 47,923 3 524
406,013 300,350 706,363 4 5,572
296,409 296,409 5 3,688
14,187,981 2,001,714 16,189,695 6 166,576
699,391 699,391 7 10,925
14,207 14,207 8 567
212,873 212,873 9 5,613
28,301 28,301 10
1,344,186 1,344,186 11 20,557
116,851 116,851 12
16,590,924 13,158 16,604,082 13 476,520
7,913 7,913 14 329
FERC FORM NO. 1 (ED. 12-90) Page 327.1
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/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.
122Box Canyon Limited Partnership LU 1
NANANABP Energy Company SF 2
NANANABP Energy Company AD 3
NANANABrigham Young University - Idaho IU 4
NANANABrookfield Renewable Trading SF 5
133Buckhorn Solar, LLC LU 6
NANANAButter Creek Power, LLC LU 7
NANANAC Drop Hydro, LLC LU 8
NANANACalifornia Independent System Operator SF 9
NANANACalpine Energy Services, L.P. SF 10
NANANACedar Springs III, LLC LU 11
NANANACedar Springs Wind, LLC LU 12
133Cedar Valley Solar, LLC LU 13
333Central Oregon Irrigation District LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.2
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2020/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.
181,692 1,218,560 1,400,252 1 7,816
11,440,453 11,440,453 2 383,237
57,402 57,402 3 1,348
2,213,609 2,213,609 4 39,249
9,135,187 9,135,187 5 249,600
439,732 331,530 771,262 6 6,151
1,001,946 1,001,946 7 12,562
22,961 22,961 8 287
552,095 552,095 9 10,706
1,001,830 1,001,830 10 45,832
790,204 790,204 11 46,700
1,985,451 1,985,451 12 145,532
435,497 309,351 744,848 13 5,739
279,236 3,242,624 3,521,860 14 28,664
FERC FORM NO. 1 (ED. 12-90) Page 327.2
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/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.
NANANACentral Rivers Power, LLC LU 1
NANANAChiloquin Solar LLC LU 2
NANANAChopin Wind, LLC LU 3
NANANACitigroup Energy, Inc. SF 4
NANANACity of Albany LU 5
NANANACity of Anaheim SF 6
NANANACity of Astoria LU 7
NANANACity of Burbank SF 8
NANANACity of Glendale SF 9
NANANACity of Hurricane LF 10
NANANACity of Idaho Falls, Idaho LU 11
NANANACity of Idaho Falls, Idaho AD 12
NANANACity of Portland,Portland Water Bureau LU 13
NANANACity of Preston, Idaho LU 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 / /2020/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.
11,746 11,746 1 484
960,121 960,121 2 20,731
2,046,678 2,046,678 3 35,568
6,575,780 6,575,780 4 236,996
92,200 92,200 5 1,139
1,212 1,212 6 612
1,296 1,296 7 30
187,674 187,674 8 4,588
28,605 28,605 9 890
210,977 210,977 10 3,022
1,738,545 1,738,545 11 51,371
106,462 106,462 12
10,162 10,162 13 128
149,773 149,773 14 2,341
FERC FORM NO. 1 (ED. 12-90) Page 327.3
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANACity of Redding SF 1
NANANACity of Roseville SF 2
NANANAClatskanie People's Utility District SF 3
NANANACommercial Energy Management Inc. LU 4
NANANAConfederate Tribes of Warm Springs LU 5
NANANAConocoPhillips Company SF 6
NANANAConsolidated Irrigation Company LU 7
NANANACottonwood Hydro, LLC IU 8
NANANACove Mountain Solar, LLC LU 9
NANANACove Mountain Solar 2, LLC LU 10
NANANACP Energy Marketing (US) Inc. SF 11
NANANACrook County Solar 1, LLC LU 12
335Deschutes Valley Water District LU 13
88100100Deseret Generation and Transmission LF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.4
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2020/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.
17,600 17,600 1 800
22 22 2 1
2,349 2,349 3 429
124,171 124,171 4 2,152
6,343 6,343 5 280
11,600,716 11,600,716 6 400,039
111,622 111,622 7 1,832
155,399 155,399 8 3,226
984,970 984,970 9 49,063
2,103,281 2,103,281 10 87,463
40,665 40,665 11 783
29,948 29,948 12 1,200
446,879 3,805,342 4,252,221 13 26,154
18,674,781 8,462,467 4,797,303 31,934,551 14 355,418
FERC FORM NO. 1 (ED. 12-90) Page 327.4
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/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.
NANANADorena Hydro, LLC LU 1
000Douglas County LU 2
NANANADouglas County Forest Products LU 3
NANANADraper Irrigation Company IU 4
NANANADry Creek LLC LU 5
NANANADry Creek LLC AD 6
NANANADTE Energy Trading, Inc. SF 7
NANANADTE Energy Trading, Inc.AD 8
NANANAeBay Inc. LU 9
NANANAEDF Trading North America, LLC SF 10
NANANAEDF Trading North America, LLC AD 11
NANANAEl Paso Electric Company SF 12
NANANAElbe Solar Center, LLC LU 13
NANANAElbe Solar Center, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.5
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2020/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.
848,652 848,652 1 10,688
45,413 440,519 485,932 2 2,693
26,858 26,858 3 907
9,422 9,422 4 129
419,242 419,242 5 7,116
-429 -429 6 -15
7,085,025 7,085,025 7 264,774
671 671 8
27,997 27,997 9 340
6,684,857 6,684,857 10 250,859
82 82 11
906,241 906,241 12 57,173
30,955 30,955 13
1,495,664 1,495,664 14 22,933
FERC FORM NO. 1 (ED. 12-90) Page 327.5
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/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.
NANANAEnergy Keepers, Inc. SF 1
NANANAEnterprise Solar, LLC LU 2
NANANAEnterprise Solar, LLC LU 3
NANANAEscalante Solar I, LLC LU 4
NANANAEscalante Solar II, LLC LU 5
NANANAEscalante Solar III, LLC LU 6
NANANAEugene Water & Electric Board SF 7
NANANAEurus Combine Hills I, LLC LU 8
NANANAExelon Generation Company, LLC SF 9
NANANAExxonMobil Production Company LU 10
NANANAFall River Rural Electric Cooperative 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 326.6
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 / /2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
61,750 61,750 1 550
446,225 446,225 2
12,859,503 12,859,503 3 234,941
10,704,693 10,704,693 4 197,911
11,145,597 11,145,597 5 218,379
10,529,326 10,529,326 6 213,740
148,631 148,631 7 7,547
5,933,148 5,933,148 8 121,240
8,714,751 8,714,751 9 286,673
675 675 10 37
1,732,358 1,732,358 11 27,090
356,643 356,643 12 4,492
1,778,498 1,778,498 13 21,272
2,399 2,399 14 44
FERC FORM NO. 1 (ED. 12-90) Page 327.6
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/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
NANANAFour Corners Windfarm, LLC LU 3
NANANAFour Mile Canyon Windfarm, LLC LU 4
NANANAGeorgetown Irrigation Company LU 5
NANANAGrand Valley Power LF 6
NANANAGranite Mountain Solar East, LLC LU 7
NANANAGranite Mountain Solar West, LLC LU 8
133Granite Peak Solar, LLC LU 9
132Greenville Solar, LLC LU 10
NANANAGridforce Energy Management, LLC SF 11
NANANAHammerich 1 & 2 LU 12
NANANAHayward Paul Luckey and Joanne Luckey LU 13
NANANAIdaho Power Company SF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.7
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2020/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.
2,777,511 2,777,511 1 34,343
7,032 7,032 2 -31,943
1,932,721 1,932,721 3 24,316
1,844,173 1,844,173 4 23,133
116,396 116,396 5 1,852
6,937 6,937 6 61
11,202,434 11,202,434 7 215,828
7,173,042 7,173,042 8 131,286
249,228 264,424 513,652 9 6,390
329,335 238,666 568,001 10 4,428
983 983 11 36
27,343 27,343 12 1,157
5,613 5,613 13 206
3,158,120 5,640 3,163,760 14 163,651
FERC FORM NO. 1 (ED. 12-90) Page 327.7
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAIdaho Power Company AD 1
NANANAImperial Irrigation District SF 2
NANANAIron Springs Solar, LLC LU 3
NANANAJ Bar 9 Ranch, Inc. LU 4
NANANAJake Amy LU 5
NANANAJoseph Community Solar, LLC LU 6
NANANAKeeton 1 & 2 LU 7
NANANAKettle Butte Digester LLC LU 8
NANANAKlamath Falls Solar 1, LLC LU 9
NANANAKlamath Falls Solar 2, LLC IU 10
NANANALacomb Irrigation District LU 11
NANANALacomb Irrigation District AD 12
133Laho Solar, LLC LU 13
NANANALatigo Wind Park, 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 / /2020/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.
4,960 4,960 1 -7,110
1,929 1,929 2 70
11,815,831 11,815,831 3 219,758
963 963 4 70
93,523 93,523 5 1,532
13,006 13,006 6 518
8,174 8,174 7 344
68,138 68,138 8 1,392
64,641 64,641 9 984
296,375 296,375 10 6,393
108,253 45,014 153,267 11 5,177
182 182 12
249,996 270,779 520,775 13 6,544
9,931,573 9,931,573 14 163,490
FERC FORM NO. 1 (ED. 12-90) Page 327.8
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/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.
NANANALatigo Wind Park, LLC AD 1
NANANALos Angeles Dept. of Water and Power SF 2
NANANALoyd Fery LU 3
NANANAMacquarie Energy LLC SF 4
NANANAMarsh Valley Hydro Electric Company LU 5
NANANAMeadow Creek Project Company LLC LU 6
NANANAMiddle Fork Irrigation District LU 7
NANANAMiddle Fork Irrigation District AD 8
133Milford Flat Solar, LLC LU 9
NANANAMilford Solar I, LLC LU 10
NANANAMink Creek Hydro LLC LU 11
NANANAMonsanto Company IU 12
NANANAMorgan City Corporation LF 13
NANANAMorgan Stanley Capital Group, Inc. SF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.9
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2020/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.
-1,740 -1,740 1 -1
2,070,570 2,070,570 2 50,008
6,617 6,617 3 257
30,075,816 30,075,816 4 706,433
402,367 402,367 5 6,269
28,633,311 28,633,311 6 360,905
1,810,178 1,810,178 7 23,835
-2 -2 8
249,522 269,929 519,451 9 6,523
1,788,472 1,788,472 10 58,167
599,018 599,018 11 9,598
20,072,359 20,072,359 12
680 680 13 10
21,554,859 21,554,859 14 909,026
FERC FORM NO. 1 (ED. 12-90) Page 327.9
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/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.
NANANAMountain Wind Power, LLC LU 1
NANANAMountain Wind Power II, LLC LU 2
NANANAMyron Jones LU 3
NANANANevada Power Company SF 4
NANANANextEra Energy Marketing, LLC SF 5
00 1Nichols Gap Limited Partnership LU 6
NANANANorthWestern Energy SF 7
NANANANorthWestern Energy AD 8
NANANANorWest Energy 2, LLC IU 9
NANANANorWest Energy 4, LLC IU 10
NANANANorWest Energy 7, LLC IU 11
NANANANorWest Energy 9, LLC IU 12
NANANANucor Corporation IU 13
NANANAOak Lea Digester 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 / /2020/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.
9,600,152 9,600,152 1 171,459
14,220,429 14,220,429 2 219,720
34,842 34,842 3 599
1,131,238 1,131,238 4 26,692
566,923 566,923 5 33,438
32,386 456,659 489,045 6 2,958
30,520 1,790 32,310 7 4,694
17 17 8
1,465,863 1,465,863 9 22,414
773,667 773,667 10 11,814
1,191,126 1,191,126 11 18,173
553,627 553,627 12 11,957
7,201,200 7,201,200 13
67,392 67,392 14 846
FERC FORM NO. 1 (ED. 12-90) Page 327.10
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/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.
NANANAObsidian Finance Group, LLC LU 1
NANANAOld Mill Solar, LLC LU 2
NANANAOR Solar 2, LLC LU 3
NANANAOR Solar 3, LLC LU 4
NANANAOR Solar 5, LLC LU 5
NANANAOR Solar 6, LLC LU 6
NANANAOR Solar 8, LLC LU 7
NANANAOregon Environmental Industries, LLC LU 8
NANANAOregon Solar Incentive LU 9
NANANAOregon State University LU 10
NANANAOregon Trail Windfarm, LLC LU 11
NANANAOSLH, LLC IU 12
NANANAPacific Canyon Windfarm, LLC LU 13
NANANAPavant Solar LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.11
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2020/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.
22,936 22,936 1 921
864,095 864,095 2 11,521
44,936 44,936 3 963
1,173,355 1,173,355 4 25,322
919,677 919,677 5 19,849
1,116,560 1,116,560 6 24,089
1,245,773 1,245,773 7 26,898
1,635,239 1,635,239 8 21,551
248,277 248,277 9 10,294
136 136 10 8
1,977,793 1,977,793 11 24,782
1,110,553 1,110,553 12 23,985
1,513,196 1,513,196 13 18,876
5,297,932 178,983 5,476,915 14 119,323
FERC FORM NO. 1 (ED. 12-90) Page 327.11
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/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.
NANANAPavant Solar II LLC LU 1
NANANAPavant Solar III LLC LU 2
NANANAPioneer Wind Park I, LLC LU 3
NANANAPlatte River Power Authority SF 4
NANANAPortland General Electric Company LF 5
NANANAPortland General Electric Company AD 6
NANANAPortland General Electric Company SF 7
NANANAPower County Wind Park North, LLC LU 8
NANANAPower County Wind Park South, LLC LU 9
NANANAPowerex Corporation SF 10
NANANAProvo City Corporation LF 11
NANANAPublic Service Company of Colorado SF 12
NANANAPublic Service Company of Colorado AD 13
NANANAPublic Service Company of New Mexico 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 / /2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
3,923,343 3,923,343 1 124,414
2,639,628 2,639,628 2 49,993
11,752,419 11,752,419 3 292,559
74,854 74,854 4 2,496
179,245 179,245 5 12,284
29,977 29,977 6
2,324,145 3,204 2,327,349 7 79,086
5,579,429 5,579,429 8 70,303
5,067,175 5,067,175 9 63,049
11,767,789 11,767,789 10 227,785
8,226 8,226 11 100
6,849,867 16,353 6,866,220 12 317,881
4,754 4,754 13 118
367,054 367,054 14 17,960
FERC FORM NO. 1 (ED. 12-90) Page 327.12
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAPUD No. 1 of Chelan County SF 1
NANANAPUD No. 1 of Douglas County SF 2
NANANAPUD No. 1 of Snohomish County SF 3
NANANAPUD No. 2 of Grant County LU 4
NANANAPUD No. 2 of Grant County AD 5
NANANAPUD No. 2 of Grant County SF 6
NANANAPUD No. 2 of Grant County SF 7
NANANAPuget Sound Energy, Inc. SF 8
133Quichapa 1, LLC LU 9
233Quichapa 2, LLC LU 10
133Quichapa 3, LLC LU 11
NANANARainbow Energy Marketing Corporation SF 12
NANANARock River I, LLC LU 13
NANANARoseburg Forest Products Company LU 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 / /2020/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.
2,404,946 519 2,405,465 1 98,428
76,850 271 77,121 2 2,914
820,850 820,850 3 23,995
-887,574 -887,574 4 101,571
-377,611 -377,611 5
26,901,952 26,901,952 6 763,012
966 966 7 42
3,760,097 3,083 3,763,180 8 142,399
244,729 333,069 577,798 9 8,049
244,672 330,885 575,557 10 7,996
244,226 332,351 576,577 11 8,032
799,530 799,530 12 2,815
5,363,677 5,363,677 13 151,175
1,354,981 1,354,981 14 59,327
FERC FORM NO. 1 (ED. 12-90) Page 327.13
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/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.
NANANARoseburg LFG Energy, LLC LU 1
NANANASacramento Municipal Utility District SF 2
NANANASage Solar I LLC LU 3
NANANASage Solar II LLC LU 4
NANANASage Solar III LLC LU 5
NANANASalt River Project SF 6
NANANASand Ranch Windfarm, LLC LU 7
NANANASeattle City Light SF 8
NANANASempra Gas & Power Marketing, LLC SF 9
NANANAShell Energy North America (US), L.P. SF 10
NANANAShiloh Warm Springs Ranch, LLC LU 11
NANANASierra Pacific Power Company SF 12
NANANASimplot Phosphates, LLC LU 13
NANANASolwatt, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.14
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2020/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.
844,107 844,107 1 10,648
7,950 7,950 2 200
2,414,208 2,414,208 3 51,602
2,403,159 2,403,159 4 51,135
2,134,932 2,134,932 5 45,783
2,032,520 2,032,520 6 69,350
1,849,312 1,849,312 7 23,087
816,146 1,235 817,381 8 26,115
1,132,279 1,132,279 9 61,807
12,101,222 12,101,222 10 371,473
48,968 48,968 11 774
6,677 9,787 16,464 12 500
7,784 7,784 13 327
20,367 20,367 14 855
FERC FORM NO. 1 (ED. 12-90) Page 327.14
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANASpanish Fork Wind Park 2, LLC LU 1
000Sprague Hydro LLC LU 2
NANANASt. Anthony Hydro, LLC LU 3
NANANAStahlbush Island Farms, Inc. IU 4
031SunE DB18, LLC LU 5
122SunE DB24, LLC LU 6
233SunE Solar XVII Project 1, LLC LU 7
231SunE Solar XVII Project 2, LLC LU 8
232SunE Solar XVII Project 3, LLC LU 9
NANANASunny Bar Ranch LP LU 10
NANANASunny Bar Ranch LP AD 11
516047Sunnyside Cogeneration Associates LU 12
NANANASwalley Irrigation District LU 13
NANANASweetwater Solar LLC 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 / /2020/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.
2,775,890 2,775,890 1 46,146
44,920 304,838 349,758 2 2,013
302,297 302,297 3 4,747
49,917 -857 49,060 4 2,398
215,313 154,111 369,424 5 2,859
172,217 172,290 344,507 6 4,164
406,325 396,132 802,457 7 7,349
148,899 62,259 211,158 8 1,155
200,175 225,215 425,390 9 5,443
120,038 120,038 10 1,848
12,868 -66 12,802 11 200
24,657,706 24,657,706 12 322,298
178,778 178,778 13 2,209
7,617,135 7,617,135 14 177,948
FERC FORM NO. 1 (ED. 12-90) Page 327.15
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANATacoma Power SF 1
NANANATata Chemicals (Soda Ash) Partners LU 2
NANANATenaska Power Services Co. SF 3
NANANATesoro Refining & Marketing Co LLC LU 4
NANANAThayn Hydro LLC LU 5
NANANAThe Energy Authority, Inc. SF 6
NANANAThree Buttes Windpower, LLC LU 7
NANANAThree Peaks Power, LLC LU 8
NANANAThree Sisters Irrigation District LU 9
NANANAThree Sisters Irrigation District AD 10
NANANAThreemile Canyon Wind I, LLC LU 11
NANANATMF Biofuels, LLC LU 12
NANANATooele Army Depot LU 13
NANANATop of the World Wind Energy 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 / /2020/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.
1,930,971 611 1,931,582 1 38,501
43,280 43,280 2 2,103
1,573,785 1,573,785 3 35,783
202,948 202,948 4 9,743
195,495 195,495 5 4,072
1,419,162 1,419,162 6 32,509
21,836,473 21,836,473 7 342,883
9,797,561 9,797,561 8 229,822
118,738 118,738 9 2,207
2,148 2,148 10 60
2,049,012 2,049,012 11 25,199
2,816,547 2,816,547 12 37,453
42,391 42,391 13 1,538
34,270,423 8,426,687 42,697,110 14 519,249
FERC FORM NO. 1 (ED. 12-90) Page 327.16
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/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.
NANANATransAlta Energy Marketing (U.S.) Inc. SF 1
NANANATransCanada Energy Sales Ltd. SF 2
192525Tri-State Generation and Transmission LF 3
NANANATri-State Generation and Transmission SF 4
NANANATucson Electric Power Company SF 5
NANANATumbleweed Solar LLC LU 6
NANANATurlock Irrigation District SF 7
NANANAUniper Global Commodities SF 8
NANANAU.S. Dept. of the Interior LU 9
NANANAU.S. Air Force at Hill Air Force Base LU 10
NANANAUNS Electric, Inc. SF 11
NANANAUS Magnesium LLC LU 12
NANANAUtah Associated Municipal Power System LF 13
NANANAUtah Municipal Power Agency SF 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 / /2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
10,934,716 10,934,716 1 257,035
247,100 247,100 2 2,750
2,591,250 1,623,679 4,214,929 3 50,191
6,416,580 6,416,580 4 103,821
3,231,967 3,231,967 5 154,435
978,947 978,947 6 21,155
929,980 929,980 7 20,420
236,726 236,726 8 3,000
2,271 2,271 9 34
765,001 765,001 10 13,070
280,327 280,327 11 11,825
4,491,647 4,491,647 12
3,094,589 3,094,589 13 60,752
4,396 4,396 14 109
FERC FORM NO. 1 (ED. 12-90) Page 327.17
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAUtah Red Hills Renewable Park, LLC LU 1
NANANAUtah Retail Solar Customers LU 2
NANANAUtah Retail Solar Customers AD 3
NANANAVitol Inc. SF 4
NANANAWagon Trail, LLC LU 5
NANANAWard Butte Windfarm, LLC LU 6
NANANAWeber County LU 7
NANANAWestern Area Power Administration LF 8
NANANAWestern Area Power Administration SF 9
NANANAWestern Area Power Administration AD 10
NANANAWolverine Creek Energy, LLC LU 11
NANANAWoodline Solar, LLC IU 12
001Yakima-Tieton Irrigation District LU 13
CA 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 / /2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
12,725,414 12,725,414 1 216,965
5,898,055 5,898,055 2 67,045
815 815 3 9
614,524 614,524 4 39,600
610,337 610,337 5 7,618
1,346,880 1,346,880 6 16,885
724 724 7 12
121,017 121,017 8 3,500
227,459 7,863 235,322 9 10,628
-450 -450 10
11,366,071 11,366,071 11 185,417
936,559 936,559 12 20,221
80,217 191,814 272,031 13 6,759
2,509,352 2,509,352 14
FERC FORM NO. 1 (ED. 12-90) Page 327.18
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/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.
Net Power Cost Deferrals 1
Netting - Bookouts 2
Netting - Trading 3
System Deviation 4
Accrual 5
6
Power Exchanges: 7
NANANAArizona Public Service Company 307EX 8
NANANAAvista Corporation 382EX 9
NANANABonneville Power Administration T-BPAEX 10
NANANABonneville Power Administration 237EX 11
NANANABonneville Power Administration 237AD 12
NANANABonneville Power Administration 519EX 13
NANANACalifornia Independent System Operator 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 / /2020/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.
52,596,049 52,596,049 1
-134,256,359 -134,256,359 2 -4,947,283
-937,097 -937,097 3
4 4,900
1,250,737 1,250,737 5
6
7
571,391 564,975 -582,258 -582,258 8
590 9
6,835 248,950 169,821 169,821 10
8,183 4,256 -9,820 -9,820 11
-106 -106 12
42,301 36,512 13
3,285,458 5,123,168 -11,961,501 -11,961,501 14
FERC FORM NO. 1 (ED. 12-90) Page 327.19
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/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.
NANANACalifornia Independent System Operator T-12AD 1
NANANACalifornia Independent System Operator T-11EX 2
NANANACalifornia Independent System Operator T-11AD 3
NANANAEmerald People's Utility District 351EX 4
NANANAIdaho Power Company 708EX 5
NANANAIdaho Power Company T-6EX 6
NANANALos Angeles Dept. of Water and Power OV-1EX 7
NANANALos Angeles Dept. of Water and Power OV-1AD 8
NANANAMilford Wind Corridor Phase I, LLC OV-1EX 9
NANANAMilford Wind Corridor Phase I, LLC OV-1AD 10
NANANAMilford Wind Corridor Phase II, LLC OV-1EX 11
NANANAMilford Wind Corridor Phase II, LLC OV-1AD 12
NANANAPortland General Electric Company T-8EX 13
NANANAPublic Service Company of Colorado 334EX 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 / /2020/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.
-8,949 -8,949 1
-9,461,449 -9,461,449 2
-7,683,214 -7,683,214 3
888 -22,208 -22,208 4
93,373 88,996 5
1,989 1,969 6
3,223 293,399 293,399 7
11,910 11,910 8
2,194 -161,066 -161,066 9
10,000 10,000 10
1,029 -132,333 -132,333 11
-10,210 -10,210 12
3,939 13
1,316,376 1,316,686 5,400,000 5,400,000 14
FERC FORM NO. 1 (ED. 12-90) Page 327.20
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
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 / /2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAPUD No. 1 of Cowlitz County 442EX 1
NANANASeattle City Light 554EX 2
NANANAWestern Area Power Administration LAS-4EX 3
NANANAWestern Area Power Administration LAS-4AD 4
NANANAImbalance Energy Accrual T-11EX 5
NANANAImbalance Energy Accrual T-11AD 6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 326.21
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2020/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.
217,802 193,637 1
381,129 414,378 849,671 849,671 2
127,219 2,082 -437,067 -437,067 3
568 3,194 79,220 79,220 4
328,372 9,579,455 9,579,455 5
9,368 1,245,155 1,245,155 6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 327.21
11,927,865 8,343,705 6,057,325 26,612,653 696,119,123 -15,607,071 707,124,705
Schedule Page: 326 Line No.: 2 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.
Schedule Page: 326 Line No.: 3 Column: b
Reactive supply and voltage control, per FERC Docket ER20-2528, effective September 28,
2020.
Schedule Page: 326 Line No.: 3 Column: l
Reactive supply and voltage control, per FERC Docket ER20-2528, effective September 28,
2020.
Schedule Page: 326 Line No.: 4 Column: l
Liquidated damages.
Schedule Page: 326 Line No.: 7 Column: b
Arizona Public Service Company - Contract terminated on October 31, 2020.
Schedule Page: 326 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326 Line No.: 9 Column: l
Settlement adjustment.
Schedule Page: 326 Line No.: 10 Column: l
Reserve share.
Schedule Page: 326 Line No.: 11 Column: l
Reserve share.
Schedule Page: 326 Line No.: 14 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.
Schedule Page: 326.1 Line No.: 2 Column: b
Beaver City Corporation - contract termination date: 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.: 8 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.: 10 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.
Schedule Page: 326.1 Line No.: 12 Column: b
Bonneville Power Administration - contract termination date: Upon 30 days written notice.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
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.: 5 Column: a
Complete name is Brookfield Renewable Trading and Marketing LP.
Schedule Page: 326.2 Line No.: 9 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: 326.3 Line No.: 10 Column: b
City of Hurricane - contract termination date: August 31, 2022.
Schedule Page: 326.3 Line No.: 11 Column: l
Labor, equipment and administration fees associated with a hydro project in Idaho Falls,
Idaho.
Schedule Page: 326.3 Line No.: 12 Column: b
Settlement adjustment.

Schedule Page: 326.3 Line No.: 12 Column: l
Settlement adjustment.
Schedule Page: 326.4 Line No.: 14 Column: a
Complete name is Deseret Generation and Transmission Co-operative.
Schedule Page: 326.4 Line No.: 14 Column: b
Deseret Generation and Transmission Co-operative - contract termination date: September
30, 2024.

Schedule Page: 326.4 Line No.: 14 Column: l
Reimbursement to counterparty for operations and maintenance costs at a coal fired
generating facility located in Vernal, Utah.
Schedule Page: 326.5 Line No.: 6 Column: b
Settlement adjustment.

Schedule Page: 326.5 Line No.: 6 Column: l
Settlement adjustment.
Schedule Page: 326.5 Line No.: 8 Column: b
Settlement adjustment.

Schedule Page: 326.5 Line No.: 8 Column: l
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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 326.5 Line No.: 11 Column: b
Settlement adjustment.

Schedule Page: 326.5 Line No.: 11 Column: l
Settlement adjustment.
Schedule Page: 326.5 Line No.: 13 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.
Schedule Page: 326.6 Line No.: 2 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.
Schedule Page: 326.6 Line No.: 11 Column: a
Complete name is Fall River Rural Electric Cooperative, Inc.
Schedule Page: 326.6 Line No.: 14 Column: b
Fillmore City Corporation - contract termination date: Under Electric Service Agreement
subject to termination upon timely notification.
Schedule Page: 326.7 Line No.: 2 Column: b
Flathead Electric Cooperative, Inc. - contract termination date: September 30, 2021.

Schedule Page: 326.7 Line No.: 6 Column: b
Grand Valley Power - contract termination date: Under Electric Service Agreement subject
to termination upon timely notification.
Schedule Page: 326.7 Line No.: 11 Column: l
Reserve share.
Schedule Page: 326.7 Line No.: 13 Column: a
Complete name is Hayward Paul Luckey and Joanne Luckey Revocable Trust of 2005.
Schedule Page: 326.7 Line No.: 14 Column: l
Reserve share.
Schedule Page: 326.8 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 326.8 Line No.: 1 Column: l
Settlement adjustment.
Schedule Page: 326.8 Line No.: 11 Column: l
Fixed annual payment.
Schedule Page: 326.8 Line No.: 12 Column: b
Settlement adjustment.

Schedule Page: 326.8 Line No.: 12 Column: l
Settlement adjustment.

Schedule Page: 326.9 Line No.: 1 Column: b
Settlement adjustment.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 326.9 Line No.: 1 Column: l
Settlement adjustment.
Schedule Page: 326.9 Line No.: 2 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.: 8 Column: b
Settlement adjustment.

Schedule Page: 326.9 Line No.: 8 Column: l
Settlement adjustment.
Schedule Page: 326.9 Line No.: 12 Column: l
Compensation for interruptible service and operating reserves.
Schedule Page: 326.9 Line No.: 13 Column: b
Morgan City Corporation - contract termination date: Under Electric Service Agreement
subject to termination upon timely notification.
Schedule Page: 326.10 Line No.: 3 Column: a
Complete name is Myron Jones, Nola Jones, Larry Oja and Christie Oja.
Schedule Page: 326.10 Line No.: 4 Column: a
Nevada Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect
wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
company.
Schedule Page: 326.10 Line No.: 7 Column: l
Reserve share.
Schedule Page: 326.10 Line No.: 8 Column: b
Settlement adjustment.

Schedule Page: 326.10 Line No.: 8 Column: l
Settlement adjustment.
Schedule Page: 326.10 Line No.: 13 Column: l
Ancillary services.
Schedule Page: 326.11 Line No.: 14 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.
Schedule Page: 326.12 Line No.: 5 Column: b
Portland General Electric Company - contract termination date: When the Round Butte
project no longer operates for power production purposes.

Schedule Page: 326.12 Line No.: 5 Column: l
Operations expense plus amortization of unrecovered costs of Cove Project.
Schedule Page: 326.12 Line No.: 6 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 326.12 Line No.: 6 Column: l
Settlement adjustment.
Schedule Page: 326.12 Line No.: 7 Column: l
Reserve share.
Schedule Page: 326.12 Line No.: 11 Column: b
Provo City Corporation - contract termination date: Under Electric Service Agreement
subject to termination upon timely notification.

Schedule Page: 326.12 Line No.: 12 Column: l
Reserve share.
Schedule Page: 326.12 Line No.: 13 Column: b
Settlement adjustment.

Schedule Page: 326.12 Line No.: 13 Column: l
Settlement adjustment.
Schedule Page: 326.13 Line No.: 1 Column: a
Complete name is Public Utility District No. 1 of Chelan County.
Schedule Page: 326.13 Line No.: 1 Column: l
Reserve share.
Schedule Page: 326.13 Line No.: 2 Column: a
Complete name is Public Utility District No. 1 of Douglas County.

Schedule Page: 326.13 Line No.: 2 Column: l
Reserve share.
Schedule Page: 326.13 Line No.: 3 Column: a
Complete name is Public Utility District No. 1 of Snohomish County.
Schedule Page: 326.13 Line No.: 4 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: 326.13 Line No.: 4 Column: l
Operations expense, bond interest, amortization and taxes.
Schedule Page: 326.13 Line No.: 5 Column: b
Settlement adjustment.

Schedule Page: 326.13 Line No.: 5 Column: l
Settlement adjustment.
Schedule Page: 326.13 Line No.: 6 Column: l
2020 Meaningful Priority award to PacifiCorp of generation output from the Priest Rapids
Project from Grant County, consisting of 0.92% generation output from Eugene Water &
Electric Board and 7.5% generation output from Exelon Generation Company, LLC.
Schedule Page: 326.13 Line No.: 7 Column: l
Reserve share.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Schedule Page: 326.13 Line No.: 8 Column: l
Reserve share.
Schedule Page: 326.14 Line No.: 8 Column: l
Reserve share.
Schedule Page: 326.14 Line No.: 12 Column: a
Sierra Pacific Power Company is a principal subsidiary of NV Energy, Inc., which is an
indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's
indirect parent company.
Schedule Page: 326.14 Line No.: 12 Column: l
Reserve share.
Schedule Page: 326.15 Line No.: 4 Column: l
Ancillary services.
Schedule Page: 326.15 Line No.: 11 Column: b
Settlement adjustment.

Schedule Page: 326.15 Line No.: 11 Column: l
Settlement adjustment.
Schedule Page: 326.16 Line No.: 1 Column: l
Reserve share.
Schedule Page: 326.16 Line No.: 10 Column: b
Settlement adjustment.

Schedule Page: 326.16 Line No.: 10 Column: l
Settlement adjustment.
Schedule Page: 326.16 Line No.: 14 Column: l
Non-generation agreement.
Schedule Page: 326.17 Line No.: 3 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.: 3 Column: b
Tri-State Generation and Transmission Association, Inc. - Contract terminated on December
31, 2020.
Schedule Page: 326.17 Line No.: 8 Column: a
Complete name is Uniper Global Commodities North America LLC.
Schedule Page: 326.17 Line No.: 9 Column: a
Complete name is U.S. Department of the Interior, Bureau of Land Management.
Schedule Page: 326.17 Line No.: 12 Column: l
Ancillary services.
Schedule Page: 326.17 Line No.: 13 Column: b
Utah Associated Municipal Power System - contract termination date: March 31, 2022.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
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: b
Western Area Power Administration - contract termination date: May 31, 2022.

Schedule Page: 326.18 Line No.: 9 Column: l
Reserve share.
Schedule Page: 326.18 Line No.: 10 Column: b
Settlement adjustment.

Schedule Page: 326.18 Line No.: 10 Column: l
Settlement adjustment.
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
Represents deferrals and amortization of net power cost, renewable energy credits and
production tax credit regulatory asset mechanisms.
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
Reflects transactions that were categorized as trading activities.
Schedule Page: 326.19 Line No.: 4 Column: g
Adjustment for inadvertent interchange.
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 credit.
Schedule Page: 326.19 Line No.: 10 Column: l
Storage and exchange energy charge.
Schedule Page: 326.19 Line No.: 11 Column: l
Storage and exchange energy credit.
Schedule Page: 326.19 Line No.: 12 Column: b
Settlement adjustment.

Schedule Page: 326.19 Line No.: 12 Column: l
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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
Schedule Page: 326.19 Line No.: 14 Column: l
Energy Imbalance Market ("EIM") participating resource settlements in EIM.
Schedule Page: 326.20 Line No.: 1 Column: b
Settlement adjustment.

Schedule Page: 326.20 Line No.: 1 Column: l
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
Settlement adjustment.
Schedule Page: 326.20 Line No.: 4 Column: l
Exchange energy credit.
Schedule Page: 326.20 Line No.: 7 Column: l
Station service for a third-party wind project.
Schedule Page: 326.20 Line No.: 8 Column: b
Settlement adjustment.

Schedule Page: 326.20 Line No.: 8 Column: l
Settlement adjustment.
Schedule Page: 326.20 Line No.: 9 Column: l
Reimbursement for providing station service to a third-party wind project.
Schedule Page: 326.20 Line No.: 10 Column: b
Settlement adjustment.

Schedule Page: 326.20 Line No.: 10 Column: l
Settlement adjustment.
Schedule Page: 326.20 Line No.: 11 Column: l
Reimbursement for providing station service to a third-party wind project.
Schedule Page: 326.20 Line No.: 12 Column: b
Settlement adjustment.

Schedule Page: 326.20 Line No.: 12 Column: l
Settlement adjustment.
Schedule Page: 326.20 Line No.: 14 Column: l
Exchange energy charge.
Schedule Page: 326.21 Line No.: 1 Column: a
Complete name is Public Utility District No. 1 of Cowlitz County.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
Schedule Page: 326.21 Line No.: 2 Column: l
Exchange energy charge.
Schedule Page: 326.21 Line No.: 3 Column: l
Imbalance energy settlements between PacifiCorp, the transmission provider and third-party
transmission customers.
Schedule Page: 326.21 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 326.21 Line No.: 4 Column: l
Settlement adjustment.
Schedule Page: 326.21 Line No.: 5 Column: l
Imbalance energy settlements between PacifiCorp, the transmission provider and third-party
transmission customers.
Schedule Page: 326.21 Line No.: 6 Column: b
Settlement adjustment.

Schedule Page: 326.21 Line No.: 6 Column: l
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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX / /2020/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.
3 Phase Renewables, LLC Bonneville Power Administration Oregon Direct Access FNO 1
3 Phase Renewables, LLC Bonneville Power Administration Oregon Direct Access AD 2
Airport Solar LLC Airport Solar LLC Portland General Electric Company LFP 3
Arizona Public Service Company Arizona Public Service Company various signatories OS 4
Avangrid Renewables, LLC various signatories various signatories NF 5
Avangrid Renewables, LLC various signatories various signatories AD 6
Avangrid Renewables, LLC various signatories various signatories SFP 7
Avangrid Renewables, LLC various signatories various signatories AD 8
Avangrid Renewables, LLC Avangrid Renewables, LLC OS 9
Avangrid Renewables, LLC Avangrid Renewables, LLC AD 10
Avangrid Renewables, LLC Exxon Mobil Nevada Power Company LFP 11
Avangrid Renewables, LLC Exxon Mobil Nevada Power Company AD 12
Avangrid Renewables, LLC Bonneville Power Administration Oregon Direct Access FNO 13
Avangrid Renewables, LLC Avangrid Renewables, LLC various signatories AD 14
Basin Electric Power Cooperative, Inc. Western Area Power Administration Powder River Energy Corporation FNO 15
Basin Electric Power Cooperative, Inc. Western Area Power Administration Powder River Energy Corporation AD 16
Basin Electric Power Cooperative, Inc. Western Area Power Administration Powder River Energy Corporation NF 17
Basin Electric Power Cooperative, Inc. Western Area Power Administration Powder River Energy Corporation AD 18
Basin Electric Power Cooperative, Inc. Western Area Power Administration Powder River Energy Corporation SFP 19
Black Hills/Colorado Electric Utility Company various signatories various signatories NF 20
Black Hills/Colorado Electric Utility Company various signatories various signatories AD 21
Black Hills/Colorado Electric Utility Company various signatories various signatories SFP 22
Black Hills Corporation PacifiCorp Montana-Dakota Utilities FNO 23
Black Hills Corporation PacifiCorp Montana-Dakota Utilities AD 24
Black Hills Corporation PacifiCorp Black Hills Corporation LFP 25
Black Hills Corporation PacifiCorp Black Hills Corporation AD 26
Black Hills Corporation various signatories various signatories NF 27
Black Hills Corporation various signatories various signatories AD 28
Black Hills Corporation various signatories various signatories SFP 29
Black Hills Power Marketing various signatories various signatories NF 30
Black Hills Power Marketing various signatories various signatories AD 31
Black Hills Power Marketing various signatories various signatories SFP 32
Bonneville Power Administration OS 33
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 34
FERC FORM NO. 1 (ED. 12-90) Page 328
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2020/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
Bonneville Power AdmSA 876 various 1 1,522 1,522 1
Bonneville Power AdmSA 876 various 1 44 44 2
Trona SubstationSA 965 Red Butte/Mona Sub 52 99,052 99,052 3
RS 436 Borah/Brady Sub 4
variousSA 121 various 199,751 199,751 5
variousSA 121 various 18,003 18,003 6
variousSA 122 various 83,526 83,526 7
variousSA 122 various 3,507 3,507 8
SA 476 9
SA 476 10
Trona SubstationSA 895 Red Butte/Mona Sub 31 69,867 69,867 11
Trona SubstationSA 895 Red Butte/Mona Sub 6,306 6,306 12
Ponderosa SubstationSA 742 various 33 264,562 264,562 13
Ponderosa SubstationSA 742 various 33 23,949 23,949 14
Yellowtail SubSA 505 Sheridan Substation 10 64,671 64,671 15
Yellowtail SubSA 505 Sheridan Substation 10 6,974 6,974 16
variousSA 607 various 23,631 23,631 17
variousSA 607 various 2,587 2,587 18
variousSA 606 various 4,523 4,523 19
variousSA 563 various 5 5 20
variousSA 563 various 21
variousSA 562 various 260 260 22
variousSA 347 Sheridan Substation 47 268,629 268,629 23
variousSA 347 Sheridan Substation 44 28,183 28,183 24
variousSA 67 Wyodak Substation 52 77,240 77,240 25
variousSA 67 Wyodak Substation 52 5,623 5,623 26
variousSA 768 various 970 970 27
variousSA 768 various 36 36 28
variousSA 767 various 265 265 29
variousSA 43 various 790 790 30
variousSA 43 various 31
variousSA 714 various 107 107 32
Midpoint SubstationRS 369 Summer Lake Sub 33
variousRS 237 various 356 1,045,889 1,045,889 34
FERC FORM NO. 1 (ED. 12-90) Page 329
5,765 16,923,319 16,816,917
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 / /2020/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.
7,643 8,917 1,274 1
98 98 2
1,555,977 1,992,702 436,725 3
4
1,998,059 78,552 1,919,507 5
133,932 133,932 6
971,043 38,179 932,864 7
51,101 51,101 8
218,916 218,916 9
18,956 18,956 10
933,586 971,746 38,160 11
29,026 29,026 12
994,623 1,554,383 559,760 13
179,686 179,686 14
290,100 335,676 45,576 15
11,917 11,917 16
188,325 7,461 180,864 17
12,817 12,817 18
41,920 1,669 40,251 19
13,190 1,616 11,574 20
130 130 21
3,482 135 3,347 22
1,429,400 1,487,869 58,469 23
33,951 33,951 24
1,555,977 1,619,576 63,599 25
48,376 48,376 26
3,260 128 3,132 27
387 387 28
2,486 99 2,387 29
3,738 149 3,589 30
139 139 31
2,802 109 2,693 32
33
3,594,482 3,626,550 32,068 34
FERC FORM NO. 1 (ED. 12-90) Page 330
75,203,521 111,710,807 16,992,110 19,515,176
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 / /2020/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 Bonneville Power Administration LFP 2
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 3
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative FNO 4
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative AD 5
Bonneville Power Administration Bonneville Power Administration Benton REA FNO 6
Bonneville Power Administration Bonneville Power Administration Benton REA AD 7
Bonneville Power Administration Bonneville Power Administration Umatilla Electric and Columbia FNO 8
Bonneville Power Administration Bonneville Power Administration Umatilla Electric and Columbia AD 9
Bonneville Power Administration U.S. Bureau of Reclamation Bonneville Power Administration LFP 10
Bonneville Power Administration U.S. Bureau of Reclamation Bonneville Power Administration AD 11
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 12
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 13
Bonneville Power Administration Bonneville Power Administration Yakama Power FNO 14
Bonneville Power Administration Bonneville Power Administration Yakama Power AD 15
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO 16
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 17
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO 18
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 19
Bonneville Power Administration various signatories various signatories NF 20
Bonneville Power Administration various signatories various signatories FNO 21
Bonneville Power Administration various signatories various signatories AD 22
Bonneville Power Administration Bonneville Power Administration PUD No. 1 of Clark County FNO 23
Bonneville Power Administration Bonneville Power Administration PUD No. 1 of Clark County AD 24
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO 25
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 26
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO 27
Brookfield Renewable Trading and Marketing various signatories various signatories NF 28
Brookfield Renewable Trading and Marketing various signatories various signatories AD 29
Brookfield Renewable Trading and Marketing various signatories various signatories SFP 30
Calpine Energy Solutions, LLC Bonneville Power Administration Oregon Direct Access FNO 31
Calpine Energy Solutions, LLC Bonneville Power Administration Oregon Direct Access AD 32
City of Roseville City of Roseville City of Roseville LFP 33
City of Roseville City of Roseville City of Roseville AD 34
FERC FORM NO. 1 (ED. 12-90) Page 328.1
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2020/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.
variousRS 237 various 360 110,444 110,444 1
Lost Creek Hydro PltSA 656 Alvey Substation 58 211,091 211,091 2
Lost Creek Hydro PltSA 656 Alvey Substation 58 14,920 14,920 3
Bonneville Power AdmSA 229 Gazley Substation 3 21,787 21,787 4
Bonneville Power AdmSA 229 Gazley Substation 3 2,353 2,353 5
Bonneville Power AdmSA 539 Tieton Substation 1 5,230 5,230 6
Bonneville Power AdmSA 539 Tieton Substation 1 781 781 7
McNary SubstationSA 538 Hinkle Substation 1 708 708 8
McNary SubstationSA 538 Hinkle Substation 1 78 78 9
USBR Green SpringsSA 179 Bonneville Power Adm 19 53,766 53,766 10
USBR Green SpringsSA 179 Bonneville Power Adm 4,006 4,006 11
Malin SubstationRS 368 Malin Substation 650,739 650,739 12
Malin SubstationRS 368 Malin Substation 62,839 62,839 13
Bonneville Power AdmSA 328 6 31,957 31,957 14
Bonneville Power AdmSA 328 5 3,473 3,473 15
Bonneville Power AdmSA 827 Neff Substation 1 673 673 16
Bonneville Power AdmSA 827 Neff Substation 1 88 88 17
Goshen SubstationSA 746 various 209 1,296,983 1,296,983 18
Goshen SubstationSA 746 various 291 166,916 166,916 19
variousSA 44 various 240,859 240,859 20
Goshen SubstationSA 747 various 94 635,122 635,122 21
Goshen SubstationSA 747 various 66 65,048 65,048 22
Cardwell-MerwinSA 735 Chelatchie/View115kV 22 118,020 118,020 23
Cardwell-MerwinSA 735 Chelatchie/View115kV 24 14,654 14,654 24
Goshen SubstationSA 865 various 1 746 746 25
Goshen SubstationSA 865 various 1 91 91 26
Bonneville Power AdmSA 975 various 1 426 426 27
variousSA 941 various 147,967 147,967 28
variousSA 941 various 12,696 12,696 29
variousSA 941 various 366 366 30
Bonneville Power AdmSA 299 various 15 102,193 102,193 31
Bonneville Power AdmSA 299 various 14 9,190 9,190 32
Malin 500 SubstationSA 881 Round Mountain Sub 50 33
Malin 500 SubstationSA 881 Round Mountain Sub 50 34
FERC FORM NO. 1 (ED. 12-90) Page 329.1
5,765 16,923,319 16,816,917
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 / /2020/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.
128,672 128,672 1
1,742,695 1,758,893 16,198 2
49,559 49,559 3
98,890 251,629 152,739 4
15,655 15,655 5
24,437 28,316 3,879 6
1,341 1,341 7
3,715 6,032 2,317 8
-159 -159 9
560,152 566,125 5,973 10
15,918 15,918 11
232,452 232,452 12
21,132 21,132 13
172,413 288,431 116,018 14
12,590 12,590 15
154 379 225 16
479 479 17
6,162,325 7,672,792 1,510,467 18
558,823 558,823 19
1,361,041 53,615 1,307,426 20
2,802,895 3,285,393 482,498 21
57,797 57,797 22
683,398 782,958 99,560 23
37,714 37,714 24
963 1,292 329 25
739 739 26
1,610 1,891 281 27
1,023,597 40,721 982,876 28
155,646 155,646 29
3,099 123 2,976 30
439,677 517,253 77,576 31
22,700 22,700 32
1,489,687 1,525,369 35,682 33
43,648 43,648 34
FERC FORM NO. 1 (ED. 12-90) Page 330.1
75,203,521 111,710,807 16,992,110 19,515,176
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 / /2020/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.
Clatskanie People's Utility District Clatskanie People's Utility Dist Clatskanie People's Utility Dist AD 1
Clatskanie People's Utility District Clatskanie People's Utility Dist Clatskanie People's Utility Dist LFP 2
Clatskanie People's Utility District Clatskanie People's Utility Dist Clatskanie People's Utility Dist AD 3
Clatskanie People's Utility District Clatskanie People's Utility Dist Clatskanie People's Utility Dist LFP 4
Clatskanie People's Utility District Clatskanie People's Utility Dist Clatskanie People's Utility Dist AD 5
ConocoPhillips Company various signatories various signatories AD 6
CP Energy Marketing (US) Inc. various signatories various signatories NF 7
CP Energy Marketing (US) Inc. various signatories various signatories SFP 8
Deseret Gen and Trans Deseret Gen and Trans Deseret Gen and Trans OS 9
Deseret Gen and Trans Deseret Gen and Trans Deseret Gen and Trans AD 10
Deseret Gen and Trans various signatories various signatories NF 11
Deseret Gen and Trans various signatories various signatories AD 12
Eagle Energy Partners I LP various signatories various signatories NF 13
Eagle Energy Partners I LP various signatories various signatories AD 14
Enel Trading North America, LLC various signatories various signatories NF 15
Energy Keepers, Inc. various signatories various signatories NF 16
Energy Keepers, Inc. various signatories various signatories SFP 17
Eugene Water & Electric Board NextEra Energy Resources, LLC PUD No. 2 of Grant County AD 18
Evergreen Biopower LLC NextEra Energy Resources, LLC various signatories LFP 19
Evergreen Biopower LLC NextEra Energy Resources, LLC PUD No. 2 of Grant County AD 20
Exelon Generation Company, LLC Bonneville Power Administration Oregon Direct Access FNO 21
Exelon Generation Company, LLC Bonneville Power Administration Oregon Direct Access AD 22
Exelon Generation Company, LLC various signatories various signatories NF 23
Exelon Generation Company, LLC various signatories various signatories AD 24
Fall River Rural Electric Cooperative, Inc. Marysville Hydro Partners Idaho Power Company OS 25
Fall River Rural Electric Cooperative, Inc. Marysville Hydro Partners Idaho Power Company AD 26
Falls Creek H.P. Limited Partnership Lakeview Airport 10 Portland General Electric Company LFP 27
Garrett Solar LLC Garrett Solar LLC Portland General Electric Company AD 28
Garrett Solar LLC Garrett Solar LLC Portland General Electric Company LFP 29
Guzman Energy LLC various signatories various signatories NF 30
Guzman Energy LLC various signatories various signatories SFP 31
Idaho Power Company Exxon Mobil Nevada Power Company LFP 32
Idaho Power Company Exxon Mobil Nevada Power Company AD 33
Idaho Power Company various signatories various signatories SFP 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 / /2020/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.
Troutdale SubstationSA 800 Troutdale Substation 1
Troutdale SubstationSA 899 Troutdale Substation 14 72,634 72,634 2
Troutdale SubstationSA 899 Troutdale Substation 8,251 8,251 3
Troutdale SubstationSA 901 Troutdale Substation 2 10,853 10,853 4
Troutdale SubstationSA 901 Troutdale Substation 1,233 1,233 5
variousSA 280 various 6
variousSA 968 various 386 386 7
variousSA 967 various 8
variousRS 280 various 140 1,050,616 1,050,616 9
variousRS 280 various 85 86,855 86,855 10
variousSA 156 various 11,360 11,360 11
variousSA 156 various 9,739 9,739 12
variousSA 569 various 2,754 2,754 13
variousSA 569 various 2,105 2,105 14
variousSA 962 various 5,480 5,480 15
variousSA 814 various 9,988 9,988 16
variousSA 815 various 13,256 13,256 17
variousSA 780 various 18
variousSA 874 various 10 42,571 42,571 19
variousSA 874 various 10 4,820 4,820 20
Bonneville Power AdmSA 943 various 1 7,270 7,270 21
Bonneville Power AdmSA 943 various 1 440 440 22
variousSA 759 various 2,193 2,193 23
variousSA 759 various 90 90 24
Targhee SubstationRS 322 Goshen Substation 25
Targhee SubstationRS 322 Goshen Substation 26
Falls Creek H.P.SA 868 Bonneville Power Adm 3 14,126 14,126 27
Wallula SubstationSA 966 Wala-MIDC path 10 300 300 28
Wallula SubstationSA 966 Wala-MIDC path 10 22,713 22,713 29
variousSA 786 various 16,107 16,107 30
variousSA 785 various 11,946 11,946 31
Trona SubstationSA 212 Red Butte/Mona Sub 52 400 400 32
Trona SubstationSA 212 Red Butte/Mona Sub 33
variousSA 726 various 2,807 2,807 34
FERC FORM NO. 1 (ED. 12-90) Page 329.2
5,765 16,923,319 16,816,917
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 / /2020/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.
860 860 1
405,861 422,449 16,588 2
8,640 8,640 3
60,969 63,461 2,492 4
1,291 1,291 5
9 9 6
10,791 429 10,362 7
32 1 31 8
4,284,105 5,748,879 1,464,774 9
181,089 181,089 10
98,167 3,855 94,312 11
68,934 68,934 12
50,532 2,005 48,527 13
13,948 13,948 14
45,668 1,818 43,850 15
84,156 3,355 80,801 16
112,577 4,488 108,089 17
-2,821 -2,821 18
311,195 352,957 41,762 19
12,587 12,587 20
33,175 38,896 5,721 21
1,460 1,460 22
2,115,029 1,961,302 153,727 23
125,529 125,529 24
138,699 138,699 25
12,609 12,609 26
127,488 142,719 15,231 27
33,259 33,259 28
311,195 391,135 79,940 29
139,450 5,551 133,899 30
163,765 6,530 157,235 31
703,037 732,276 29,239 32
-47,861 -47,861 33
21,669 864 20,805 34
FERC FORM NO. 1 (ED. 12-90) Page 330.2
75,203,521 111,710,807 16,992,110 19,515,176
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 / /2020/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.
Idaho Power Company various signatories various signatories NF 1
Macquarie Energy LLC various signatories various signatories NF 2
Macquarie Energy LLC various signatories various signatories AD 3
Macquarie Energy LLC various signatories various signatories SFP 4
MAG Energy Solutions, Inc. various signatories various signatories NF 5
Mercuria Energy America LLC various signatories various signatories NF 6
Moon Lake Electric Association Inc. Moon Lake Electric Association Moon Lake Electric Association OS 7
Moon Lake Electric Association Inc. Moon Lake Electric Association Moon Lake Electric Association AD 8
Morgan Stanley Capital Group, Inc. various signatories various signatories NF 9
Morgan Stanley Capital Group, Inc. various signatories various signatories AD 10
Morgan Stanley Capital Group, Inc. various signatories various signatories SFP 11
Morgan Stanley Capital Group, Inc. various signatories various signatories AD 12
Navajo Tribal Utility Authority Navajo Tribal Utility Authority Navajo Tribal Utility Authority FNO 13
Navajo Tribal Utility Authority Navajo Tribal Utility Authority Navajo Tribal Utility Authority AD 14
NextEra Energy Resources, LLC NextEra Energy Resources, LLC PUD No. 2 of Grant County LFP 15
NextEra Energy Resources, LLC NextEra Energy Resources, LLC PUD No. 2 of Grant County AD 16
NextEra Energy Resources, LLC various signatories various signatories NF 17
NextEra Energy Resources, LLC various signatories various signatories AD 18
NextEra Energy Resources, LLC various signatories various signatories SFP 19
NextEra Energy Resources, LLC various signatories various signatories AD 20
Obsidian Renewables, LLC NextEra Energy Resources, LLC PUD No. 2 of Grant County AD 21
Pacific Gas & Electric Company OS 22
Pacific Gas & Electric Company various signatories various signatories NF 23
Portland General Electric Company OS 24
Portland General Electric Company various signatories various signatories NF 25
Portland General Electric Company various signatories various signatories SFP 26
Portland General Electric Company various signatories various signatories AD 27
Powerex Corporation Bonneville Power Administration CAISO LFP 28
Powerex Corporation Bonneville Power Administration CAISO AD 29
Powerex Corporation Powerex Corporation CAISO LFP 30
Powerex Corporation Powerex Corporation CAISO AD 31
Powerex Corporation Powerex Corporation CAISO LFP 32
Powerex Corporation Powerex Corporation CAISO AD 33
Powerex Corporation Powerex Corporation CAISO LFP 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 / /2020/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.
variousSA 725 various 15,713 15,713 1
variousSA 755 various 28,123 28,123 2
variousSA 755 various 4,104 4,104 3
variousSA 754 various 1,969 1,969 4
variousSA 903 various 3,393 3,393 5
variousSA 998 various 4,739 4,739 6
DuchesneRS 302 Duchesne 18,862 18,862 7
DuchesneRS 302 Duchesne 1,694 1,694 8
variousSA 157 various 502,525 502,525 9
variousSA 157 various 6,044 6,044 10
variousSA 160 various 6,136 6,136 11
variousSA 160 various 72 72 12
Four CornersSA 894 Pinto-Four Corners 1 14,383 14,383 13
Four CornersSA 894 Pinto-Four Corners 1 1,627 1,627 14
Wallula SubstationSA 733 Wala-MIDC path 103 274,929 274,929 15
Wallula SubstationSA 733 Wala-MIDC path 103 7,651 7,651 16
variousSA 236 various 31 31 17
variousSA 236 various 17 17 18
variousSA 237 various 13 13 19
variousSA 237 various 58 58 20
Wallula SubstationSA 880 various 21
Sigurd-Glen CanyonRS 298 Pinto-Four Corners 22
variousSA 338 various 793 793 23
variousRS 137 various 24
variousSA 8 various 25
variousSA 248 various 432 432 26
variousSA 248 various 50 50 27
Bonneville Power AdmSA 169 CRAG View Substation 83 346,233 346,233 28
Bonneville Power AdmSA 169 CRAG View Substation 83 28,141 28,141 29
Malin 500 SubstationSA 700 Round Mountain Sub 100 30
Malin 500 SubstationSA 700 Round Mountain Sub 100 31
Malin 500 SubstationSA 701 Round Mountain Sub 100 32
Malin 500 SubstationSA 701 Round Mountain Sub 100 33
Malin 500 SubstationSA 702 Round Mountain Sub 100 34
FERC FORM NO. 1 (ED. 12-90) Page 329.3
5,765 16,923,319 16,816,917
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 / /2020/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.
166,038 6,621 159,417 1
245,885 9,787 236,098 2
25,545 25,545 3
10,840 418 10,422 4
82,213 3,270 78,943 5
44,508 1,773 42,735 6
26,858 26,858 7
1,605 1,605 8
2,909,020 115,395 2,793,625 9
36,803 36,803 10
45,913 1,827 44,086 11
829 829 12
70,568 82,572 12,004 13
4,580 4,580 14
2,813,691 3,610,742 797,051 15
146,972 146,972 16
34,610 1,590 33,020 17
15,001 15,001 18
163 6 157 19
613 613 20
334,199 334,199 21
41,553 41,553 22
5,153 199 4,954 23
3,314 3,314 24
4 4 25
2,462 95 2,367 26
427 427 27
2,489,565 2,591,324 101,759 28
77,402 77,402 29
2,979,374 3,050,738 71,364 30
88,047 88,047 31
2,979,374 3,050,738 71,364 32
88,047 88,047 33
2,979,377 3,050,741 71,364 34
FERC FORM NO. 1 (ED. 12-90) Page 330.3
75,203,521 111,710,807 16,992,110 19,515,176
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 / /2020/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.
Powerex Corporation Powerex Corporation CAISO AD 1
Powerex Corporation Powerex Corporation CAISO LFP 2
Powerex Corporation Powerex Corporation CAISO AD 3
Powerex Corporation Powerex Corporation CAISO LFP 4
Powerex Corporation Powerex Corporation CAISO AD 5
Powerex Corporation various signatories various signatories NF 6
Powerex Corporation various signatories various signatories AD 7
Powerex Corporation various signatories various signatories SFP 8
PUD No. 1 of Cowlitz County PUD No. 1 of Cowlitz County Bonneville Power Administration OS 9
PUD No. 1 of Cowlitz County PUD No. 1 of Cowlitz County Bonneville Power Administration AD 10
Rainbow Energy Marketing Corporation various signatories various signatories NF 11
Rainbow Energy Marketing Corporation various signatories various signatories AD 12
Rainbow Energy Marketing Corporation various signatories various signatories SFP 13
Sacramento Municipal Utility District Sacramento Municipal Utility Dist Sacramento Municipal Utility Dist LFP 14
Sacramento Municipal Utility District Sacramento Municipal Utility Dist Sacramento Municipal Utility Dist AD 15
Salt River Project Salt River Project Salt River Project LFP 16
Salt River Project Salt River Project Salt River Project AD 17
Salt River Project various signatories various signatories NF 18
Salt River Project various signatories various signatories SFP 19
Shell Energy North America (US), L.P. NextEra Energy Resources, LLC PUD No. 2 of Grant County LFP 20
Shell Energy North America (US), L.P. NextEra Energy Resources, LLC PUD No. 2 of Grant County AD 21
Shell Energy North America (US), L.P. various signatories various signatories NF 22
Shell Energy North America (US), L.P. various signatories various signatories AD 23
Shell Energy North America (US), L.P. various signatories various signatories SFP 24
Shell Energy North America (US), L.P. various signatories various signatories AD 25
Sierra Pacific Power Company OS 26
Sierra Pacific Power Company AD 27
Southern California Edison Company OS 28
Southern California Edison Company various signatories various signatories NF 29
Southern California Edison Company various signatories various signatories AD 30
Southern California Public Power Authority Powerex Corporation Southern California Public Power NF 31
State of South Dakota Western Area Power Administration Black Hills Corporation LFP 32
State of South Dakota Western Area Power Administration Black Hills Corporation AD 33
Tenaska Power Services Co. various signatories various signatories NF 34
FERC FORM NO. 1 (ED. 12-90) Page 328.4
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2020/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
Malin 500 SubstationSA 702 Round Mountain Sub 100 1
Malin 500 SubstationSA 748 Round Mountain Sub 50 2
Malin 500 SubstationSA 748 Round Mountain Sub 50 3
Malin 500 SubstationSA 749 Round Mountain Sub 150 4
Malin 500 SubstationSA 749 Round Mountain Sub 150 5
variousSA 47 various 286,663 286,663 6
variousSA 47 various 13,245 13,245 7
variousSA 151 various 35,813 35,813 8
Swift Unit No. 2RS 234 Woodland Substation 9
Swift Unit No. 2RS 234 Woodland Substation 10
variousSA 316 various 72,287 72,287 11
variousSA 316 various 117 117 12
variousSA 261 various 13
Malin SubstationSA 863 Malin Substation 20 122,840 122,840 14
Malin SubstationSA 863 Malin Substation 20 14,003 14,003 15
Enel Cove FortSA 809 Red Butte Substation 26 124,010 124,010 16
Enel Cove FortSA 809 Red Butte Substation 26 14,892 14,892 17
variousSA 557 various 1,416 1,416 18
variousSA 557 various 795 795 19
Wallula SubstationSA 791 Wala-MIDC path 10,298 10,298 20
Wallula SubstationSA 791 Wala-MIDC path 682 682 21
variousSA 23 various 720,420 720,420 22
variousSA 23 various 35,105 35,105 23
variousSA 162 various 17,892 17,892 24
variousSA 162 various 600 600 25
Sigurd SubstationRS 674 Utah-Nevada Border 26
Sigurd SubstationRS 674 Utah-Nevada Border 27
Sigurd-Glen CanyonRS 298 Pinto-Four Corners 28
variousSA 642 various 292,116 292,116 29
variousSA 642 various 21,878 21,878 30
Tieton SubstationSA 629 various 56 56 31
Yellowtail SubSA 779 Wyodak Substation 4 14,513 14,513 32
Yellowtail SubSA 779 Wyodak Substation 4 1,658 1,658 33
variousSA 125 various 28,615 28,615 34
FERC FORM NO. 1 (ED. 12-90) Page 329.4
5,765 16,923,319 16,816,917
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 / /2020/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.
88,047 88,047 1
1,489,687 1,525,369 35,682 2
44,023 44,023 3
4,469,061 4,576,107 107,046 4
132,070 132,070 5
1,224,962 48,765 1,176,197 6
33,613 33,613 7
225,446 8,989 216,457 8
169,947 169,947 9
15,443 15,443 10
643,603 25,636 617,967 11
766 766 12
131,355 5,235 126,120 13
591,287 615,456 24,169 14
18,360 18,360 15
778,003 809,804 31,801 16
24,188 24,188 17
11,381 453 10,928 18
13,518 539 12,979 19
778,003 1,121,512 343,509 20
90,173 90,173 21
3,855,665 261,579 3,594,086 22
40,868 40,868 23
129,720 5,138 124,582 24
1,775 1,775 25
33,147 33,147 26
3,013 3,013 27
41,553 41,553 28
3,647,411 1,059,991 2,587,420 29
310,228 310,228 30
32,457 32,457 31
124,479 129,566 5,087 32
3,870 3,870 33
368,193 168,716 199,477 34
FERC FORM NO. 1 (ED. 12-90) Page 330.4
75,203,521 111,710,807 16,992,110 19,515,176
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 / /2020/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.
Tenaska Power Services Co. various signatories various signatories AD 1
Tenaska Power Services Co. various signatories various signatories SFP 2
Tenaska Power Services Co. various signatories various signatories AD 3
The Energy Authority, Inc. various signatories various signatories NF 4
The Energy Authority, Inc. various signatories various signatories AD 5
Thermo No. 1 BE-01, LLC Thermo Geothermal Project various signatories LFP 6
Thermo No. 1 BE-01, LLC Thermo Geothermal Project various signatories AD 7
TransAlta Energy Marketing (U.S.) Inc. various signatories various signatories NF 8
TransAlta Energy Marketing (U.S.) Inc. various signatories various signatories AD 9
TransAlta Energy Marketing (U.S.) Inc. various signatories various signatories SFP 10
Tri-State Gen and Trans various signatories Tri-State Gen and Trans FNO 11
Tri-State Gen and Trans various signatories Tri-State Gen and Trans AD 12
Tri-State Gen and Trans various signatories various signatories NF 13
U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation FNO 14
U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation AD 15
U.S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv.OS 16
U.S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv.AD 17
U.S. Bureau of Reclamation Bonneville Power Administration Crooked River Irrigation District OS 18
Utah Associated Municipal Power Utah Associated Municipal Power Utah Associated Municipal Power OS 19
Utah Associated Municipal Power Utah Associated Municipal Power Utah Associated Municipal Power AD 20
Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency OS 21
Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency AD 22
Utah Municipal Power Agency various signatories various signatories NF 23
Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric Company OS 24
Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric Company AD 25
Western Area Power Administration Western Area Power Administration OS 26
Western Area Power Administration Western Area Power Administration AD 27
Western Area Power Administration Western Area Power Administration OS 28
Western Area Power Administration Western Area Power Administration AD 29
Western Area Power Administration Western Area Power Administration various signatories OS 30
Western Area Power Administration Western Area Power Administration Western Area Power Administration FNO 31
Western Area Power Administration Western Area Power Adm CO River Western Area Power Administration AD 32
Western Area Power Adm CO MO Western Area Power Adm CO River various signatories NF 33
Western Area Power Adm CO MO Western Area Power Adm CO River various signatories SFP 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 / /2020/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.
variousSA 125 various 777 777 1
variousSA 126 various 9 9 2
variousSA 126 various 857 857 3
variousSA 310 various 4,961 4,961 4
variousSA 310 various 1,041 1,041 5
South Milford SubSA 568 Mona Substation 11 54,806 54,806 6
South Milford SubSA 568 Mona Substation 11 5,814 5,814 7
variousSA 127 various 114,719 114,719 8
variousSA 127 various 5,728 5,728 9
variousSA 128 various 7,920 7,920 10
Dave Johnston SubSA 628 Thermopolis Sub 17 117,826 117,826 11
Dave Johnston SubSA 628 Thermopolis Sub 17 12,548 12,548 12
variousSA 33 various 3,290 3,290 13
Walla Walla SubSA 506 Burbank Pumps 1 2,473 2,473 14
Walla Walla SubSA 506 Burbank Pumps 1 4 4 15
variousRS 286 various 28,525 28,525 16
variousRS 286 various 897 897 17
Redmond SubstationRS 67 Crooked River Pumps 11,847 11,847 18
variousRS 297 various 547 2,941,617 2,941,617 19
variousRS 297 various 464 257,538 257,538 20
variousRS 637 various 84 639,190 639,190 21
variousRS 637 various 60 39,833 39,833 22
variousSA 20 various 13,092 13,092 23
Pelton ReregulatingRS 591 Round Butte Sub 53,442 53,442 24
Pelton ReregulatingRS 591 Round Butte Sub 6,529 6,529 25
variousRS 262 various 330 1,566,627 1,472,633 26
variousRS 262 various 330 163,190 153,398 27
variousRS 263 various 41,694 39,218 28
variousRS 263 various 4,111 3,866 29
Dave Johnston SubRS 684 various 30
Wyoming DistributionSA 175 Wyoming Distribution 1 9,184 9,184 31
variousSA 175 Wyoming Distribution 1 5 5 32
variousSA 137 various 5,522 5,522 33
variousSA 724 various 700 700 34
FERC FORM NO. 1 (ED. 12-90) Page 329.5
5,765 16,923,319 16,816,917
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 / /2020/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.
21,395 21,395 1
363 14 349 2
6,930 6,930 3
37,279 1,460 35,819 4
6,605 6,605 5
342,330 391,132 48,802 6
14,051 14,051 7
961,077 38,076 923,001 8
39,352 39,352 9
85,481 3,396 82,085 10
532,908 614,179 81,271 11
24,064 24,064 12
21,850 867 20,983 13
8,836 20,182 11,346 14
-490 -490 15
28,525 28,525 16
896 896 17
11,234 11,234 18
16,128,669 18,970,670 2,842,001 19
499,597 499,597 20
2,492,028 2,915,185 423,157 21
39,654 39,654 22
88,987 3,544 85,443 23
109,725 109,725 24
9,975 9,975 25
2,319,902 2,879,622 559,720 26
260,095 260,095 27
26,339 26,339 28
4,047 4,047 29
30
43,321 88,275 44,954 31
-2,489 -2,489 32
44,037 1,752 42,285 33
5,916 235 5,681 34
FERC FORM NO. 1 (ED. 12-90) Page 330.5
75,203,521 111,710,807 16,992,110 19,515,176
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 / /2020/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.
Western Area Power Adm CO River Western Area Power Adm CO River various signatories NF 1
Accrual 2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 328.6
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
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2020/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.
variousSA 132 various 294 294 1
11,088 11,193 2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.6
5,765 16,923,319 16,816,917
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 / /2020/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
2,459 94 2,365 1
-3,780,652 -3,780,652 2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.6
75,203,521 111,710,807 16,992,110 19,515,176
Schedule Page: 328 Line No.: 1 Column: f
This footnote applies to all occurrences of "Bonneville Power Adm" on pages 328-330.
Complete name is Bonneville Power Administration.

Schedule Page: 328 Line No.: 1 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328 Line No.: 2 Column: d
Transmission service under the Open Access Transmission Tariff (1st Revised Service
Agreement 876). 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 Line No.: 2 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328 Line No.: 3 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 965) terminating on December 31, 2024.

Schedule Page: 328 Line No.: 3 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 Line No.: 4 Column: c
This footnote applies to all occurrences of "various signatories" on pages 328-330.
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 4 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 when the Cholla Plant Unit 4 has been retired from service
and all costs of terminating Unit 4 have been paid. The Cholla Plant Unit 4 was retired
from service on December 31, 2020 and final costs to terminate Unit 4 are expected to be
paid by the end of December 31, 2021. See also page 332, Transmission of electricity by
others in this Form No. 1.

Schedule Page: 328 Line No.: 4 Column: f
Glenn Canyon/Four Corners substations
Schedule Page: 328 Line No.: 5 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.: 6 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 6 Column: m
Annual transmission services true-up refunds and/or surcharge.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 328 Line No.: 7 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 8 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 8 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328 Line No.: 9 Column: c
Avangrid Renewables, LLC and Utah Associated Municipal Power Systems

Schedule Page: 328 Line No.: 9 Column: d
Ancillary services under the Open Access Transmission Tariff (1st Revised Service
Agreement 476) in effect until superseded.

Schedule Page: 328 Line No.: 9 Column: f
Long Hollow, WY switching station

Schedule Page: 328 Line No.: 9 Column: g
Long Hollow, WY switching station

Schedule Page: 328 Line No.: 9 Column: m
Operating reserve - spinning reserve service. Operating reserve - supplemental reserve
service.

Schedule Page: 328 Line No.: 10 Column: c
Avangrid Renewables, LLC and Utah Associated Municipal Power Systems

Schedule Page: 328 Line No.: 10 Column: d
Ancillary services under the Open Access Transmission Tariff (1st Revised Service
Agreement 476) in effect until superseded.

Schedule Page: 328 Line No.: 10 Column: f
Long Hollow, WY switching station

Schedule Page: 328 Line No.: 10 Column: g
Long Hollow, WY switching station

Schedule Page: 328 Line No.: 10 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328 Line No.: 11 Column: c
This footnote applies to all occurrences of "Nevada Power Company" on pages 328-330.
Nevada Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect
wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
company.
Schedule Page: 328 Line No.: 11 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 895) terminating on April 30, 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 328 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328 Line No.: 12 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 895) terminating on April 30, 2024.

Schedule Page: 328 Line No.: 12 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328 Line No.: 13 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Generation regulation and frequency
response service. Operating reserve - spinning reserve service. Operating reserve -
supplemental reserve service.

Schedule Page: 328 Line No.: 14 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 742) terminating no earlier than 12-months from notice by the customer.

Schedule Page: 328 Line No.: 14 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328 Line No.: 15 Column: m
Distribution voltage service charge. Primary delivery service. Scheduling, system control
and dispatch service. Reactive supply and voltage control service. Regulation and
frequency response service.

Schedule Page: 328 Line No.: 16 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.: 16 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328 Line No.: 17 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 18 Column: 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
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328 Line No.: 19 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328 Line No.: 20 Column: 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.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 328 Line No.: 20 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.: 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 Line No.: 21 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328 Line No.: 22 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.: 23 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328 Line No.: 24 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 347) terminating on December 31, 2023.

Schedule Page: 328 Line No.: 24 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328 Line No.: 25 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.: 25 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.: 26 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.: 26 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328 Line No.: 27 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

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
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328 Line No.: 29 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 328 Line No.: 30 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 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 Line No.: 31 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328 Line No.: 32 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328 Line No.: 33 Column: b
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of energy.

Schedule Page: 328 Line No.: 33 Column: c
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of energy.

Schedule Page: 328 Line No.: 33 Column: d
Legacy contract executed between PacifiCorp and Bonneville Power Administration concerning
the exchange of transmission services over agreed-upon facilities ("Midpoint-Meridian
Transmission Agreement", Rate Schedule 369). This agreement runs concurrently with the AC
Intertie Agreement (Rate Schedule 368), which terminates when the facilities subject to
that agreement are taken out of service. See also page 332, Transmission of electricity by
others in this Form No. 1.

Schedule Page: 328 Line No.: 34 Column: d
Legacy contract (3rd Revised Rate Schedule 237) executed between PacifiCorp and Bonneville
Power Administration ("BPA") for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Contract subject to terminate 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.: 34 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.

Schedule Page: 328.1 Line No.: 1 Column: d
Legacy contract (3rd Revised Rate Schedule 237) executed between PacifiCorp and Bonneville
Power Administration ("BPA") for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Contract subject to terminate 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: 328.1 Line No.: 1 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.1 Line No.: 2 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised
Service Agreement 656) terminating on August 31, 2030.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Schedule Page: 328.1 Line No.: 2 Column: m
Reactive supply and voltage control service.

Schedule Page: 328.1 Line No.: 3 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.: 3 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.1 Line No.: 4 Column: m
Distribution voltage service charge. Primary delivery service. Regulation and frequency
response service. Reactive supply and voltage control 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 (9th Revised Service Agreement 229) terminating on September 30, 2028.

Schedule Page: 328.1 Line No.: 5 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.1 Line No.: 6 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.: 6 Column: m
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.: 7 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.: 7 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.1 Line No.: 8 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.: 8 Column: m
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.: 9 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.: 9 Column: m
Annual transmission services true-up refunds and/or surcharge.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
Schedule Page: 328.1 Line No.: 10 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.: 10 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.: 10 Column: m
Reactive supply and voltage control service.

Schedule Page: 328.1 Line No.: 11 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.: 11 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.1 Line No.: 12 Column: d
Legacy contract (5th Revised Rate Schedule 368) executed between PacifiCorp and Bonneville
Power Administration for transmission service over agreed-upon facilities and/or subject
to a sole-use or facilities charge. Subject to termination upon mutual agreement.

Schedule Page: 328.1 Line No.: 12 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.: 13 Column: d
Legacy contract (5th Revised Rate Schedule 368) executed between PacifiCorp and Bonneville
Power Administration for transmission service over agreed-upon facilities and/or subject
to a sole-use or facilities charge. Subject to termination upon mutual agreement.

Schedule Page: 328.1 Line No.: 13 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.1 Line No.: 14 Column: g
White Swan/Toppenish substations

Schedule Page: 328.1 Line No.: 14 Column: m
Distribution voltage service charge. Primary delivery service. Regulation and frequency
response service. Reactive supply and voltage control service. Operating reserve -
spinning reserve service. Operating Reserve - supplemental reserve service.

Schedule Page: 328.1 Line No.: 15 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.: 15 Column: g
White Swan/Toppenish substations

Schedule Page: 328.1 Line No.: 15 Column: m
Annual transmission services true-up refunds and/or surcharge.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
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: 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.: 17 Column: m
Annual transmission services true-up refunds and/or surcharge.

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. Generation regulation and frequency
response service. Operating reserve - spinning reserve service. Operating reserve -
supplemental reserve service.

Schedule Page: 328.1 Line No.: 19 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (3rd Revised Service Agreement 746) terminating on June 30, 2028.

Schedule Page: 328.1 Line No.: 19 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.1 Line No.: 20 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 21 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328.1 Line No.: 22 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (3rd Revised Service Agreement 746) terminating on June 30, 2028.

Schedule Page: 328.1 Line No.: 22 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.1 Line No.: 23 Column: c
This footnote applies to all occurrences of “PUD No. 1 of Clark County” on pages 328-330.
Complete name is Public Utility District No. 1 of Clark County.

Schedule Page: 328.1 Line No.: 23 Column: m
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.: 24 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.: 24 Column: m
Annual transmission services true-up refunds and/or surcharge.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
Schedule Page: 328.1 Line No.: 25 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.: 26 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (1st Revised Service Agreement 865) terminating on September 30, 2028.

Schedule Page: 328.1 Line No.: 26 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.1 Line No.: 27 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328.1 Line No.: 28 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.1 Line No.: 29 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.1 Line No.: 29 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.1 Line No.: 30 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 31 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328.1 Line No.: 32 Column: d
Transmission service under the Open Access Transmission Tariff (12th 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.: 32 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.1 Line No.: 33 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 881) terminating on February 28, 2023.

Schedule Page: 328.1 Line No.: 33 Column: m
Scheduling, system control and dispatch service.

Schedule Page: 328.1 Line No.: 34 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 881) terminating on February 28, 2023.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
Schedule Page: 328.1 Line No.: 34 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 Line No.: 1 Column: b
This footnote applies to all occurrences of “Clatskanie People's Utility Dist” on pages
328-330. Complete name is Clatskanie People's Utility District.

Schedule Page: 328.2 Line No.: 1 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 800) which terminated on December 31, 2020.

Schedule Page: 328.2 Line No.: 1 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 Line No.: 2 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 899) terminating on September 30, 2023.

Schedule Page: 328.2 Line No.: 2 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 3 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 899) terminating on September 30, 2023.

Schedule Page: 328.2 Line No.: 3 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 Line No.: 4 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 901) terminating on September 30, 2023.

Schedule Page: 328.2 Line No.: 4 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 5 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 901) terminating on September 30, 2023.

Schedule Page: 328.2 Line No.: 5 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 Line No.: 6 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 6 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 Line No.: 7 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
Schedule Page: 328.2 Line No.: 8 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 9 Column: a
This footnote applies to all occurrences of "Deseret Gen and Trans" on pages 328-330.
Complete name is Deseret Generation and Transmission Co-operative.

Schedule Page: 328.2 Line No.: 9 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: 328.2 Line No.: 9 Column: m
Distribution voltage service charge. Meter interrogation services. 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.: 10 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: 328.2 Line No.: 10 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 12 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 12 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 Line No.: 13 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 14 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 14 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 Line No.: 15 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.11
Schedule Page: 328.2 Line No.: 16 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 17 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 18 Column: c
This footnote applies to all occurrences of "PUD No. 2 of Grant County" on pages 328-330.
Complete name is Public Utility District No. 2 of Grant County.

Schedule Page: 328.2 Line No.: 18 Column: d
Transmission resale service under the Open Access Transmission Tariff (Service Agreement
780) terminating upon mutual consent.

Schedule Page: 328.2 Line No.: 18 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 Line No.: 19 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 874) terminating on December 31, 2032.
Schedule Page: 328.2 Line No.: 19 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.

Schedule Page: 328.2 Line No.: 20 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 874) terminating on December 31, 2032.
Schedule Page: 328.2 Line No.: 20 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 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: 328.2 Line No.: 22 Column: d
Transmission service under the Open Access Transmission Tariff (1st Revised Service
Agreement 943). 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: 328.2 Line No.: 22 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 Line No.: 23 Column: m
Unauthorized use of transmission service. Scheduling, system control and dispatch service.
Reactive supply and voltage control service. Generation regulation and frequency response
service. Operating reserve - spinning reserve service. Operating reserve - supplemental
reserve service.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.12
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
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 Line No.: 25 Column: d
Legacy contract (Rate Schedule 322) executed between PacifiCorp and Fall River Rural
Electric Cooperative, Inc. 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.: 25 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.: 26 Column: d
Legacy contract (Rate Schedule 322) executed between PacifiCorp and Fall River Rural
Electric Cooperative, Inc. 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.: 26 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 Line No.: 27 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised
Service Agreement 868) terminating on December 31, 2034.

Schedule Page: 328.2 Line No.: 27 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 28 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 966) terminating on November 30, 2024.

Schedule Page: 328.2 Line No.: 28 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 Line No.: 29 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 966) terminating on November 30, 2024.

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. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.

Schedule Page: 328.2 Line No.: 30 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 31 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.13
Schedule Page: 328.2 Line No.: 32 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised
Service Agreement 212) terminating on May 31, 2024.

Schedule Page: 328.2 Line No.: 32 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 33 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised
Service Agreement 212) terminating on May 31, 2024.

Schedule Page: 328.2 Line No.: 33 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.2 Line No.: 34 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 1 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 2 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 3 Column: 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
Annual transmission services true-up refunds and/or surcharge.

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: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 6 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 7 Column: d
Legacy contract (3rd Revised Rate Schedule 302) executed between PacifiCorp and Moon Lake
Electric Association Inc. 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 by providing two years written notice.

Schedule Page: 328.3 Line No.: 7 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.14
Schedule Page: 328.3 Line No.: 8 Column: d
Legacy contract (3rd Revised Rate Schedule 302) executed between PacifiCorp and Moon Lake
Electric Association Inc. 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 by providing two years written notice.

Schedule Page: 328.3 Line No.: 8 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.3 Line No.: 9 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 10 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 10 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.3 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 12 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 12 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.3 Line No.: 13 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: 328.3 Line No.: 14 Column: d
Network transmission service under the Open Access Transmission Tariff (Service Agreement
894) terminating on December 31, 2057.

Schedule Page: 328.3 Line No.: 14 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.3 Line No.: 15 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 733) terminating on November 30, 2023.

Schedule Page: 328.3 Line No.: 15 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.: 16 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 733) terminating on November 30, 2023.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.15
Schedule Page: 328.3 Line No.: 16 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.3 Line No.: 17 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 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: 328.3 Line No.: 18 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.3 Line No.: 19 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

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
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.3 Line No.: 21 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 880) terminating on September 30, 2024.

Schedule Page: 328.3 Line No.: 21 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.3 Line No.: 22 Column: b
Operations and maintenance or facility lease services with no receipt or delivery of
energy.

Schedule Page: 328.3 Line No.: 22 Column: c
Operations and maintenance or facility lease services with no receipt or delivery of
energy.

Schedule Page: 328.3 Line No.: 22 Column: d
Legacy contract (Rate Schedule 298) executed between PacifiCorp and Pacific Gas & Electric
Company for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge and phase shifting transformers at Sigurd-Glen Canyon 230kV
transmission line and Pinto-Four Corners 345kV transmission line, which terminated on
February 12, 2020.

Schedule Page: 328.3 Line No.: 22 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.: 23 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.16
Schedule Page: 328.3 Line No.: 24 Column: b
Operations and maintenance or facility lease services with no receipt or delivery of
energy.

Schedule Page: 328.3 Line No.: 24 Column: c
Operations and maintenance or facility lease services with no receipt or delivery of
energy.

Schedule Page: 328.3 Line No.: 24 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 allows for
automatic one-year renewals after initial one-year term.

Schedule Page: 328.3 Line No.: 24 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.: 26 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.

Schedule Page: 328.3 Line No.: 27 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 27 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.3 Line No.: 28 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.: 28 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised
Service Agreement 169) terminating on October 31, 2025.

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 (9th Revised
Service Agreement 169) terminating on October 31, 2025.

Schedule Page: 328.3 Line No.: 29 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.3 Line No.: 30 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 700) terminating on March 31, 2022.

Schedule Page: 328.3 Line No.: 30 Column: m
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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.17
Schedule Page: 328.3 Line No.: 31 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 700) terminating on March 31, 2022.

Schedule Page: 328.3 Line No.: 31 Column: m
Annual transmission services true-up refunds and/or surcharge.
Schedule Page: 328.3 Line No.: 32 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 701) terminating on March 31, 2022.

Schedule Page: 328.3 Line No.: 32 Column: m
Scheduling, system control and dispatch service.

Schedule Page: 328.3 Line No.: 33 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 701) terminating on March 31, 2022.

Schedule Page: 328.3 Line No.: 33 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.3 Line No.: 34 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 702) terminating on March 31, 2022.

Schedule Page: 328.3 Line No.: 34 Column: m
Scheduling, system control and dispatch service.

Schedule Page: 328.4 Line No.: 1 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 702) terminating on March 31, 2022.

Schedule Page: 328.4 Line No.: 1 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.4 Line No.: 2 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 748) terminating on December 31, 2023.

Schedule Page: 328.4 Line No.: 2 Column: m
Scheduling, system control and dispatch service.

Schedule Page: 328.4 Line No.: 3 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 748) terminating on December 31, 2023.

Schedule Page: 328.4 Line No.: 3 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.4 Line No.: 4 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 749) terminating on December 31, 2023.

Schedule Page: 328.4 Line No.: 4 Column: m
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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.18
Schedule Page: 328.4 Line No.: 5 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 749) terminating on December 31, 2023.

Schedule Page: 328.4 Line No.: 5 Column: m
Annual transmission services true-up refunds and/or surcharge.
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
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 7 Column: m
Annual transmission services true-up refunds and/or surcharge.

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: a
This footnote applies to all occurrences of "PUD No. 1 of Cowlitz County" on pages
328-330. Complete name is Public Utility District No. 1 of Cowlitz County.

Schedule Page: 328.4 Line No.: 9 Column: d
Legacy contract (Rate Schedule 234) providing for transmission and operation of the
hydroelectric plant - Swift 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 Plant, No. 2.

Schedule Page: 328.4 Line No.: 9 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.

Schedule Page: 328.4 Line No.: 10 Column: d
Legacy contract (Rate Schedule 234) providing for transmission and operation of the
hydroelectric plant - Swift 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 Plant, No. 2.
Schedule Page: 328.4 Line No.: 10 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.4 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.19
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
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.4 Line No.: 13 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 14 Column: b
This footnote applies to all occurrences of "Sacramento Municipal Utility Dist" on pages
328-330. Complete name is Sacramento Municipal Utility District.

Schedule Page: 328.4 Line No.: 14 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 863) terminating on June 30, 2022.

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: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 863) terminating on June 30, 2022.

Schedule Page: 328.4 Line No.: 15 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.4 Line No.: 16 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Service
Agreement 809) terminating on October 31, 2025.
Schedule Page: 328.4 Line No.: 16 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 17 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Service
Agreement 809) terminating on October 31, 2025.

Schedule Page: 328.4 Line No.: 17 Column: m
Annual transmission services true-up refunds and/or surcharge.

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: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 20 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised
Service Agreement 791) terminating upon written notification.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.20
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: d
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised
Service Agreement 791) terminating upon written notification.
Schedule Page: 328.4 Line No.: 21 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.4 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: 328.4 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
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.4 Line No.: 24 Column: m
Transmission resale - purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control service. Generation regulation
and frequency response service.

Schedule Page: 328.4 Line No.: 25 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 25 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.4 Line No.: 26 Column: a
This footnote applies to all occurrences of "Sierra Pacific Power Company" on pages
328-330. Sierra Pacific Power Company is a principal subsidiary of NV Energy, Inc., which
is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's
indirect parent company.
Schedule Page: 328.4 Line No.: 26 Column: b
Operations and maintenance or facility lease services with no receipt or delivery of
energy.

Schedule Page: 328.4 Line No.: 26 Column: c
Operations and maintenance or facility lease services with no receipt or delivery of
energy.

Schedule Page: 328.4 Line No.: 26 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.: 26 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.21
Schedule Page: 328.4 Line No.: 27 Column: b
Operations and maintenance or facility lease services with no receipt or delivery of
energy.

Schedule Page: 328.4 Line No.: 27 Column: c
Operations and maintenance or facility lease services with no receipt or delivery of
energy.
Schedule Page: 328.4 Line No.: 27 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.: 27 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.4 Line No.: 28 Column: b
Operations and maintenance or facility lease services with no receipt or delivery of
energy.

Schedule Page: 328.4 Line No.: 28 Column: c
Operations and maintenance or facility lease services with no receipt or delivery of
energy.

Schedule Page: 328.4 Line No.: 28 Column: d
Use of Facilities Agreement pertaining to the legacy contract (Rate Schedule 298) for
phase shifting transformers at Sigurd-Glen Canyon 230kV transmission line and Pinto-Four
Corners 345kV transmission line, which terminated on February 12, 2020.

Schedule Page: 328.4 Line No.: 28 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.: 29 Column: m
Unauthorized use of transmission service. Scheduling, system control and dispatch service.
Reactive supply and voltage control service. Generation regulation and frequency response
service. Operating reserve - spinning reserve service. Operating reserve - supplemental
reserve service.

Schedule Page: 328.4 Line No.: 30 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 30 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.4 Line No.: 31 Column: c
Complete name is Southern California Public Power Authority.

Schedule Page: 328.4 Line No.: 31 Column: m
Unauthorized use of transmission service. Scheduling, system control and dispatch service.
Reactive supply and voltage control service. Generation regulation and frequency response
service. Operating reserve - spinning reserve service. Operating reserve - supplemental
reserve service.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.22
Schedule Page: 328.4 Line No.: 32 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 779) terminating on August 31, 2024.

Schedule Page: 328.4 Line No.: 32 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 33 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 779) terminating on August 31, 2024.
Schedule Page: 328.4 Line No.: 33 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.4 Line No.: 34 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 Line No.: 1 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.5 Line No.: 1 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.5 Line No.: 2 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 Line No.: 3 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.5 Line No.: 3 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.5 Line No.: 4 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 Line No.: 5 Column: d
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.: 5 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.5 Line No.: 6 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: 328.5 Line No.: 6 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.23
Schedule Page: 328.5 Line No.: 7 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: 328.5 Line No.: 7 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.5 Line No.: 8 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 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: 328.5 Line No.: 9 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.5 Line No.: 10 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 Line No.: 11 Column: a
This footnote applies to all occurrences of "Tri-State Gen and Trans" on pages 328-330.
Complete name is Tri-State Generation and Transmission Association, Inc.

Schedule Page: 328.5 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328.5 Line No.: 12 Column: d
Network transmission service under the Open Access Transmission Tariff (7th Revised
Service Agreement 628) terminating on June 30, 2021.

Schedule Page: 328.5 Line No.: 12 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.5 Line No.: 13 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 Line No.: 14 Column: m
Distribution voltage service charge. Primary delivery service. Scheduling, system control
and dispatch service. Reactive supply and voltage control service. Regulation and
frequency response service. Operating reserve - spinning reserve service. Operating
reserve - supplemental reserve service.

Schedule Page: 328.5 Line No.: 15 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: 328.5 Line No.: 15 Column: m
Annual transmission services true-up refunds and/or surcharge.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.24
Schedule Page: 328.5 Line No.: 16 Column: c
This footnote applies to all occurrences of "Weber Basin Water Conserv." on pages 328-330.
Complete name is Weber Basin Water Conservancy District.

Schedule Page: 328.5 Line No.: 16 Column: d
Legacy contract (3rd Revised Rate Schedule 286) executed between PacifiCorp and United
States Department of the Interior, Bureau of Reclamation Weber Basin Water Conservancy
District for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge for energy deliveries at and below 138kV. Agreement terminates any
time after April 1, 2040 with four years written notification.

Schedule Page: 328.5 Line No.: 16 Column: m
Energy consumption charge for deliveries at and below 138kV.

Schedule Page: 328.5 Line No.: 17 Column: d
Legacy contract (3rd Revised Rate Schedule 286) executed between PacifiCorp and United
States Department of the Interior, Bureau of Reclamation Weber Basin Water Conservancy
District for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge for energy deliveries at and below 138kV. Agreement terminates any
time after April 1, 2040 with four years written notification.

Schedule Page: 328.5 Line No.: 17 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.5 Line No.: 18 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 terminates with one-year written notice.

Schedule Page: 328.5 Line No.: 19 Column: a
This footnote applies to all occurrences of "Utah Associated Municipal Power" on pages
328-330. Complete name is Utah Associated Municipal Power Systems.

Schedule Page: 328.5 Line No.: 19 Column: d
Legacy contract executed between PacifiCorp and Utah Associated Municipal Power Systems
for transmission service over agreed-upon facilities (4th 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: 328.5 Line No.: 19 Column: m
Distribution voltage service charge. Scheduling, system control and dispatch service.
Reactive supply and voltage control service. Generation regulation and frequency response
service. Operating reserve - spinning reserve service. Operating reserve - supplemental
reserve service.

Schedule Page: 328.5 Line No.: 20 Column: d
Legacy contract executed between PacifiCorp and Utah Associated Municipal Power Systems
for transmission service over agreed-upon facilities (4th 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: 328.5 Line No.: 20 Column: m
Annual transmission services true-up refunds and/or surcharge.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.25
Schedule Page: 328.5 Line No.: 21 Column: d
Legacy contract (5th Revised Rate Schedule 637) executed between PacifiCorp and Utah
Municipal Power Agency for transmission service over agreed-upon facilities (Amended and
Restated Transmission Service and Operating Agreement). Subject to termination upon mutual
agreement and replacement agreements are in effect.

Schedule Page: 328.5 Line No.: 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: 328.5 Line No.: 22 Column: d
Legacy contract (5th Revised Rate Schedule 637) executed between PacifiCorp and Utah
Municipal Power Agency for transmission service over agreed-upon facilities (Amended and
Restated Transmission Service and Operating Agreement). Subject to termination upon mutual
agreement and replacement agreements are in effect.

Schedule Page: 328.5 Line No.: 22 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.5 Line No.: 23 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 Line No.: 24 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.: 24 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.

Schedule Page: 328.5 Line No.: 25 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.: 25 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.5 Line No.: 26 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.

Schedule Page: 328.5 Line No.: 26 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
terminates upon three years after written notice and mutual consent.

Schedule Page: 328.5 Line No.: 26 Column: m
Fixed termination fee associated with a contract cancellation applied for the duration of
the 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.26
Schedule Page: 328.5 Line No.: 27 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.

Schedule Page: 328.5 Line No.: 27 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
terminates upon three years after written notice and mutual consent.

Schedule Page: 328.5 Line No.: 27 Column: m
Fixed termination fee associated with a contract cancellation applied for the duration of
the agreement. Prior period adjustment.
Schedule Page: 328.5 Line No.: 28 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.

Schedule Page: 328.5 Line No.: 28 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 terminates upon three years after written notice and mutual consent.

Schedule Page: 328.5 Line No.: 28 Column: m
Charges for low-voltage transmission of power and energy.
Schedule Page: 328.5 Line No.: 29 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.

Schedule Page: 328.5 Line No.: 29 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 terminates upon three years after written notice and mutual consent.

Schedule Page: 328.5 Line No.: 29 Column: m
Charges for low-voltage transmission of power and energy.
Schedule Page: 328.5 Line No.: 30 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 is subject to terminate upon the earlier of five years after
written notice or June 30, 2042. See also page 332, Transmission of electricity by others
in this Form No. 1.

Schedule Page: 328.5 Line No.: 31 Column: m
Distribution voltage service charge. Primary delivery service. 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.27
Schedule Page: 328.5 Line No.: 32 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.: 32 Column: d
Evergreen network transmission service under the Open Access Transmission Tariff (4th
Revised Service Agreement 175).

Schedule Page: 328.5 Line No.: 32 Column: m
Annual transmission services true-up refunds and/or surcharge.

Schedule Page: 328.5 Line No.: 33 Column: a
This footnote applies to all occurrences of "Western Area Power Adm CO MO" on pages
328-330. Complete name is Western Area Power Administration Colorado Missouri.
Schedule Page: 328.5 Line No.: 33 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.5 Line No.: 34 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.6 Line No.: 1 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.6 Line No.: 2 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.28
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
/ /2020/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 -546 -546Adams Solar Center LLC 1
LFP -42,268 -42,268Adams Solar Center LLC 2
OS -9,018 -9,018Adams Solar Center LLC 3
AD -57,703 -57,703Arizona Public Service 4
OS 3,135,547 3,135,547 1,317,600 1,317,600Arizona Public Service 5
NF 615,028 615,028 100,247 100,247Arizona Public Service 6
OS -20,677 -20,677Arizona Public Service 7
SFP 562,916 562,916 65,485 65,485Arizona Public Service 8
FNS 25,835 25,835 2,669 2,669Ashland, City of 9
AD -457 -457Avista Corporation 10
FNS 301,661 301,661 22,384 23,058Avista Corporation 11
NF 449,603 449,603 78,831 76,871Avista Corporation 12
OS -112 -112Avista Corporation 13
SFP 253,363 253,363 80,596 78,840Avista Corporation 14
NF 4,714 4,714 2,364 2,364Basin Elect. Power Coop 15
OLF 148,437 148,437 32,985 32,985Big Horn Rural Electric 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332
20,835,307 21,084,173 123,507,865 60,829 17,619,531 141,188,225TOTAL
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
/ /2020/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 -882 -882Black Hills Power, Inc. 1
NF 424 424 424 424Black Hills Power, Inc. 2
OS 28,114 28,114Black Hills Power, Inc. 3
SFP 209,731 209,731 30,099 30,099Black Hills Power, Inc. 4
AD 251,547 251,547Bonneville Power Admin 5
FNS 5,467,187 5,467,187 3,203 3,130Bonneville Power Admin 6
LFP 52,510,625 52,510,625 4,987,087 4,873,745Bonneville Power Admin 7
NF 7,351,017 7,351,017 1,948,134 1,903,902Bonneville Power Admin 8
OLF 20,702,752 20,702,752 3,413,013 3,335,264Bonneville Power Admin 9
OS 15,269,684 15,269,684Bonneville Power Admin 10
SFP 481,755 481,755 152,592 149,105Bonneville Power Admin 11
AD -17,892 -17,892CA Ind Sys Operator 12
OS 2,358,710 2,358,710CA Ind Sys Operator 13
SFP 32,137 32,137CA Ind Sys Operator 14
LFP 3,031,312 3,031,312 862,096 862,096Deseret Gen and Trans 15
NF 53,123 53,123 8,418 8,418Deseret Gen and Trans 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.1
20,835,307 21,084,173 123,507,865 60,829 17,619,531 141,188,225TOTAL
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
/ /2020/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 -858 -858Deseret Gen and Trans 1
SFP 78,056 78,056 22,080 22,080Deseret Gen and Trans 2
AD -2,732 -2,732Elbe Solar Center, LLC 3
LFP -203,034 -203,034Elbe Solar Center, LLC 4
OS -44,345 -44,345Elbe Solar Center, LLC 5
OS 92,024 92,024Flathead Elect Coop Inc 6
OS 209,693 209,693Hermiston Gen Co L.P. 7
AD -42,847 -42,847Idaho Power Company 8
FNS 10,933 10,933Idaho Power Company 9
LFP 14,268,627 14,268,627 4,479,840 4,479,840Idaho Power Company 10
NF 1,209,416 1,209,416 326,633 323,593Idaho Power Company 11
OLF 29,760 29,760Idaho Power Company 12
OS 113,209 113,209Idaho Power Company 13
SFP 87,394 87,394 28,871 28,871Idaho Power Company 14
AD 70,308 70,308Moon Lake Elect. Assoc. 15
FNS 262,852 262,852 18 18Moon Lake Elect. Assoc. 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.2
20,835,307 21,084,173 123,507,865 60,829 17,619,531 141,188,225TOTAL
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
/ /2020/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 1,419 1,419Morgan City Corporation 1
AD 7,263 7,263Nevada Power Company 2
NF 392,749 392,749 86,758 86,758Nevada Power Company 3
OS 241,270 241,270Nevada Power Company 4
SFP 1,000,700 1,000,700 246,478 246,478Nevada Power Company 5
NF 16,866 16,866 2,971 2,971NorthWestern Energy 6
OS 416 416NorthWestern Energy 7
LFP 849,350 849,350 191,221 191,221Platte River Pwr Auth 8
OS 17,041 17,041Platte River Pwr Auth 9
AD -2 -2Portland Gen. Electric 10
LFP 75,360 75,360 105,720 105,720Portland Gen. Electric 11
NF 1,642 1,642 1,598 1,598Portland Gen. Electric 12
OLF 963 963Portland Gen. Electric 13
OS 7,716 7,716 3,901Portland Gen. Electric 14
SFP 39,124 39,124 36,596 36,596Portland Gen. Electric 15
LFP 180,310 180,310 62,532 62,532Public Service Co of CO 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.3
20,835,307 21,084,173 123,507,865 60,829 17,619,531 141,188,225TOTAL
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
/ /2020/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification(b)
NF 1,438 1,438 200 200Public Service Co of NM 1
OS 137 137Public Service Co of NM 2
AD 28,295 28,295Puget Sound Energy, Inc 3
SFP 35,111 35,111 6,788 6,788Puget Sound Energy, Inc 4
NF 963 963 156 156Salt River Project 5
OS 152 152Salt River Project 6
SFP 99 99 16 16Salt River Project 7
NF 34,182 34,182 7,636 7,636Sierra Pacific Power Co 8
OS 5,665 5,665Sierra Pacific Power Co 9
SFP 4,560 4,560 1,152 1,152Sierra Pacific Power Co 10
OLF 7,244 7,244Surprise Valley Electr. 11
LFP 174,819 174,819 61,275 61,275Tri-State Gen and Trans 12
NF 30,301 30,301 2,397 2,397Tri-State Gen and Trans 13
OS 8,254 8,254Tri-State Gen and Trans 14
AD -773 -773Western Area Power Admn 15
FNS 7,225,848 7,225,848 934,453 934,453Western Area Power Admn 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.4
20,835,307 21,084,173 123,507,865 60,829 17,619,531 141,188,225TOTAL
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
/ /2020/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 2,392,916 2,392,916 1,278,000 1,278,000Western Area Power Admn 1
NF 264,512 264,512 88,388 88,388Western Area Power Admn 2
OS 771,634 771,634Western Area Power Admn 3
SFP 3,269 3,269 268 268Western Area Power Admn 4
LFP -2,259,331 -2,259,331Westport Field Srv LLC 5
392,620 392,620Accrual 6
7
8
9
10
11
12
13
14
15
16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.5
20,835,307 21,084,173 123,507,865 60,829 17,619,531 141,188,225TOTAL
Schedule Page: 332 Line No.: 1 Column: b
Settlement adjustment.

Schedule Page: 332 Line No.: 1 Column: g
Settlement adjustment.

Schedule Page: 332 Line No.: 2 Column: b
Adams Solar Center LLC - contract termination date: October 30, 2036.
Schedule Page: 332 Line No.: 2 Column: g
Reimbursement for third-party services.

Schedule Page: 332 Line No.: 3 Column: b
Ancillary services.

Schedule Page: 332 Line No.: 3 Column: g
Ancillary services.

Schedule Page: 332 Line No.: 4 Column: b
Settlement adjustment.

Schedule Page: 332 Line No.: 4 Column: g
Settlement adjustment.

Schedule Page: 332 Line No.: 5 Column: b
Arizona Public Service Company - Legacy contract executed between PacifiCorp and Arizona
Public Service Company concerning the exchange of transmission services over agreed-upon
facilities (Restated Transmission Service Agreement between PacifiCorp and Arizona Public
Service Company, Rate Schedule 436). The contract terminates when the Cholla Plant Unit 4
has been retired from service and all costs of terminating Unit 4 have been paid. The
Cholla Plant Unit 4 was retired from service on December 31, 2020 and final costs to
terminate Unit 4 are expected to be paid by the end of December 31, 2021. See also pages
328-330, Transmission of electricity for others in this Form No. 1.
Schedule Page: 332 Line No.: 7 Column: b
Ancillary services.

Schedule Page: 332 Line No.: 7 Column: g
Ancillary services.

Schedule Page: 332 Line No.: 10 Column: b
Settlement adjustment.

Schedule Page: 332 Line No.: 10 Column: g
Settlement adjustment.

Schedule Page: 332 Line No.: 13 Column: b
Ancillary services.

Schedule Page: 332 Line No.: 13 Column: g
Ancillary services.
Schedule Page: 332 Line No.: 15 Column: a
Complete name is Basin Electric Power Cooperative, 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 332 Line No.: 16 Column: b
Big Horn Rural Electric Company - contract termination date: March 10, 2021.
Schedule Page: 332 Line No.: 16 Column: g
Use of facilities.

Schedule Page: 332.1 Line No.: 1 Column: b
Settlement adjustment.

Schedule Page: 332.1 Line No.: 1 Column: g
Settlement adjustment.

Schedule Page: 332.1 Line No.: 3 Column: b
Ancillary services.

Schedule Page: 332.1 Line No.: 3 Column: g
Ancillary services.

Schedule Page: 332.1 Line No.: 5 Column: b
Settlement adjustment.

Schedule Page: 332.1 Line No.: 5 Column: g
Settlement adjustment.

Schedule Page: 332.1 Line No.: 7 Column: b
Bonneville Power Administration - contract termination dates: July 1, 2021; September 1,
2021; November 1, 2021; December 1, 2021; January 1, 2022; March 1, 2022; April 1, 2022;
July 1, 2022; November 1, 2022; March 1, 2023; July 1, 2023; October 1, 2023; December 1,
2023; January 1, 2024; July 1, 2024; September 1, 2024; October 1, 2024; November 1, 2024;
October 1, 2025, November 1, 2025, October 1, 2027; November 1, 2033 and evergreen.
Schedule Page: 332.1 Line No.: 9 Column: b
Bonneville Power Administration - contract termination dates: September 30, 2023;
September 30, 2027 and evergreen.

Schedule Page: 332.1 Line No.: 10 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 pages 328-330, Transmission of electricity for others in this Form No. 1.
Schedule Page: 332.1 Line No.: 10 Column: g
Ancillary services. Use of facilities.

Schedule Page: 332.1 Line No.: 12 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.: 12 Column: b
Settlement adjustment.
Schedule Page: 332.1 Line No.: 12 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 332.1 Line No.: 13 Column: b
Ancillary services.
Schedule Page: 332.1 Line No.: 13 Column: g
Ancillary services.

Schedule Page: 332.1 Line No.: 15 Column: a
This footnote applies to all occurrences of "Deseret Gen and Trans" on page 332. Complete
name is Deseret Generation and Transmission Co-operative.
Schedule Page: 332.1 Line No.: 15 Column: b
Deseret Generation and Transmission Co-operative - contract termination date: November 1,
2022.
Schedule Page: 332.2 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 332.2 Line No.: 1 Column: g
Settlement adjustment.

Schedule Page: 332.2 Line No.: 3 Column: b
Settlement adjustment.

Schedule Page: 332.2 Line No.: 3 Column: g
Settlement adjustment.

Schedule Page: 332.2 Line No.: 4 Column: b
Elbe Solar Center, LLC - contract termination date: October 30, 2036.

Schedule Page: 332.2 Line No.: 4 Column: g
Reimbursement for third-party services.
Schedule Page: 332.2 Line No.: 5 Column: b
Ancillary services.

Schedule Page: 332.2 Line No.: 5 Column: g
Ancillary services.

Schedule Page: 332.2 Line No.: 6 Column: a
Complete name is Flathead Electric Cooperative, Inc.
Schedule Page: 332.2 Line No.: 6 Column: b
Use of facilities.

Schedule Page: 332.2 Line No.: 6 Column: g
Use of facilities.

Schedule Page: 332.2 Line No.: 7 Column: a
Complete name is Hermiston Generating Company, L.P. who operates the Hermiston Plant and
is jointly owned. PacifiCorp owns a 50% share of the Hermiston Plant.
Schedule Page: 332.2 Line No.: 7 Column: b
Use of 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 332.2 Line No.: 7 Column: g
Use of facilities.

Schedule Page: 332.2 Line No.: 8 Column: b
Settlement adjustment.

Schedule Page: 332.2 Line No.: 8 Column: g
Settlement adjustment.

Schedule Page: 332.2 Line No.: 10 Column: b
Idaho Power Company - contract termination dates: April 1, 2025 and July 1, 2025.

Schedule Page: 332.2 Line No.: 12 Column: b
Idaho Power Company - The contract terminates on August 31, 2022 and shall automatically
renew for each successive one-year period thereafter unless or until the earlier of (i)
one-year following the Department of Energy’s receipt of written notice by PacifiCorp, if
due to a re-configuration of its transmission system and PacifiCorp no longer needs use of
the Department of Energy's Scoville facilities; or (ii) upon mutual agreement of the
parties.

Schedule Page: 332.2 Line No.: 12 Column: g
Use of facilities.

Schedule Page: 332.2 Line No.: 13 Column: b
Ancillary services.

Schedule Page: 332.2 Line No.: 13 Column: g
Ancillary services.

Schedule Page: 332.2 Line No.: 15 Column: a
This footnote applies to all occurrences of "Moon Lake Elect. Assoc." on page 332.
Complete name is Moon Lake Electric Association Inc.

Schedule Page: 332.2 Line No.: 15 Column: b
Settlement adjustment.

Schedule Page: 332.2 Line No.: 15 Column: g
Settlement adjustment.

Schedule Page: 332.2 Line No.: 16 Column: b
Use of facilities.

Schedule Page: 332.2 Line No.: 16 Column: g
Use of facilities.

Schedule Page: 332.3 Line No.: 1 Column: b
Morgan City Corporation - contract termination date: Evergreen.

Schedule Page: 332.3 Line No.: 2 Column: a
This footnote applies to all occurrences of "Nevada Power Company" on page 332. Nevada
Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect wholly
owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 332.3 Line No.: 2 Column: b
Settlement adjustment.

Schedule Page: 332.3 Line No.: 2 Column: g
Settlement adjustment.

Schedule Page: 332.3 Line No.: 4 Column: b
Ancillary services.

Schedule Page: 332.3 Line No.: 4 Column: g
Ancillary services.

Schedule Page: 332.3 Line No.: 7 Column: b
Ancillary services.

Schedule Page: 332.3 Line No.: 7 Column: g
Ancillary services.

Schedule Page: 332.3 Line No.: 8 Column: a
This footnote applies to all occurrences of "Platte River Pwr Auth" on page 332. Complete
name is Platte River Power Authority.
Schedule Page: 332.3 Line No.: 8 Column: b
Platte River Power Authority - contract termination date: October 31, 2022.

Schedule Page: 332.3 Line No.: 9 Column: b
Ancillary services.

Schedule Page: 332.3 Line No.: 9 Column: g
Ancillary services.

Schedule Page: 332.3 Line No.: 10 Column: a
This footnote applies to all occurrences of "Portland Gen. Electric" on page 332. Complete
name is Portland General Electric Company.

Schedule Page: 332.3 Line No.: 10 Column: b
Settlement adjustment.

Schedule Page: 332.3 Line No.: 10 Column: g
Settlement adjustment.

Schedule Page: 332.3 Line No.: 11 Column: b
Portland General Electric Company - contract termination date: April 1, 2022.

Schedule Page: 332.3 Line No.: 13 Column: b
Portland General Electric Company - contract termination date: Upon two years written
notice.
Schedule Page: 332.3 Line No.: 13 Column: g
Use of facilities.

Schedule Page: 332.3 Line No.: 14 Column: b
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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Schedule Page: 332.3 Line No.: 14 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 16 Column: a
Complete name is Public Service Company of Colorado.

Schedule Page: 332.3 Line No.: 16 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: 332.4 Line No.: 1 Column: a
This footnote applies to all occurrences of "Public Service Co of NM" on page 332.
Complete name is Public Service Company of New Mexico.

Schedule Page: 332.4 Line No.: 2 Column: b
Ancillary services.

Schedule Page: 332.4 Line No.: 2 Column: g
Ancillary services.

Schedule Page: 332.4 Line No.: 3 Column: b
Settlement adjustment.

Schedule Page: 332.4 Line No.: 3 Column: g
Settlement adjustment.

Schedule Page: 332.4 Line No.: 6 Column: b
Ancillary services.

Schedule Page: 332.4 Line No.: 6 Column: g
Ancillary services.

Schedule Page: 332.4 Line No.: 8 Column: a
This footnote applies to all occurrences of "Sierra Pacific Power Co" on page 332. Sierra
Pacific Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect
wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
company.
Schedule Page: 332.4 Line No.: 9 Column: b
Ancillary services.

Schedule Page: 332.4 Line No.: 9 Column: g
Ancillary services.

Schedule Page: 332.4 Line No.: 11 Column: a
Complete name is Surprise Valley Electrification Corp.

Schedule Page: 332.4 Line No.: 11 Column: b
Surprise Valley Electrification Corp. - contract termination date: Evergreen.

Schedule Page: 332.4 Line No.: 11 Column: g
Use of 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
Schedule Page: 332.4 Line No.: 12 Column: a
This footnote applies to all occurrences of "Tri-State Gen and Trans" on page 332. The
complete name is Tri-State Generation and Transmission Association, Inc.
Schedule Page: 332.4 Line No.: 12 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.: 14 Column: b
Ancillary services.

Schedule Page: 332.4 Line No.: 14 Column: g
Ancillary services.

Schedule Page: 332.4 Line No.: 15 Column: b
Settlement adjustment.

Schedule Page: 332.4 Line No.: 15 Column: g
Settlement adjustment.

Schedule Page: 332.5 Line No.: 1 Column: b
Western Area Power Administration - contract termination date: May 31, 2022.

Schedule Page: 332.5 Line No.: 3 Column: b
Western Area Power Administration - 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 is subject to terminate upon the
earlier of five years after written notice or June 30, 2042. See also pages 328-330,
Transmission of electricity for others in this Form No. 1.

Schedule Page: 332.5 Line No.: 3 Column: g
Ancillary services. Use of facilities.

Schedule Page: 332.5 Line No.: 5 Column: b
Westport Field Services LLC - contract termination date: Evergreen.

Schedule Page: 332.5 Line No.: 5 Column: g
Reimbursement for third-party services.

Schedule Page: 332.5 Line No.: 6 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
PacifiCorp X / /2020/Q4
Line Description Amount
(b)(a)No.
1,318,681Industry 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
Business & Economic Development and 7
Corporate Memberships & Subscriptions: 8
5,000 Carbon County Economic Development Corporation 9
5,000 Clatsop Economic Development Resources 10
7,500 Economic Development for Central Oregon 11
5,025 Greater Yakima Chamber of Commerce 12
5,000 GridForward 13
5,000 Klamath County Economic Development Association 14
5,000 Laramie Chamber of Business Alliance 15
6,000 Ogden-Weber Chamber of Commerce 16
41,256 Oregon Business & Industry Association 17
24,596 Oregon Business Council 18
7,500 Oregon Economic Development Association 19
5,000 Oregon Sports Authority 20
15,000 Oregon State University, Utility Pole Research 21
28,848 Portland Business Alliance 22
5,000 Redmond Economic Development, Inc. 23
30,000 Salt Lake Chamber 24
5,000 South Coast Development Council, Inc. 25
5,000 South Valley Chamber 26
7,075 Utah Manufacturers Association 27
18,700 Utah Taxpayers Association 28
11,000 Utah Valley Chamber of Commerce 29
15,000 Walla Walla Valley Chamber of Commerce 30
9,250 Wyoming Business Alliance 31
5,375 Wyoming Economic Development Association 32
6,500 Wyoming State Chamber of Commerce 33
8,150 Yakima County Development Association 34
121,173 Other (Individually < $5,000) 35
36
Rating Agency and Trustee Fees: 37
140,628 The Bank of New York Mellon 38
20,317 Computershare Shareowner Services, LLC 39
130,318 Moody's Investors Service, Inc. 40
189,802 Standard and Poor's Financial Services, LLC 41
13,372 U.S. Bank National Association 42
43
16,499Directors' Fees - Regional Advisory Board 44
45
2,242,565
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
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
PacifiCorp X
/ /2020/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)
46,992,581 46,992,581 1 Intangible Plant
570,040,492 570,040,492 2 Steam Production Plant
3 Nuclear Production Plant
35,360,999 35,049,303 311,696 4 Hydraulic Production Plant-Conventional
5 Hydraulic Production Plant-Pumped Storage
197,423,490 197,423,490 6 Other Production Plant
116,134,858 116,134,858 7 Transmission Plant
168,914,015 168,914,015 8 Distribution Plant
9 Regional Transmission and Market Operation
45,818,998 45,107,563 711,435 10 General Plant
11 Common Plant-Electric
1,180,685,433 1,132,669,721 48,015,712 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
/ /2020/Q4
Line
No.Account No.
(c)(b)(a)(d) (e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f) (g)(Percent)
HYDRAULIC PROD. 12
Bear River 13
7.02330.40 ID 38 14
Klamath River Accel 15
20.00331.00 CA/OR 973 16
20.00332.00 CA/OR 205 17
20.00333.00 CA/OR 623 18
20.00334.00 CA/OR 14 19
20.00336.00 CA/OR 95 20
21
WIND GENERATION 22
Cedar Springs II 23
29.33 -1.00 3.44 28.90341.00 WY 5,704 24
29.41 -1.00 3.43 28.90343.00 WY 198,371 25
26.53 -2.00 3.85 26.00344.00 WY 12,141 26
28.99 -1.00 3.49 28.50345.00 WY 29,017 27
29.94 -1.00 3.37 29.50346.00 WY 1,273 28
Ekola Flats 29
29.33 -2.00 3.47 28.90341.00 WY 6,947 30
29.41 -2.00 3.47 28.90343.00 WY 263,897 31
26.53 -2.00 3.85 26.00344.00 WY 16,232 32
28.99 -2.00 3.53 28.50345.00 WY 27,170 33
29.94 -1.00 3.37 29.50346.00 WY 2,012 34
Glenrock 35
3.39330.20 WY 23 36
Pryor Mountain 37
3.45341.00 MT 19,634 38
3.45343.00 MT 27,153 39
3.45344.00 MT 1,616 40
3.45345.00 MT 2,352 41
3.45346.00 MT 1,498 42
TB Flats 43
29.33 -1.00 3.44 28.90341.00 WY 5,460 44
29.41 -1.00 3.43 28.90343.00 WY 200,367 45
26.53 -2.00 3.85 26.00344.00 WY 12,293 46
28.99 -1.00 3.49 28.50345.00 WY 18,305 47
29.94 3.34 29.50346.00 WY 1,564 48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2020/Q4
Line
No.Account No.
(c)(b)(a)(d) (e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f) (g)(Percent)
GENERAL PLANT 12
2.50389.20 WA 95 13
14
Acct 403 - Provisions 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 337.1
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, 2020, depreciation expense associated with transportation equipment was
$17,001,326.
Schedule Page: 336 Line No.: 12 Column: e
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as
a regulatory asset.
Schedule Page: 336 Line No.: 15 Column: a
The depreciation rate changes are for the Klamath hydroelectric system’s four mainstem
dams (JC Boyle, Iron Gate, Copco No. 1 and Copco No. 2). For further discussion, refer to
Note 14 of Notes to Financial Statements in this Form No. 1.
Schedule Page: 336 Line No.: 35 Column: a
Includes Glenrock, Glenrock III and Rolling Hills wind plants

Schedule Page: 336.1 Line No.: 15 Column: a
For a discussion on provisions for depreciation that were made during the year, refer to
Note 3 of Notes to Financial Statements in this Form No. 1.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
REGULATORY COMMISSION EXPENSES
PacifiCorp X
/ /2020/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 6,214,734 6,214,734 2
Rate Cases and Proceedings 1,056,085 1,056,085 3
4
Oregon Public Utility Commission: 5
Annual Fee 3,386,782 3,386,782 6
Rate Cases and Proceedings 2,775,954 2,775,954 7
1,496,800 Deferred Intervenor Funding Grants 8
9
Wyoming Public Service Commission: 10
Annual Fee 1,897,583 1,897,583 11
Rate Cases and Proceedings 759,512 759,512 12
13
Washington Utilities and Transportation 14
Commission: 15
Annual Fee 629,100 629,100 16
Rate Cases and Proceedings 344,062 344,062 17
18
Idaho Public Utilities Commission: 19
Annual Fee 723,671 723,671 20
Rate Cases and Proceedings 193,052 193,052 21
66,865 Deferred Intervenor Funding Grants 22
23
California Public Utilities Commission: 24
Annual Fee 1,281 1,281 25
Rate Cases and Proceedings 605,974 605,974 26
43,749 Deferred Intervenor Funding Grants 27
28
California Environmental Protection Agency: 29
Industry Compliance Fee 53,297 18,120 71,417 30
31
Multi-State: 32
Rate Cases and Proceedings 141,443 141,443 33
Other Regulatory 1,377,899 1,377,899 34
35
Federal Energy Regulatory Commission: 36
Annual Fee 2,230,645 2,230,645 37
Annual Fee - Hydroelectric Plants 2,175,960 2,175,960 38
Transmission Rate Cases 730,619 730,619 39
Other Regulatory 671,057 671,057 40
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96) Page 350
46 TOTAL 17,313,053 8,673,777 25,986,830 1,607,414
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
/ /2020/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 6,214,734928
Electric 3 1,056,085928
4
5
Electric 6 3,386,782928
Electric 7 2,775,954928
2,110,849 614,049 8
9
10
Electric 11 1,897,583928
Electric 12 759,512928
13
14
15
Electric 16 629,100928
Electric 17 344,062928
18
19
Electric 20 723,671928
Electric 21 193,052928
103,348 36,483 22
23
24
Electric 25 1,281928
Electric 26 605,974928
152,013 108,264 27
28
29
Electric 30 71,417928
31
32
Electric 33 141,443928
Electric 34 1,377,899928
35
36
Electric 37 2,230,645928
Electric 38 2,175,960928
Electric 39 730,619928
Electric 40 671,057928
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96) Page 351
46 25,986,830 758,796 2,366,210
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
/ /2020/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
A. Electric R, D & D Performed Internally: 1
Utah Sustainable Transportation and Energy Plan 2
- Clean Coal Technology Projects (1) b. Generation, Fossil-fuel steam 3
- Innovative Utility Projects (3) Distribution 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
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
/ /2020/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
7,204 3 434,182 908 441,386
110,484 4 2,662,886 908 2,773,370
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 353
Schedule Page: 352 Line No.: 2 Column: b
The Utah Sustainable Transportation and Energy Plan was signed into law in March 2016. The
Utah legislation established a five-year pilot program to provide up to $10 million
annually of mandated funding for electric vehicle infrastructure and clean coal research,
and authorized funding at the Utah Public Service Commission's discretion for solar
development, utility-scale battery storage and other innovative technology, economic
development and air quality initiatives.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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
/ /2020/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
97,649,453Production 3
16,643,645Transmission 4
Regional Market 5
37,754,404Distribution 6
30,611,189Customer Accounts 7
7,716,377Customer Service and Informational 8
Sales 9
42,222,956Administrative and General 10
232,598,024TOTAL Operation (Enter Total of lines 3 thru 10) 11
Maintenance 12
43,220,523Production 13
11,350,846Transmission 14
Regional Market 15
78,532,642Distribution 16
1,592,525Administrative and General 17
134,696,536TOTAL Maintenance (Total of lines 13 thru 17) 18
Total Operation and Maintenance 19
140,869,976Production (Enter Total of lines 3 and 13) 20
27,994,491Transmission (Enter Total of lines 4 and 14) 21
Regional Market (Enter Total of Lines 5 and 15) 22
116,287,046Distribution (Enter Total of lines 6 and 16) 23
30,611,189Customer Accounts (Transcribe from line 7) 24
7,716,377Customer Service and Informational (Transcribe from line 8) 25
Sales (Transcribe from line 9) 26
43,815,481Administrative and General (Enter Total of lines 10 and 17) 27
367,294,560 367,294,560TOTAL 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
/ /2020/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
367,294,560 367,294,560TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65
Utility Plant 66
Construction (By Utility Departments) 67
177,240,117 177,240,117Electric Plant 68
Gas Plant 69
Other (provide details in footnote): 70
177,240,117 177,240,117TOTAL Construction (Total of lines 68 thru 70) 71
Plant Removal (By Utility Departments) 72
12,197,231 12,197,231Electric Plant 73
Gas Plant 74
Other (provide details in footnote): 75
12,197,231 12,197,231TOTAL Plant Removal (Total of lines 73 thru 75) 76
Other Accounts (Specify, provide details in footnote): 77
6,072,745 6,072,745Fuel Stock 78
269,725 269,725Miscellaneous Other Income Deductions 79
478,060 478,060Miscellaneous Non-Operating and Non-Utility 80
2,275,193 2,275,193Charges to Affiliates 81
82
83
84
85
86
87
88
89
90
91
92
93
94
9,095,723 9,095,723TOTAL Other Accounts 95
565,827,631 565,827,631TOTAL 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
/ /2020/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) 2 552,095 11,946 153,745 260,240
Net Sales (Account 447) 3 ( 26,104)( 22,179) ( 22,179)
Transmission Rights 4
Ancillary Services 5
Other Items (list separately) 6
Energy Imbalance Market (Account 555) 7 ( 29,115,113)( 4,815,415) 7,722,711 ( 8,428,050)
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
( 28,589,122)( 4,803,469) 7,854,277 ( 8,189,989)
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
/ /2020/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
12,865,042MWh140,601,158Scheduling, System Control and Dispatch 1
8,416,666MWh131,320,291 7,381,935MWh114,356,993Reactive Supply and Voltage 2
30,114,821MWh133,227,169 22,813,062MWh113,602,957Regulation and Frequency Response 3
24,373,215MWh -2,172,702Energy Imbalance 4
19,422,502MWh128,573,527 17,608,981MWh116,615,766Operating Reserve - Spinning 5
19,605,304MWh129,783,537 17,608,981MWh116,615,766Operating Reserve - Supplement 6
Other 7
114,797,550661,332,980 65,412,959461,191,482Total (Lines 1 thru 7) 8
FERC FORM NO. 1 (New 2-04) Page 398
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
PacifiCorp X / /2020/Q4
Line
No.
Monthly Peak
MW - Total
(c)(b)(a)
Month
NAME OF SYSTEM:
Day of
Monthly
Peak
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically
integrated, furnish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the
definition of each statistical classification.
(d)
Hour of
Monthly
Peak
(e)
Firm Network
Service for Self
(f)
Firm Network
Service for
Others
(g)
Long-Term Firm
Point-to-point
Reservations
(h)
Other Long-
Term Firm
Service
(i)
Short-Term Firm
Point-to-point
Reservation
(j)
Other
Service
1,041 1,307 3,634 537 8,584 80015 15,103January 1
944 1,340 3,634 580 8,444 800 4 14,942February 2
1,433 1,148 3,634 513 7,850 800 2 14,578March 3
3,418 3,795 10,902 1,630 24,878Total for Quarter 1 4
883 1,081 3,634 421 7,140 900 2 13,159April 5
928 1,647 3,634 352 8,941170029 15,502May 6
1,334 1,690 3,766 403 9,616180023 16,809June 7
3,145 4,418 11,034 1,176 25,697Total for Quarter 2 8
1,438 1,887 3,762 442 10,658170030 18,187July 9
1,535 2,017 3,762 444 10,721160017 18,479August 10
1,193 1,837 3,764 390 9,8001700 3 16,984September 11
4,166 5,741 11,288 1,276 31,179Total for Quarter 3 12
1,324 1,245 3,766 521 7,978 90026 14,834October 13
1,077 1,252 3,734 487 7,930190030 14,480November 14
1,057 1,315 3,734 587 8,504180029 15,197December 15
3,458 3,812 11,234 1,595 24,412Total for Quarter 4 16
14,187 17,766 44,458 5,677 106,166
Total Year to
Date/Year
17
FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400
Schedule Page: 400 Line No.: 1 Column: d
Pacific Standard Time
Schedule Page: 400 Line No.: 2 Column: d
Pacific Standard Time
Schedule Page: 400 Line No.: 3 Column: d
Pacific Standard Time
Schedule Page: 400 Line No.: 5 Column: d
Pacific Daylight Time
Schedule Page: 400 Line No.: 6 Column: d
Pacific Daylight Time
Schedule Page: 400 Line No.: 7 Column: d
Pacific Daylight Time
Schedule Page: 400 Line No.: 9 Column: d
Pacific Daylight Time
Schedule Page: 400 Line No.: 10 Column: d
Pacific Daylight Time
Schedule Page: 400 Line No.: 11 Column: d
Pacific Daylight Time
Schedule Page: 400 Line No.: 13 Column: d
Pacific Daylight Time
Schedule Page: 400 Line No.: 14 Column: d
Pacific Standard Time
Schedule Page: 400 Line No.: 15 Column: d
Pacific Standard Time
Schedule Page: 400 Line No.: 17 Column: e
For the year being reported, the Net System Load information was compiled using metering
and/or scheduling data. Reflects actual peak net system load for self at time of
Transmission System Peak. Peak load includes behind-the-meter generation.
Schedule Page: 400 Line No.: 17 Column: f
For the year being reported, the 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
For the year being reported, the 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 400 Line No.: 17 Column: i
For the year being reported, the Net System Load information was compiled using
reservations in OASIS at time of Transmission System Peak.
Schedule Page: 400 Line No.: 17 Column: j
For the year being reported, the 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
2020/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
ELECTRIC ENERGY ACCOUNT
PacifiCorp X
/ /2020/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
34,553,522Steam3
Nuclear4
3,040,336Hydro-Conventional5
Hydro-Pumped Storage6
12,069,855Other7
3,104Less Energy for Pumping8
49,660,609Net Generation (Enter Total of lines 3
through 8)
9
11,927,865Purchases10
Power Exchanges:11
8,343,705Received12
6,057,325Delivered13
2,286,380Net Exchanges (Line 12 minus line 13)14
Transmission For Other (Wheeling)15
16,923,319Received16
16,816,917Delivered17
106,402Net Transmission for Other (Line 16 minus
line 17)
18
-248,866Transmission By Others Losses19
63,732,390TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
20
DISPOSITION OF ENERGY21
54,559,978Sales to Ultimate Consumers (Including
Interdepartmental Sales)
22
267,143Requirements Sales for Resale (See
instruction 4, page 311.)
23
4,981,923Non-Requirements Sales for Resale (See
instruction 4, page 311.)
24
Energy Furnished Without Charge25
129,115Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
26
3,794,231Total Energy Losses27
63,732,390TOTAL (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 / /2020/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 15 8,327 357,238 0800 PST 5,521,779
February 30 4 8,221 372,019 0800 PST 5,031,397
March 31 2 7,658 473,753 0800 PST 5,200,628
April 32 2 6,924 80,680 0900 PDT 4,483,384
May 33 29 8,750 321,598 1700 PDT 4,781,604
June 34 23 9,451 470,864 1800 PDT 5,111,972
July 35 30 10,476 313,386 1700 PDT 5,880,577
August 36 17 10,546 402,100 1600 PDT 6,044,999
September 37 3 9,618 274,292 1700 PDT 5,023,885
October 38 26 7,776 732,752 0900 PDT 5,304,644
November 39 9 7,885 673,488 0900 PST 5,467,552
December 40 29 8,274 509,753 1800 PST 5,879,969
FERC FORM NO. 1 (ED. 12-90) Page 401b
41 TOTAL 63,732,390 4,981,923
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
2020/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
/ /2020/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)
154366 6 Net Peak Demand on Plant - MW (60 minutes)
85595256 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
8863260001669474000 12 Net Generation, Exclusive of Plant Use - KWh
17886441266851 13 Cost of Plant: Land and Land Rights
677794880 14 Structures and Improvements
1712928790 15 Equipment Costs
894068422980969 16 Asset Retirement Costs
24980169524247820 17 Total Cost
1605.306258.5696 18 Cost per KW of Installed Capacity (line 17/5) Including
291102399932 19 Production Expenses: Oper, Supv, & Engr
1589291148928144 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
12536887288764 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
28835319080 25 Electric Expenses
25332862785220 26 Misc Steam (or Nuclear) Power Expenses
0816 27 Rents
00 28 Allowances
4007102478867 29 Maintenance Supervision and Engineering
4712254392794 30 Maintenance of Structures
41387874242189 31 Maintenance of Boiler (or reactor) Plant
810018886014 32 Maintenance of Electric Plant
3785991743250 33 Maintenance of Misc Steam (or Nuclear) Plant
2593716975465070 34 Total Production Expenses
0.02930.0452 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)
991077 2147 0 556279 1836 0 38 Quantity (Units) of Fuel Burned
9455 129480 0 8565 140000 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
42.991 82.430 0.000 26.571 81.375 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
49.190 82.430 0.000 28.301 81.375 0.000 41 Average Cost of Fuel per Unit Burned
2.601 15.157 2.609 1.652 13.840 1.666 42 Average Cost of Fuel Burned per Million BTU
0.029 0.000 0.029 0.018 0.000 0.018 43 Average Cost of Fuel Burned per KWh Net Gen
11226.052 6.994 11233.046 10751.243 12.180 10763.423 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
/ /2020/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
81.25172.13 816.77 5
78161 759 6
85548783 8784 7
00 0 8
77161 745 9
00 0 10
00 191 11
3925860001122758000 4325604000 12
683069137086 10448598 13
1778154238554515 168500441 14
96273841185358716 889515797 15
212248735149 28193649 16
116860939224085466 1096658485 17
1438.28851301.8385 1342.6772 18
59982379586 18184 19
979315021781208 46067140 20
00 0 21
9744151715401 3060349 22
00 0 23
00 0 24
410006777158 0 25
4279141279671 16804053 26
00 87656 27
00 0 28
203102687195 0 29
302415392811 1930786 30
10042263249689 7621924 31
530616859945 7333173 32
238580739646 1492527 33
1394440631862310 84415792 34
0.03550.0284 0.0195 35
Coal Oil Composite Coal Oil CompositeCoal Oil Composite 36
Tons Barrels Tons BarrelsTons Barrels 37
590699 134 0 181074 582 02941428 17945 0 38
9797 133981 0 11183 137142 08350 138000 0 39
37.592 93.076 0.000 48.056 90.996 0.00015.365 72.402 0.000 40
36.773 93.076 0.000 53.695 90.996 0.00015.220 72.402 0.000 41
1.877 16.545 1.882 2.401 15.798 2.4160.911 12.492 0.936 42
0.019 0.000 0.019 0.025 0.000 0.0250.010 0.000 0.010 43
10308.539 0.674 10309.213 10315.755 8.541 10324.29611356.572 24.045 11380.617 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
/ /2020/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)
270414 6 Net Peak Demand on Plant - MW (60 minutes)
84398379 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
20178940002662426000 12 Net Generation, Exclusive of Plant Use - KWh
96882619688261 13 Cost of Plant: Land and Land Rights
5446371265021612 14 Structures and Improvements
252324102389360219 15 Equipment Costs
42150754215075 16 Asset Retirement Costs
320691150468285167 17 Total Cost
1089.08221023.0598 18 Cost per KW of Installed Capacity (line 17/5) Including
00 19 Production Expenses: Oper, Supv, & Engr
3674027850695443 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
52643966395583 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
-7338-52728 25 Electric Expenses
2069674727301 26 Misc Steam (or Nuclear) Power Expenses
36115612 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
18592872669673 30 Maintenance of Structures
21543362908783 31 Maintenance of Boiler (or reactor) Plant
12122691820520 32 Maintenance of Electric Plant
281369438797 33 Maintenance of Misc Steam (or Nuclear) Plant
4771517569608984 34 Total Production Expenses
0.02360.0261 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)
1241338 1941 0 900809 2041 0 38 Quantity (Units) of Fuel Burned
11432 138000 0 11675 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
40.720 0.000 0.000 40.614 0.000 0.000 41 Average Cost of Fuel per Unit Burned
1.781 13.163 1.785 1.739 13.054 1.746 42 Average Cost of Fuel Burned per Million BTU
0.019 0.000 0.019 0.018 0.000 0.018 43 Average Cost of Fuel Burned per KWh Net Gen
10660.189 4.225 10664.414 10423.401 5.862 10429.263 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
/ /2020/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
1015.50495.59 1247.78 5
909481 1150 6
87847386 8784 7
00 0 8
909471 1158 9
00 0 10
1550 204 11
45153050002263496000 6943816000 12
237756410274569 29651091 13
12810001193092388 212577712 14
765427731453094515 1094778836 15
83826664215075 12645225 16
904287972560676547 1349652864 17
890.48541131.3314 1081.6433 18
74850 0 19
9932573943231438 130667159 20
00 0 21
142034377118983 18778962 22
00 0 23
00 0 24
0-8683 -68749 25
289695795528092 10462360 26
44176323 15546 27
00 0 28
15572360 0 29
22161394634525 9163485 30
584242711338192 16401311 31
10363163162814 6195603 32
728335642169 1362335 33
15389111075653853 192978012 34
0.03410.0334 0.0278 35
Coal Oil Composite Coal Oil CompositeCoal Oil Composite 36
Tons Barrels Tons BarrelsTons Barrels 37
1025661 16465 0 2022415 4009 03167808 20447 0 38
11344 138000 0 11518 138000 011473 138000 0 39
0.000 0.000 0.000 47.894 84.828 0.00040.167 73.832 0.000 40
40.973 0.000 0.000 48.944 84.828 0.00040.772 73.832 0.000 41
1.806 12.649 1.850 2.125 14.636 2.1311.777 12.738 1.795 42
0.019 0.001 0.020 0.022 0.000 0.0220.019 0.000 0.019 43
10280.961 42.160 10323.121 10317.443 5.146 10322.58910467.760 17.067 10484.827 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
/ /2020/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)
6051387 6 Net Peak Demand on Plant - MW (60 minutes)
87238784 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
6041413 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
105332 11 Average Number of Employees
26590330007006689000 12 Net Generation, Exclusive of Plant Use - KWh
13210311193761 13 Cost of Plant: Land and Land Rights
128923544150056245 14 Structures and Improvements
6241548791282644030 15 Equipment Costs
4295390523681350 16 Asset Retirement Costs
7973533591457575386 17 Total Cost
1127.4793939.9770 18 Cost per KW of Installed Capacity (line 17/5) Including
32413312769319 19 Production Expenses: Oper, Supv, & Engr
73662576209285230 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
759326818255366 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
2088150299 25 Electric Expenses
5283144-16297493 26 Misc Steam (or Nuclear) Power Expenses
100335470 27 Rents
00 28 Allowances
2301511577906 29 Maintenance Supervision and Engineering
130105610451371 30 Maintenance of Structures
431019917196413 31 Maintenance of Boiler (or reactor) Plant
14070994755199 32 Maintenance of Electric Plant
1171038796142 33 Maintenance of Misc Steam (or Nuclear) Plant
97375005258175222 34 Total Production Expenses
0.03660.0368 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)
3957097 7368 0 1368098 2130069 0 38 Quantity (Units) of Fuel Burned
9467 138000 0 9907 1035 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
46.891 83.783 0.000 48.766 3.101 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
52.733 83.783 0.000 49.015 3.101 0.000 41 Average Cost of Fuel per Unit Burned
2.785 14.455 2.792 2.474 2.997 2.513 42 Average Cost of Fuel Burned per Million BTU
0.030 0.000 0.030 0.025 0.002 0.027 43 Average Cost of Fuel Burned per KWh Net Gen
10693.406 6.095 10699.501 10194.853 828.825 11023.678 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
/ /2020/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
240266 192 6
73848242 1233 7
00 0 8
231266 238 9
00 0 10
061 30 11
14535190001265038000 90333000 12
796929210526 1252090 13
1283665052785722 15300629 14
168970057412293032 68468689 15
407646486090 901542 16
183011282465775370 85922950 17
654.64041608.0072 341.4519 18
014613 80624 19
2424697621904619 4490915 20
00 0 21
03156723 71416 22
00 0 23
00 0 24
90838790 0 25
03508847 4261921 26
013234 0 27
00 0 28
00 0 29
0291052 87106 30
03709481 877619 31
01401689 1383838 32
0100480 249005 33
3333085534100738 11502444 34
0.02290.0270 0.1273 35
Coal Oil Composite GasGas 36
Tons Barrels MCFMCF 37
1082254 3363 0 10398346 0 01429644 0 0 38
8114 138000 0 1042 0 01029 0 0 39
19.692 83.086 0.000 2.332 0.000 0.0003.141 0.000 0.000 40
19.982 83.086 0.000 2.332 0.000 0.0003.141 0.000 0.000 41
1.231 14.335 1.246 2.237 0.000 0.0003.052 0.000 0.000 42
0.017 0.000 0.017 0.017 0.000 0.0000.050 0.000 0.000 43
13883.194 15.408 13898.602 7456.529 0.000 0.00016291.477 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
/ /2020/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)
50833 6 Net Peak Demand on Plant - MW (60 minutes)
71798699 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
1819 11 Average Number of Employees
2407519000175570000 12 Net Generation, Exclusive of Plant Use - KWh
373052741195596 13 Cost of Plant: Land and Land Rights
244279098435435 14 Structures and Improvements
328706364104117321 15 Equipment Costs
10307775019290 16 Asset Retirement Costs
357895577158767642 17 Total Cost
603.22874167.1297 18 Cost per KW of Installed Capacity (line 17/5) Including
18379246316 19 Production Expenses: Oper, Supv, & Engr
580161020 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
0-111509 22 Steam Expenses
06509105 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
17386860 25 Electric Expenses
1157507-4583 26 Misc Steam (or Nuclear) Power Expenses
014210 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
61892374227 30 Maintenance of Structures
02120118 31 Maintenance of Boiler (or reactor) Plant
150838378585 32 Maintenance of Electric Plant
038940 33 Maintenance of Misc Steam (or Nuclear) Plant
626663629065409 34 Total Production Expenses
0.02600.0516 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 16340635 0 0 38 Quantity (Units) of Fuel Burned
0 0 0 1096 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
0.000 0.000 0.000 3.550 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
0.000 0.000 0.000 3.550 0.000 0.000 41 Average Cost of Fuel per Unit Burned
0.000 0.000 0.000 3.240 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.000 0.000 0.000 0.024 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
0.000 0.000 0.000 7436.879 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
/ /2020/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
558118 563 6
7195776 7642 7
00 0 8
546119 524 9
00 0 10
320 20 11
238819500043077000 2335426000 12
145322750 3403277 13
354670954255523 44229911 14
33316157881274955 308258159 15
00 134848 16
38316094885530478 356026195 17
647.9975472.4136 628.0229 18
454660 68983 19
536155082401639 49141345 20
00 0 21
00 0 22
00 0 23
00 0 24
2077018527270 1940739 25
5019630 697359 26
00 0 27
00 0 28
00 0 29
276254778519 540132 30
00 0 31
3287258223385 2593438 32
2384777380 27532 33
623136073308193 55009528 34
0.02610.0768 0.0236 35
Gas GasGas 36
MCF MCFMCF 37
495183 0 0 17553137 0 016787069 0 0 38
1060 0 0 1040 0 01041 0 0 39
4.850 0.000 0.000 3.054 0.000 0.0002.927 0.000 0.000 40
4.850 0.000 0.000 3.054 0.000 0.0002.927 0.000 0.000 41
4.577 0.000 0.000 2.937 0.000 0.0002.811 0.000 0.000 42
0.056 0.000 0.000 0.022 0.000 0.0000.021 0.000 0.000 43
12181.326 0.000 0.000 7643.919 0.000 0.0007484.863 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
/ /2020/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)
0634 6 Net Peak Demand on Plant - MW (60 minutes)
07874 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
03171917000 12 Net Generation, Exclusive of Plant Use - KWh
016794626 13 Cost of Plant: Land and Land Rights
053100929 14 Structures and Improvements
0572919713 15 Equipment Costs
00 16 Asset Retirement Costs
0642815268 17 Total Cost
0981.0978 18 Cost per KW of Installed Capacity (line 17/5) Including
052544 19 Production Expenses: Oper, Supv, & Engr
065199212 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)
04048039 25 Electric Expenses
0581908 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
0919145 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
0284747 32 Maintenance of Electric Plant
027261 33 Maintenance of Misc Steam (or Nuclear) Plant
071112856 34 Total Production Expenses
0.00000.0224 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)
21331781 0 0 0 0 0 38 Quantity (Units) of Fuel Burned
1041 0 0 0 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
3.056 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
3.056 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned
2.936 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.021 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
7001.422 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
On December 31, 2020, the Cholla Unit No. 4 ceased operation and the coal-fueled
generating unit was retired.
The Cholla Plant was operated by Arizona Public Service Company and jointly owned.
PacifiCorp owned 100% of Unit No. 4 and 49.53% of common facilities. Data reported
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 represents PacifiCorp's
share.
Schedule Page: 403 Line No.: -1 Column: d
The Craig Plant is operated by Tri-State Generation and Transmission Association, Inc. 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 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 MWh) share of Hayden Unit No. 1, a 12.6% (33 MWh) share of
Hayden Unit No. 2 and 17.5% of common facilities. Data reported 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: 402 Line No.: 20 Column: c
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 represents PacifiCorp's share. Costs that were billed to minority owners for the
operations and maintenance (excluding fuel) of this unit for calendar year 2020 were $1.2
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 represents
PacifiCorp's share. Costs that were billed to minority owners for the operations and
maintenance (excluding fuel) of this unit for calendar year 2020 were $6.8 million and
were primarily credited to Account 506, Miscellaneous steam power 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 403.1 Line No.: -1 Column: e
Refer to Hunter Unit Nos. 1, 2 and 3 for each unit's plant statistics.
Schedule Page: 402.1 Line No.: 11 Column: b
Refer to Hunter - Total Plant for the average number of employees.
Schedule Page: 402.1 Line No.: 11 Column: c
Refer to Hunter - Total Plant for the average number of employees.
Schedule Page: 403.1 Line No.: 11 Column: d
Refer to Hunter - Total Plant 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 66.67% and 33.33%, respectively. Data
reported represents PacifiCorp's share. Costs that were billed to minority owners for the
operations and maintenance (excluding fuel) of this plant for calendar year 2020 were
$24.2 million and were primarily credited to Account 506, Miscellaneous steam power
expenses.
Schedule Page: 402.2 Line No.: -1 Column: c
During the year ended December 31, 2020, Naughton Unit No. 3 was converted to a natural
gas-fueled generation resource as it was previously removed from service as a coal-fueled
generating unit on January 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
represents PacifiCorp's share. Costs that were billed to minority owners for the
operations and maintenance (excluding fuel) of this plant for calendar year 2020 were $4.0
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% share of the Hermiston Plant. Data reported represents
PacifiCorp's share.
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 this
generating facility may be: (a) used in future years to comply with renewable portfolio
standards or other regulatory requirements or (b) sold to third parties in the form of
renewable energy credits or other environmental commodities.
Schedule Page: 403.3 Line No.: 11 Column: d
Refer to the Gadsby Steam Plant for the average number of employees.
Schedule Page: 402.4 Line No.: 11 Column: b
Refer to the Lake Side Plant for the average number of employees.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 402 Line No.: 36 Column: b2
Cholla Plant - Fuel oil is used for start-up purposes.
Schedule Page: 402 Line No.: 36 Column: c2
Colstrip Plant - Fuel oil is used for start-up purposes.

Schedule Page: 402 Line No.: 36 Column: d2
Craig Plant - Fuel oil is used for start-up purposes.
Schedule Page: 402 Line No.: 36 Column: e2
Dave Johnston Plant - Fuel oil is used for start-up purposes.

Schedule Page: 402 Line No.: 36 Column: f2
Hayden Plant - 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 Plant - Fuel oil is used for start-up purposes.

Schedule Page: 402.2 Line No.: 36 Column: b2
Jim Bridger Plant - Fuel oil is used for start-up purposes.

Schedule Page: 402.2 Line No.: 36 Column: d2
Wyodak Plant - 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
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
14803
Copco No. 2
14803
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
/ /2020/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 4,732 4,616
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 70,220,000 86,600,000
Cost of Plant 13
Land and Land Rights 14 107,019 20,914
Structures and Improvements 15 2,234,949 2,724,385
Reservoirs, Dams, and Waterways 16 3,375,745 3,261,503
Equipment Costs 17 5,716,082 10,514,795
Roads, Railroads, and Bridges 18 133,348 551,687
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 11,567,143 17,073,284
Cost per KW of Installed Capacity (line 20 / 5) 21 578.3572 632.3439
Production Expenses 22
Operation Supervision and Engineering 23 16,580 22,383
Water for Power 24 0 0
Hydraulic Expenses 25 3,202 4,322
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 1,088,794 1,312,824
Rents 28 90,319 121,931
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 2,432 3,283
Maintenance of Reservoirs, Dams, and Waterways 31 12,753 618
Maintenance of Electric Plant 32 10,406 99,357
Maintenance of Misc Hydraulic Plant 33 9,727 13,132
Total Production Expenses (total 23 thru 33) 34 1,234,213 1,577,850
Expenses per net KWh 35 0.0176 0.0182
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
/ /2020/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
10 297 6
6,805 6,5027,251 7
8
31 2918 9
31 2918 10
1 31 11
22,190,000 63,793,00023,582,000 12
13
0 3,511,1050 14
2,435,237 4,812,8761,500,507 15
14,820,860 9,980,7225,185,834 16
2,202,766 15,006,3381,407,764 17
250,151 1,086,17650,817 18
0 00 19
19,709,014 34,397,2178,144,922 20
758.0390 1,146.5739542.9948 21
22
25,654 127,71914,800 23
601 0347 24
52,148 132,44730,086 25
0 00 26
422,561 1,233,177306,632 27
106,612 48,86561,507 28
0 00 29
37,161 021,063 30
37,355 74430,180 31
132,282 02,086 32
137,575 366,41278,641 33
951,949 1,909,364545,342 34
0.0429 0.02990.0231 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
/ /2020/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 28
Plant Hours Connect to Load 7 2,892 8,747
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 4
Net Generation, Exclusive of Plant Use - Kwh 12 20,795,000 100,740,000
Cost of Plant 13
Land and Land Rights 14 0 74,674
Structures and Improvements 15 1,764,935 3,124,682
Reservoirs, Dams, and Waterways 16 12,462,362 14,041,525
Equipment Costs 17 2,993,343 6,448,603
Roads, Railroads, and Bridges 18 533,015 546,275
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 17,753,655 24,235,759
Cost per KW of Installed Capacity (line 20 / 5) 21 1,613.9686 734.4169
Production Expenses 22
Operation Supervision and Engineering 23 12,550 108,428
Water for Power 24 254 0
Hydraulic Expenses 25 22,063 40,936
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 283,193 1,122,375
Rents 28 45,105 13,518
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 15,446 14,655
Maintenance of Reservoirs, Dams, and Waterways 31 10,226 17,364
Maintenance of Electric Plant 32 18,619 78,858
Maintenance of Misc Hydraulic Plant 33 57,856 75,258
Total Production Expenses (total 23 thru 33) 34 465,312 1,471,392
Expenses per net KWh 35 0.0224 0.0146
FERC FORM NO. 1 (REV. 12-03) Page 406.1
14803
Iron Gate Lemolo No. 1
1927
JC Boyle
14803
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
/ /2020/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
77 2019 6
5,309 7,2518,501 7
8
83 3219 9
83 3219 10
2 11 11
177,589,000 82,790,00082,373,000 12
13
25,845 0341,617 14
4,256,377 2,930,1518,656,577 15
15,917,365 15,815,11917,221,596 16
15,918,631 6,907,7853,295,170 17
1,061,007 482,5711,095,742 18
0 00 19
37,179,225 26,135,62630,610,702 20
379.4573 816.99361,700.5946 21
22
157,289 31,8771,556,614 23
0 7400 24
12,846 64,1632,882 25
0 00 26
838,199 557,721964,746 27
1,914 131,17381,287 28
0 00 29
134,328 50,0052,189 30
97,386 25,4150 31
18,577 42,85578,482 32
58,246 167,71412,931 33
1,318,785 1,071,6632,699,131 34
0.0074 0.01290.0328 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
/ /2020/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 30 147
Plant Hours Connect to Load 7 7,409 8,782
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 39 151
(b) Under the Most Adverse Oper Conditions 10 39 151
Average Number of Employees 11 1 1
Net Generation, Exclusive of Plant Use - Kwh 12 95,400,000 471,718,000
Cost of Plant 13
Land and Land Rights 14 0 1,735,054
Structures and Improvements 15 6,276,981 111,772,490
Reservoirs, Dams, and Waterways 16 33,251,206 39,020,447
Equipment Costs 17 11,848,673 19,898,159
Roads, Railroads, and Bridges 18 1,820,580 4,245,959
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 53,197,440 176,672,109
Cost per KW of Installed Capacity (line 20 / 5) 21 1,381.7517 1,299.0596
Production Expenses 22
Operation Supervision and Engineering 23 139,638 1,753,306
Water for Power 24 891 37,494
Hydraulic Expenses 25 77,220 960,584
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 603,194 442,925
Rents 28 157,868 120,295
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 65,061 25,975
Maintenance of Reservoirs, Dams, and Waterways 31 71,189 64,801
Maintenance of Electric Plant 32 68,721 129,791
Maintenance of Misc Hydraulic Plant 33 201,844 484,728
Total Production Expenses (total 23 thru 33) 34 1,385,626 4,019,899
Expenses per net KWh 35 0.0145 0.0085
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
/ /2020/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
19 3640 6
8,773 8,5187,273 7
8
28 3645 9
28 3645 10
2 11 11
49,903,000 175,890,000156,575,000 12
13
309,259 105,1680 14
2,903,968 4,222,3165,234,437 15
9,213,407 35,561,87812,846,444 16
15,833,600 7,362,7876,269,096 17
861,447 533,194502,952 18
0 00 19
29,121,681 47,785,34324,852,929 20
970.7227 1,493.2920584.7748 21
22
96,147 202,93450,012 23
0 5,164983 24
37,215 4,19585,245 25
0 00 26
546,599 584,908681,483 27
11,834 58,337174,273 28
0 2690 29
145 74,54697,143 30
1,489 161,04714,717 31
47,142 98,653162,715 32
65,587 263,186222,820 33
806,158 1,453,2391,489,391 34
0.0162 0.00830.0095 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
/ /2020/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 15 7
Plant Hours Connect to Load 7 7,275 7,562
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 47,976,000 25,575,000
Cost of Plant 13
Land and Land Rights 14 0 511,083
Structures and Improvements 15 2,198,755 1,323,693
Reservoirs, Dams, and Waterways 16 14,939,625 11,257,174
Equipment Costs 17 8,979,657 6,450,591
Roads, Railroads, and Bridges 18 582,653 0
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 26,700,690 19,542,541
Cost per KW of Installed Capacity (line 20 / 5) 21 1,483.3717 1,352.4250
Production Expenses 22
Operation Supervision and Engineering 23 21,285 44,869
Water for Power 24 834 0
Hydraulic Expenses 25 36,103 17,367
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 318,366 565,319
Rents 28 73,808 5,606
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 25,891 108
Maintenance of Reservoirs, Dams, and Waterways 31 19,305 1,489
Maintenance of Electric Plant 32 11,971 19,903
Maintenance of Misc Hydraulic Plant 33 94,369 30,607
Total Production Expenses (total 23 thru 33) 34 601,932 685,268
Expenses per net KWh 35 0.0125 0.0268
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
/ /2020/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
247 16212 6
4,967 5,9107,214 7
8
264 16412 9
264 16412 10
1 12 11
569,679,000 503,194,00037,577,000 12
13
17,912,070 8,363,0130 14
73,717,841 18,112,0074,225,236 15
49,426,279 35,023,13890,311,267 16
25,661,245 18,889,0972,638,625 17
1,302,690 2,204,1812,089,012 18
0 00 19
168,020,125 82,591,43699,264,140 20
700.0839 616.35409,024.0127 21
22
3,003,733 1,696,46213,462 23
66,166 36,943254 24
1,909,692 946,458227,366 25
0 00 26
214,324 341,898412,685 27
212,285 118,52645,105 28
0 00 29
23,227 17,72717,028 30
94,254 125,06432,468 31
210,265 141,82111,938 32
850,479 485,57657,670 33
6,584,425 3,910,475817,976 34
0.0116 0.00780.0218 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
2020/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 / /2020/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
6.85 7.0 35,556,000 33,960,3741917Ashton 2381 2
1.11 1.0 315,000 3,419,6751913Bend 3
4.15 4.6 27,032,000 10,998,4831910Big Fork 2652 4
2.81 2.8 15,999,000 2,790,9231957Eagle Point 5
3.20 1,736,6851924East Side 2082 6
2.20 2.0 8,316,000 2,510,2341903Fall Creek 2082 7
2.00 1.2 5,965,000 5,265,4981896Granite 8
0.75 0.4 1,060,000 681,9861917Gunlock 9
1.73 1.4 6,218,000 3,173,4961983Last Chance 10
0.72 0.7 975,000 459,7631910Paris 703 11
5.00 4.0 17,302,000 12,169,5401897Pioneer 2722 12
3.76 4.6 12,911,000 5,344,4521912Prospect No. 1 2630 13
7.20 7.0 17,021,000 9,547,4071932Prospect No. 3 2337 14
1.00 0.9 2,694,000 2,518,1271944Prospect No. 4 2630 15
0.80 0.4 1,006,000 1,137,6971926Sand Cove 16
1.00 1.2 4,591,000 1,955,1561895Stairs 597 17
0.50 0.2 794,000 897,1541920Veyo 18
0.74 0.1 647,000 1,232,1151986Viva Naughton 19
1.10 1.1 5,078,000 4,936,7551921Wallowa Falls 308 20
3.85 2.0 12,750,000 3,888,6071911Weber 1744 21
0.60 -53,000 577,6061908West Side 2082 22
7,698,160Keno Regulating Dam 2082 23
3,852,038Upper Klamath Lake 2082 24
18,404,715North Umpqua 1927 25
26
Pumping Plant: 27
-2.80 -2.8 -3,104,000 19,543,1861917Lifton 28
29
Wind: 30
198.88 188.0 64,482,000 251,488,4902020Cedar Springs II 31
136.90 112.0 388,242,000 218,133,2962010Dunlap Ranch 1 32
250.90 166.0 36,054,000 322,708,3482020Ekola Flats 33
48.00 34.0 49,196,000 49,941,8171999Foote Creek I 34
119.30 109.0 402,769,000 192,470,1902008Glenrock 35
46.00 44.0 154,628,000 81,413,2902009Glenrock III 36
103.40 94.0 326,832,000 154,831,8552008Goodnoe Hills 37
122.10 105.0 358,815,000 189,706,5782009High Plains 38
110.38 100.0 316,368,000 177,133,6382006Leaning Juniper 1 39
156.00 153.0 448,708,000 213,209,2832007Marengo 40
78.00 77.0 200,122,000 110,736,7322008Marengo II 41
35.15 33.0 109,272,000 52,683,3832009McFadden Ridge I 42
239.80 50.0 161,000 58,644,3432020Pryor Mountain 43
115.80 108.0 363,221,000 196,906,6542009Rolling Hills 44
122.10 109.0 427,856,000 188,317,8802008Seven Mile Hill 45
24.05 23.0 90,796,000 38,524,7552008Seven Mile Hill II 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 / /2020/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
117,133 4,957,719 2Water 465,553
3,660 3,080,788 3Water 89,758
89,038 2,650,237 4Water 273,165
114,211 993,211 5Water 283,237
2,895 542,714 6Water 55,043
99,119 1,141,015 7Water 135,466
52,292 2,632,749 8Water 243,109
26,284 909,315 9Water 34,861
17,996 1,834,391 10Water 194,650
12,773 638,560 11Water 92,036
109,564 2,433,908 12Water 445,620
82,159 1,421,397 13Water 115,822
186,301 1,326,029 14Water 438,278
17,729 2,518,127 15Water 42,696
28,760 1,422,121 16Water 61,613
3,490 1,955,156 17Water 208,805
226,707 1,794,308 18Water 48,177
22,998 1,665,020 19Water 123,907
7,367 4,487,959 20Water 250,720
21,949 1,010,028 21Water 293,145
3,280 962,677 22Water 11,016
23 11,338
33,076,977 24 268,654
25
26
27
46,040 -6,979,709 28Water 236,097
29
30
87,864 1,264,524 31Wind 140,813
1,011,662 1,593,377 32Wind 201,648
8,679 1,286,203 33Wind 159,048
618,314 1,040,455 34Wind 445,050
1,402,700 1,613,329 35Wind 1,515,095
563,020 1,769,854 36Wind 57,764
76,623 1,497,407 37Wind 1,493,976
1,341,011 1,553,698 38Wind 1,110,034
73,208 1,604,762 39Wind 2,167,462
1,156,560 1,366,726 40Wind 1,172,940
573,274 1,419,702 41Wind 585,708
382,269 1,498,816 42Wind 312,109
2,888 244,555 43Wind 12,610
1,345,498 1,700,403 44Wind 149,741
257,538 1,542,325 45Wind 568,809
52,028 1,601,861 46Wind 117,764
FERC FORM NO. 1 (REV. 12-03) Page 411
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
GENERATING PLANT STATISTICS (Small Plants)
PacifiCorp X / /2020/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.
247.30 183.0 30,117,000 248,540,7532020TB Flats 1
2
Solar: 3
2.00 2.0 3,553,000 74,9862012Black Cap 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03) Page 410.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
GENERATING PLANT STATISTICS (Small Plants) (Continued)
PacifiCorp X / /2020/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
1,028 1,005,017 1Wind 128,627
2
3
37,493 4Solar 450,617
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03) Page 411.1
Schedule Page: 410 Line No.: 1 Column: a
Common river system costs for the operation of these facilities are allocated to each
plant based upon the unit’s name plate rating.
This footnote applies to all hydroelectric generating facilities with current generation.
All or some of the renewable energy attributes associated with generation from these
generating facilities may be: (a) used in future years to comply with renewable portfolio
standards or other regulatory requirements or (b) sold to third parties in the form of
renewable energy credits or other environmental commodities.
Schedule Page: 410 Line No.: 6 Column: a
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
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.
Schedule Page: 410 Line No.: 23 Column: a
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
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
Represents facilities that support the North Umpqua River system projects. All common
roads, employee houses, control equipment, etc. are included in this account.
Schedule Page: 410 Line No.: 28 Column: a
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: 410.1 Line No.: 4 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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
/ /2020/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.
1
Steel Tower 500.00 500.00 138.00 1 2 AEOLUS, WY ANTICLINE, WY
Steel Tower 500.00 500.00 58.00 1 3 ALVEY, OR DIXONVILLE 500kV, OR
Steel Tower 500.00 500.00 112.00 1 4 BROADVIEW, MT COLSTRIP A, MT
Steel Tower 500.00 500.00 116.00 1 5 BROADVIEW, MT COLSTRIP B, MT
Steel Tower 500.00 500.00 133.00 1 6 BROADVIEW, MT TOWNSEND A, MT
Steel Tower 500.00 500.00 133.00 1 7 BROADVIEW, MT TOWNSEND B, MT
Steel Tower 500.00 500.00 7.00 1 8 CAPTAIN JACK, OR MALIN, OR
Steel Tower 500.00 500.00 1.00 1 9 COLSTRIP 4, MT COLSTRIP, MT
Steel Tower 500.00 500.00 74.00 1 10 DIXONVILLE, OR MERIDIAN, OR
Steel Tower 500.00 500.00 242.00 1 11 HEMINGWAY, ID SUMMER LAKE, OR
Steel Tower 500.00 500.00 2.00 1 12 KLAMATH CO-GEN, OR SNOW GOOSE, OR
Steel Tower 500.00 500.00 47.00 1 13 MALIN, OR INDIAN SPRINGS, CA
Steel Tower 500.00 500.00 58.00 1 14 MERIDIAN, OR KLAMATH CO-GEN, OR
Steel Tower 500.00 500.00 130.00 1 15 MIDPOINT, ID HEMINGWAY, ID
Steel Tower 500.00 500.00 24.00 1 16 SNOW GOOSE, OR CAPTAIN JACK, OR
Steel Tower 500.00 500.00 75.00 1 17 SUMMER LAKE, OR MALIN, OR
18 500kV costs and expenses
1,350.00 16 19 Subtotal 500kV
20
Steel - SP 345.00 345.00 11.00 1 21 90TH SOUTH, UT CAMP WILLIAMS #3, UT
Steel - SP 345.00 345.00 11.00 1 22 90TH SOUTH, UT CAMP WILLIAMS #4, UT
Steel - SP 345.00 345.00 11.00 1 23 90TH SOUTH, UT CAMP WILLIAMS #1, UT
Steel - SP 345.00 345.00 16.00 1 24 90TH SOUTH, UT TERMINAL, UT
Steel - H 345.00 345.00 5.00 1 25 ANTICLINE, WY JIM BRIDGER, WY
Steel - SP 345.00 345.00 82.00 1 26 BEN LOMOND, UT POPULUS #1, ID
Steel - SP 345.00 345.00 86.00 1 27 BEN LOMOND, UT POPULUS #2, ID
Steel - SP 345.00 345.00 69.00 1 28 BEN LOMOND, UT CAMP WILLIAMS, UT
Steel - SP 345.00 345.00 47.00 1 29 BEN LOMOND, UT TERMINAL #2, UT
Steel - SP 345.00 345.00 47.00 1 30 BEN LOMOND, UT TERMINAL #1, UT
Wood - H 345.00 345.00 83.00 1 31 BORAH, ID MIDPOINT #1, ID
Wood - H 345.00 345.00 78.00 1 32 BORAH, ID MIDPOINT #2, ID
Wood - H 345.00 345.00 47.00 1 33 CAMP WILLIAMS, UT MONA #3, UT
Wood - H 345.00 345.00 47.00 1 34 CAMP WILLIAMS, UT MONA #1, UT
Steel Tower 345.00 345.00 47.00 1 35 CAMP WILLIAMS, UT MONA #2, UT
FERC FORM NO. 1 (ED. 12-87) Page 422
36 TOTAL 17,272.00 656.00 308
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
/ /2020/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.
1
3-1272 ACSR 45/7 2
3-2250 AAC /91 3
795 ACSR 26/7 4
795 ACSR 26/7 5
795 ACSR 26/7 6
795 ACSR 26/7 7
3-1272 ACSR 36/1 8
795 ACSR 26/7 9
3-1272 ACSR 36/1 10
3-1272 ACSR 36/1 11
3-1272 ACSR 54/19 12
3-1852 ACSR 51/27 13
3-1272 ACSR 54/19 14
3-1272 ACSR 36/1 15
3-1272 ACSR 54/19 16
3-1272 ACSR 36/1 17
264,992,606 237,076,901 27,915,705 1,667,620 324,703 1,337,812 5,105 18
264,992,606 237,076,901 27,915,705 1,667,620 324,703 1,337,812 5,105 19
20
21
22
1272 ACSR 45/7 23
1272 ACSR 45/7 24
3-1272 ACSR 45/7 25
1272 ACSR 45/7 26
1272 ACSR 45/7 27
1272 ACSR 45/7 28
1272 ACSR 45/7 29
1272 ACSR 45/7 30
1272 ACSR 45/7 31
1272 ACSR 45/7 32
954 ACSR 45/7 33
1272 ACSR 45/7 34
954 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423
36 274,562,517 3,717,200,904 3,991,763,421 1,038,503 16,623,016 2,217,342 19,878,861
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
/ /2020/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Steel Tower 345.00 345.00 42.00 5.00 1 1 CAMP WILLIAMS, UT MONA #4 UT
Steel Tower 345.00 345.00 100.00 1 2 CLOVER, UT OQUIRRH, UT
Steel - SP 345.00 345.00 1.00 1 3 CURRANT CREEK, UT MONA, UT
Steel Tower 345.00 345.00 121.00 1 4 EMERY, UT CAMP WILLIAMS, UT
Wood - H 345.00 345.00 20.00 1 5 EMERY, UT HUNTINGTON, UT
Steel - H 345.00 345.00 74.00 1 6 EMERY, UT SIGURD #1, UT
Steel - H 345.00 345.00 75.00 1 7 EMERY, UT SIGURD #2, UT
Wood - H 345.00 345.00 101.00 1 8 FOUR CORNERS, NM PINTO, UT
Wood - H 345.00 345.00 41.00 1 9 GOSHEN, ID KINPORT, ID
Steel Tower 345.00 345.00 1.00 1 10 HUNTINGTON, UT HUNT PLANT 1, UT
Steel Tower 345.00 345.00 1.00 1 11 HUNTINGTON, UT HUNT PLANT 2, UT
Steel - SP 345.00 345.00 158.00 1 12 HUNTINGTON, UT PINTO, UT
Steel Tower 345.00 345.00 78.00 1 13 HUNTINGTON, UT SPANISH FORK, UT
Steel Tower 345.00 345.00 220.00 1 14 JIM BRIDGER, WY GOSHEN, ID
Steel Tower 345.00 345.00 240.00 1 15 JIM BRIDGER, WY BORAH, ID
Steel - SP 345.00 345.00 234.00 1 16 JIM BRIDGER, WY KINPORT, ID
Steel - SP 345.00 345.00 113.00 1 17 KINPORT, ID MIDPOINT, ID
Wood - H 345.00 345.00 69.00 1 18 MONA, UT SIGURD #1, UT
Steel - SP 345.00 345.00 69.00 1 19 MONA, UT SIGURD #2, UT
Steel - SP 345.00 345.00 60.00 1 20 MONA, UT HUNTINGTON, UT
Steel - H 345.00 345.00 170.00 1 21 RED BUTTE, UT SIGURD, UT
Steel Tower 345.00 345.00 190.00 1 22 SIGURD, UT UT-NV STATE LINE
Steel - SP 345.00 345.00 35.00 1 23 SPANISH FORK, UT CAMP WILLIAMS, UT
Wood - H 345.00 345.00 138.00 1 24 TERMINAL, UT BORAH, ID
Steel - SP 345.00 345.00 47.00 1 25 TERMINAL, UT BORAH, ID
Steel - SP 345.00 345.00 10.00 16.00 1 26 TERMINAL, UT CAMP WILLIAMS #2, UT
Steel Tower 345.00 345.00 23.00 1 27 TERMINAL, UT CAMP WILLIAMS, UT
28 345kV costs and expenses
382.00 2,757.00 42 29 Subtotal 345kV
30
Steel - H 230.00 230.00 1.00 1 31 AEOLUS, WY EKOLA FLATS, WY
Steel - H 230.00 230.00 4.00 1 32 AEOLUS, WY FREEZEOUT, WY
Steel - H 230.00 230.00 17.00 1 33 AEOLUS, WY SHIRLEY BASIN #1, WY
Steel - H 230.00 230.00 16.00 1 34 AEOLUS, WY SHIRLEY BASIN #2, WY
Wood - H 230.00 230.00 59.00 1 35 ALVEY, OR DIXONVILLE, OR
FERC FORM NO. 1 (ED. 12-87) Page 422.1
36 TOTAL 17,272.00 656.00 308
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
/ /2020/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
1949 ACSR 45/7 2
954 ACSR 54/7 3
1272 ACSR 45/7 4
954 ACSR 45/7 5
954 ACSR 45/7 6
954 ACSR 54/7 7
795 ACSR 45/7 8
795 ACSR/SD 22/7 9
2156 ACSR 8419 10
2156 ACSR 8419 11
795 ACSR 45/7 12
1272 ACSR 45/7 13
1272 ACSR 36/1 14
1272 ACSR 36/1 15
1272 ACSR 36/1 16
1272 ACSR 45/7 17
795 ACSR 45/7 18
954 ACSR 45/7 19
954 ACSR 54/7 20
2-954 ACSR 45/7 21
954 ACSR 54/7 22
1272 ACSR 45/7 23
2-954 ACSR 45/7 24
2-1272 ACSR 45/7 25
1272 ACSR 45/7 26
1272 ACSR 45/7 27
1,826,818,614 1,670,749,493 156,069,121 2,623,556 658,933 1,919,135 45,488 28
1,826,818,614 1,670,749,493 156,069,121 2,623,556 658,933 1,919,135 45,488 29
30
795 ACSR 26/7 31
1272 ACSR 45/7 32
1158.4 ACSS 25/7 33
1158.4 ACSS 25/7 34
1272 ACSR 36/1 35
FERC FORM NO. 1 (ED. 12-87) Page 423.1
36 274,562,517 3,717,200,904 3,991,763,421 1,038,503 16,623,016 2,217,342 19,878,861
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
/ /2020/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 76.00 1 1 ANTELOPE, ID ANACONDA, MT
Wood - H 230.00 230.00 20.00 1 2 ANTELOPE, ID LOST RIVER, ID
Wood - H 230.00 230.00 9.00 1 3 ARROWHEAD, WY FIREHOLE, WY
Wood - H 230.00 230.00 1.00 1 4 ATLANTIC CITY, WY COLUMBIA GENEVA, WY
Wood - H 230.00 230.00 88.00 1 5 BEN LOMOND, UT NAUGHTON #1, WY
Wood - H 230.00 230.00 88.00 1 6 BEN LOMOND, UT NAUGHTON #2, WY
Wood - H 230.00 230.00 19.00 1 7 BIRCH CREEK, UT RAILROAD, WY
Wood - H 230.00 230.00 3.00 1 8 BITTER CREEK, WY MONELL, WY
Wood - H 230.00 230.00 1.00 1 9 BRIDGER PUMP, WY MANS FACE, WY
Wood - H 230.00 230.00 107.00 1 10 BUFFALO, WY CASPER, WY
Wood - H 230.00 230.00 36.00 1 11 CASPER, WY DAVE JOHNSTON, WY
Wood - H 230.00 230.00 110.00 1 12 CASPER, WY RIVERTON, WY
Steel - SP 230.00 230.00 30.00 1 13 CHAPPEL CREEK, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 32.00 1 14 CHAPPEL CREEK, WY JONAH GAS, WY
Wood - H 230.00 230.00 6.00 29.00 1 15 CHAPPEL CREEK, WY RILEY RIDGE, WY
Wood - H 230.00 230.00 9.00 1 16 CORRAL, OR OCHOCO #1, OR
Wood - H 230.00 230.00 10.00 1 17 CORRAL, OR OCHOCO #2, OR
Wood - H 230.00 230.00 2.00 1 18 CRAVEN CREEK, WY PIONEER, WY
Wood - H 230.00 230.00 31.00 1 19 DAVE JOHNSTON, WY SPENCE, WY
Wood - H 230.00 230.00 69.00 1 20 DAVE JOHNSTON, WY WYODAK, WY
Wood - H 230.00 230.00 1.00 1 21 DIXONVILLE 500kV, OR DIXONVILLE 230kV, OR
Wood - H 230.00 230.00 17.00 1 22 DIXONVILLE, OR RESTON (BPA), OR
Wood - H 230.00 230.00 12.00 1 23 FAIRVIEW (BPA), OR ISTHMUS, OR
Wood - H 230.00 230.00 49.00 1 24 FIREHOLE, WY MONUMENT, WY
Steel - SP 230.00 230.00 1.00 2 25 FRIEND, OR OCHOCO #1, OR
Steel - SP 230.00 230.00 1.00 2 26 FRIEND, OR OCHOCO #2, OR
Wood - H 230.00 230.00 26.00 1 27 FRY, OR BETHEL, OR
Wood - H 230.00 230.00 45.00 1 28 FRY, OR ALVEY, OR
Wood - H 230.00 230.00 159.00 1 29 GLEN CANYON, AZ SIGURD, UT
Wood - H 230.00 230.00 98.00 1 30 GONDER, UT-NV STATE PAVANT, UT
Wood - H 230.00 230.00 62.00 1 31 DIXONVILLE, OR GRANTS PASS, OR
Wood - H 230.00 230.00 38.00 1 32 HIGH PLAINS, WY STANDPIPE, WY
Wood - H 230.00 230.00 78.00 1 33 HURRICANE, OR WALLA WALLA, WA
Wood - H 230.00 230.00 35.00 1 34 JIM BRIDGER, WY ROCK SPRINGS, WY
Wood - H 230.00 230.00 149.00 1 35 JIM BRIDGER, WY SPENCE, WY
FERC FORM NO. 1 (ED. 12-87) Page 422.2
36 TOTAL 17,272.00 656.00 308
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
/ /2020/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
1272 ACSR 45/7 1
795 ACSR 45/7 2
795 ACSR 26/7 3
1272 ACSR 36/1 4
795 ACSR 26/7 5
795 ACSR 26/7 6
954 ACSR 54/7 7
795 ACSR 26/7 8
1272 ACSR 36/1 9
1272 ACSR 36/1 10
11
1272 ACSR 36/1 12
954 ACSR 54/7 13
1272 ACSR 45/7 14
1272 ACSR 45/7 15
16
17
1272 ACSR 45/7 18
1272 ACSR 45/7 19
1272 ACSR 36/1 20
1272 ACSR 36/1 21
795 ACSR 26/7 22
1272 ACSR 36/1 23
1272 ACSR 45/7 24
25
26
1272 ACSR 36/1 27
1272 ACSR 36/1 28
954 ACSR 45/7 29
795 ACSR 45/7 30
1272 ACSR 36/1 31
1272 ACSR 45/7 32
1272 ACSR 36/1 33
1272 ACSR 45/7 34
1272 ACSR 36/1 35
FERC FORM NO. 1 (ED. 12-87) Page 423.2
36 274,562,517 3,717,200,904 3,991,763,421 1,038,503 16,623,016 2,217,342 19,878,861
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
/ /2020/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 36.00 1 1 KLAMATH FALLS, OR MALIN, OR
Wood - H 230.00 230.00 2.00 1 2 LIMA, WY ROBERTSON CREEK, WY
Wood - H 230.00 230.00 76.00 1 3 LONE PINE, OR KLAMATH FALLS, OR
Steel - SP 230.00 230.00 5.00 1 4 LONE PINE, OR MERIDIAN #1, OR
Steel - SP 230.00 230.00 5.00 1 5 LONE PINE, OR MERIDIAN #2, OR
Wood - H 230.00 230.00 56.00 1 6 MCNARY (BPA), OR WALLA WALLA, WA
Wood - H 230.00 230.00 29.00 1 7 MCNARY (BPA), OR WALLULA, WA
Wood - H 230.00 230.00 35.00 1 8 MERIDIAN, OR GRANTS PASS, OR
Wood - H 230.00 230.00 13.00 1 9 MONUMENT, WY EXXON, WY
Wood - H 230.00 230.00 20.00 1 10 MONUMENT, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 80.00 1 11 NAUGHTON, WY TREASURETON, ID
Wood - H 230.00 230.00 30.00 1 12 NAUGHTON, WY MONUMENT, WY
Wood - H 230.00 230.00 16.00 1 13 NAUGHTON, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 4.00 1 14 PALISADES SS, WY BLUE RIM, WY
Wood - H 230.00 230.00 94.00 1 15 PAROWAN VALLEY, UT SIGURD, UT
Wood - H 230.00 230.00 26.00 1 16 PAROWAN VALLEY, UT WEST CEDAR, UT
Wood - H 230.00 230.00 43.00 1 17 PAVANT, UT SIGURD, UT
Wood - H 230.00 230.00 209.00 1 18 POINT OF ROCKS, WY DAVE JOHNSTON, WY
Wood - H 230.00 230.00 40.00 1 19 POMONA, WA VANTAGE, WA
Wood - H 230.00 230.00 7.00 1 20 POMONA, WA UNION GAP, WA
Wood - H 230.00 230.00 118.00 1 21 RIVERTON, WY ROCK SPRINGS, WY
Wood - H 230.00 230.00 51.00 1 22 RIVERTON, WY THERMOPOLIS, WY
Wood - H 230.00 230.00 55.00 1 23 ROCK SPRINGS, WY FLAMING GORGE, UT
Wood - H 230.00 230.00 35.00 1 24 ROCK SPRINGS, WY JIM BRIDGER, WY
Wood - H 230.00 230.00 41.00 1 25 ROCK SPRINGS, WY MONUMENT, WY
Wood - H 230.00 230.00 40.00 1 26 SHERIDAN (MDU), WY BUFFALO, WY
Wood - H 230.00 230.00 62.00 1 27 SHERIDAN (MDU), WY YELLOWTAIL, MT
Wood - H 230.00 230.00 12.00 1 28 SHIRLEY BASIN, WY DUNLAP RANCH, WY
Wood - H 230.00 230.00 2.00 1 29 SWIFT NO. 1, WA SWIFT NO. 2, WA
Wood - H 230.00 230.00 23.00 1 30 SWIFT NO. 2, WA WOODLAND (BPA) SS, WA
Wood - H 230.00 230.00 7.00 1 31 TALBOT, WA MARENGO II, WA
Wood - H 230.00 230.00 9.00 1 32 TAP TO HANNA, OR NICKEL MOUNTAIN, OR
Wood - H 230.00 230.00 176.00 1 33 THERMOPOLIS, WY YELLOWTAIL, MT
Wood - H 230.00 230.00 66.00 1 34 TREASURETON, ID BRADY, ID
Steel Tower 230.00 230.00 6.00 1 35 TROUTDALE (BPA), OR GRESHAM (PGE), OR
FERC FORM NO. 1 (ED. 12-87) Page 422.3
36 TOTAL 17,272.00 656.00 308
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
/ /2020/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 45/7 2
795 ACSR 26/7 3
1272 ACSR 54/19 4
1272 ACSR 36/1 5
1272 ACSR 36/1 6
7
1272 ACSR 36/1 8
1272 ACSR 36/1 9
1272 ACSR 45/7 10
1272 ACSR 45/7 11
1272 ACSR 36/1 12
954 ACSR 54/7 13
1272 ACSR 36/1 14
795 ACSR 45/7 15
795 ACSR 45/7 16
795 ACSR 45/7 17
1272 ACSR 36/1 18
1272 ACSR 45/7 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 36/1 25
795 ACSR 26/7 26
795 ACSR 26/7 27
795 ACSR 26/7 28
954 ACSR 45/7 29
954 ACSR 45/7 30
795 ACSR 26/7 31
795 ACSR 26/7 32
1272 ACSR 36/1 33
795 ACSR 26/7 34
954 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.3
36 274,562,517 3,717,200,904 3,991,763,421 1,038,503 16,623,016 2,217,342 19,878,861
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
/ /2020/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 230.00 230.00 7.00 1 1 TROUTDALE (BPA), OR LINNEMAN (PGE), OR
Wood - H 230.00 230.00 39.00 1 2 UNION GAP, WA MIDWAY (BPA), WA
Wood - H 230.00 230.00 45.00 1 3 WALLA WALLA, WA LEWISTON (AVISTA), ID
Wood - H 230.00 230.00 33.00 1 4 WALLA WALLA, WA WANAPUM (GPUD), WA
Wood - H 230.00 230.00 37.00 1 5 WANAPUM (GPUD), WA POMONA, WA
Wood - H 230.00 230.00 13.00 1 6 WINDSTAR, WY GLENROCK, WY
Wood - H 230.00 230.00 69.00 1 7 WYODAK, WY BUFFALO, WY
Wood - H 230.00 230.00 63.00 1 8 YAMSAY (BPA), OR KLAMATH FALLS, OR
9 230kV costs and expenses
14.00 3,465.00 85 10 Subtotal 230kV
11
Wood - H 161.00 161.00 45.00 1 12 ANTELOPE, ID GOSHEN, ID
Wood - H 161.00 161.00 21.00 1 13 BIG GRASSY, ID JEFFERSON, ID
Wood - SP 161.00 161.00 9.00 1 14 BONNEVILLE, ID EAGLEROCK, ID
Wood - H 161.00 161.00 15.00 1 15 EAGLEROCK, ID GOSHEN, ID
Wood - SP 161.00 161.00 15.00 1 16 GOSHEN, ID AMMON, ID
Wood - H 161.00 161.00 57.00 1 17 GOSHEN, ID GRACE, ID
Wood - H 161.00 161.00 30.00 1 18 GOSHEN, ID JEFFERSON, ID
Wood - H 161.00 161.00 31.00 1 19 GOSHEN, ID RIGBY, ID
Wood - SP 161.00 161.00 17.00 1 20 GOSHEN, ID SUGAR MILL, ID
Wood - SP 161.00 161.00 12.00 1 21 REXBURG, ID RIGBY, ID
Wood - SP 161.00 161.00 18.00 1 22 RIGBY, ID JEFFERSON, ID
Wood - SP 161.00 161.00 17.00 1 23 SUGARMILL, ID RIGBY, ID
Wood - H 161.00 161.00 46.00 1 24 YELLOWTAIL, MT RIMROCK, MT
25 161kV costs and expenses
51.00 282.00 13 26 Subtotal 161kV
27
Wood - H 138.00 138.00 12.00 1 28 90TH SOUTH, UT DUMAS #1, UT
Wood - H 138.00 138.00 6.00 1 29 90TH SOUTH, UT DUMAS #2, UT
Wood - SP 138.00 138.00 10.00 1 30 90TH SOUTH, UT OQUIRRH, UT
Steel - SP 138.00 138.00 1.00 1 31 90TH SOUTH, UT SANDY, UT
Wood - H 138.00 138.00 44.00 1 32 ABAJO, UT PINTO, UT
Wood - SP 138.00 138.00 10.00 1 33 ABAJO, UT SAN JUAN, UT
Wood - H 138.00 138.00 4.00 1 34 AGRIUM, UT THREEMILE KNOLL, ID
Wood - H 138.00 138.00 22.00 1 35 ANSCHTZ CO-GEN, WY EVANSTON, WY
FERC FORM NO. 1 (ED. 12-87) Page 422.4
36 TOTAL 17,272.00 656.00 308
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
/ /2020/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.
900 ACSR 54/7 1
954 ACSR 45/7 2
1272 ACSR 36/1 3
1272 ACSR 36/1 4
1272 ACSR 36/1 5
1272 ACSR 45/7 6
1272 ACSR 36/1 7
795 ACSR 26/7 8
517,186,910 487,390,834 29,796,076 3,149,524 504,375 2,482,412 162,737 9
517,186,910 487,390,834 29,796,076 3,149,524 504,375 2,482,412 162,737 10
11
397.5 ACSR 26/7 12
250HH CU /7 13
954 ACSR 45/7 14
1272 ACSR 45/7 15
16
250HH CU /7 17
250HH CU /7 18
397.5 ACSR 26/7 19
795 AAC /37 20
1272 ACSR 45/7 21
397.5 ACSR 26/7 22
397.5 ACSR 26/7 23
556.5 ACSR 26/7 24
42,610,693 41,949,470 661,223 302,703 7,623 281,258 13,822 25
42,610,693 41,949,470 661,223 302,703 7,623 281,258 13,822 26
27
795 AAC /37 28
795 AAC /37 29
795 ACSR 26/7 30
795 AAC /37 31
397.5 ACSR 26/7 32
795 ACSR 26/7 33
397.5 ACSR 26/7 34
795 ACSR 26/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.4
36 274,562,517 3,717,200,904 3,991,763,421 1,038,503 16,623,016 2,217,342 19,878,861
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
/ /2020/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 1.00 1 1 ANTELOPE, ID SCOVILLE #1, ID
Wood - H 138.00 138.00 1.00 1 2 ANTELOPE, ID SCOVILLE #2, ID
Wood - H 138.00 138.00 26.00 1 3 ASHGROVE, UT CLOVER, UT
Wood - H 138.00 138.00 102.00 1 4 ASHLEY, UT CARBON, UT
Wood - H 138.00 138.00 12.00 1 5 ASHLEY, UT VERNAL, UT
Wood - H 138.00 138.00 6.00 1 6 BANGERTER, UT OQUIRRH, UT
Wood - SP 138.00 138.00 1.00 1 7 BARNEYS, UT GRINDING, UT
Wood - SP 138.00 138.00 1.00 1 8 BDO, UT BDO TAP, UT
Steel - SP 138.00 138.00 27.00 1 9 BEN LOMOND, UT ANGEL, UT
Wood - H 138.00 138.00 14.00 1 10 BEN LOMOND, UT BRIGHAM CITY, UT
Steel - SP 138.00 138.00 14.00 1 11 BEN LOMOND #1, UT EL MONTE, UT
Wood - H 138.00 138.00 13.00 1 12 BEN LOMOND #2, UT EL MONTE, UT
Steel Tower 138.00 138.00 22.00 1 13 BEN LOMOND, UT HONEYVILLE, UT
Steel Tower 230.00 138.00 13.00 7.00 1 14 BEN LOMOND, UT SYRACUSE #1, UT
Steel Tower 138.00 138.00 58.00 1 15 BEN LOMOND, UT SYRACUSE, UT
Wood - SP 138.00 138.00 14.00 1 16 BEN LOMOND, UT W ZIRCONIUM, UT
Steel Tower 138.00 138.00 42.00 1 17 BEN LOMOND, UT WHEELON, UT
Wood - H 138.00 138.00 9.00 1 18 BONANZA, UT CHAPITA, UT
Wood - SP 138.00 138.00 16.00 1 19 BRIDGERLAND, UT GREEN CANYON, UT
Wood - H 138.00 138.00 24.00 1 20 BRIGHAM CITY, UT WHEELON, UT
Steel - SP 138.00 138.00 9.00 1 21 BUTLERVILLE, UT 90TH SOUTH, UT
Wood - SP 138.00 138.00 25.00 1 22 CAMERON, UT MILFORD, UT
Wood - H 138.00 138.00 35.00 1 23 CAMERON, UT PAROWAN, UT
Wood - H 138.00 138.00 65.00 1 24 CAMERON, UT SIGURD, UT
Wood - H 138.00 138.00 12.00 1 25 CANYON COMP, WY STR 204, WY
Wood - H 138.00 138.00 2.00 1 26 CARBON, UT HELPER #2, UT
Wood - H 138.00 138.00 120.00 1 27 CARBON, UT MOAB, UT
Steel Tower 138.00 138.00 54.00 1 28 CARBON, UT SPANISH FORK #1, UT
Steel Tower 138.00 138.00 52.00 1 29 CARBON, UT SPANISH FORK #2, UT
Steel - SP 138.00 138.00 20.00 1 30 CENTRAL (UAMPS) #2, UT SAINT GEORGE, UT
Steel - SP 138.00 138.00 20.00 1 31 CENTRAL (UAMPS) #3, UT SAINT GEORGE, UT
Wood - SP 138.00 138.00 5.00 1 32 CLEAR CREEK, WY PAINTER, UT
Wood - SP 138.00 138.00 2.00 1 33 CLOVER, UT BURRASTON PONDS, UT
Wood - SP 138.00 138.00 8.00 1 34 CLOVER, UT NEBO, UT
Wood - H 138.00 138.00 2.00 1 35 COLUMBIA, UT SUNNYSIDE, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.5
36 TOTAL 17,272.00 656.00 308
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
/ /2020/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
397.5 ACSR 26/7 3
397.5 ACSR 26/7 4
397.5 ACSR 26/7 5
6
7
397.5 ACSR 26/7 8
397.5 ACSR 26/7 9
1272 ACSR 45/7 10
795 ACSR 45/7 11
795 ACSR 45/7 12
250 CUHD /12 13
795 AAC /37 14
1272 ACSR 45/7 15
795 AAC /37 16
250 CUHD /12 17
795 ACSR 26/7 18
1272 ACSR 45/7 19
795 ACSR 26/7 20
795 AAC /37 21
397.5 ACSR 26/7 22
397.5 ACSR 26/7 23
397.5 ACSR 26/7 24
795 ACSR 26/7 25
556.5 ACSR 26/7 26
954 ACSR 54/7 27
795 ACSR 26/7 28
1272 ACSR 45/7 29
1272 ACSR 45/7 30
1272 ACSR 45/7 31
795 ACSR 26/7 32
397.5 ACSR 26/7 33
1272 ACSR 45/7 34
397.5 ACSR 26/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.5
36 274,562,517 3,717,200,904 3,991,763,421 1,038,503 16,623,016 2,217,342 19,878,861
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
/ /2020/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 5.00 1 1 COTTONWOOD, UT HAMMER, UT
Steel - SP 138.00 138.00 6.00 1 2 COTTONWOOD, UT MCCLELLAND, UT
Wood - SP 138.00 138.00 30.00 1 3 COTTONWOOD, UT SILVER CREEK, UT
Wood - SP 138.00 138.00 1 4 CUTLER, UT WHEELON, UT
Steel - SP 138.00 138.00 5.00 1 5 DRY CREEK, UT SPANISH FORK, UT
Wood - SP 138.00 138.00 19.00 1 6 DUMAS, UT WESTFIELD, UT
Steel - SP 138.00 138.00 2.00 1 7 DYNAMO, UT TRI-CITY #1, UT
Steel - SP 138.00 138.00 3.00 1 8 DYNAMO, UT TRI-CITY #2, UT
Wood - SP 138.00 138.00 10.00 1 9 EAGLE MOUNTAIN, UT PONY EXPRESS, UT
Steel - SP 138.00 138.00 15.00 1 10 EAST LAYTON, UT 105 TAP, UT
Wood - SP 138.00 138.00 1.00 1 11 EBAY TAP, UT OQUIRRH, UT
Steel - SP 138.00 138.00 1.00 1 12 EL MONTE, UT PIONEER, UT
Steel - SP 138.00 138.00 4.00 1 13 EL MONTE, UT EAST BANK, UT
Wood - SP 138.00 138.00 4.00 2 14 EMERY, UT CLAWSON, UT
Wood - SP 138.00 138.00 3.00 1 15 EVANSTON, WY RAILROAD, UT
Wood - SP 138.00 138.00 3.00 1 16 FORT DOUGLAS, UT MCCLELLAND, UT
Wood - SP 138.00 138.00 25.00 1 17 FRANKLIN, ID GREEN CANYON, UT
Wood - SP 138.00 138.00 10.00 1 18 FRANKLIN, ID TREASURETON, ID
Wood - SP 138.00 138.00 1 19 GADSBY, UT JORDAN, UT
Wood - SP 138.00 138.00 6.00 1 20 GADSBY, UT TERMINAL, UT
Wood - SP 138.00 138.00 1.00 1 21 GADSBY, UT THIRD WEST, UT
Wood - SP 138.00 138.00 1.00 1 22 GRAPHITE, UT MOUNTAIN VIEW, UT
Wood - SP 138.00 138.00 7.00 1 23 GREEN CANYON, UT NIBLEY, UT
Wood - SP 138.00 138.00 19.00 1 24 GREEN CANYON, UT WHEELON, UT
Wood - SP 138.00 138.00 3.00 1 25 GRINDING, UT OQUIRRH, UT
Wood - SP 138.00 138.00 14.00 1 26 GRINDING, UT TOOELE, UT
Wood - H 138.00 138.00 19.00 1 27 HALE, UT MIDWAY, UT
Wood - H 138.00 138.00 18.00 1 28 HALE, UT SPANISH FORK, UT
Wood - H 138.00 138.00 7.00 1 29 HALE, UT TANNER, UT
Wood - SP 138.00 138.00 2.00 1 30 HAMMER, UT BUTLERVILLE, UT
Wood - SP 138.00 138.00 5.00 1 31 HIGHLAND, UT BULL RIVER (LEHI #5), UT
Wood - H 138.00 138.00 25.00 1 32 HONEYVILLE, UT LAMPO, UT
Steel Tower 138.00 138.00 14.00 1 33 HONEYVILLE, UT WHEELON, UT
Wood - H 138.00 138.00 7.00 1 34 HUNTINGTON, UT MCFADDEN, UT
Wood - H 138.00 138.00 26.00 1 35 JERUSALEM, UT NEBO, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.6
36 TOTAL 17,272.00 656.00 308
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
/ /2020/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
795 AAC /37 1
795 AAC /37 2
397.5 ACSR 26/7 3
250 CUHD /12 4
1272 ACSR 45/7 5
795 ACSR 26/7 6
795 ACSR 26/7 7
795 ACSR 26/7 8
795 ACSR 26/7 9
795 ACSR 26/7 10
795 ACSR 26/7 11
1272 ACSR 45/7 12
1272 ACSR 45/7 13
397.5 ACSR 26/7 14
795 ACSR 26/7 15
16
397.5 ACSR 26/7 17
795 ACSR 26/7 18
1272 ACSR 45/7 19
1272 ACSR 45/7 20
21
397.5 ACSR 26/7 22
1272 ACSR 45/7 23
397.5 ACSR 26/7 24
795 ACSR 45/7 25
795 ACSR 45/7 26
397.5 ACSR 26/7 27
1272 ACSR 45/7 28
1272 ACSR 45/7 29
795 ACSR 26/7 30
1272 ACSR 45/7 31
397.5 ACSR 26/7 32
250 CUHD /12 33
397.5 ACSR 26/7 34
397.5 ACSR 26/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.6
36 274,562,517 3,717,200,904 3,991,763,421 1,038,503 16,623,016 2,217,342 19,878,861
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
/ /2020/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 5.00 1 1 JORDAN, UT MCCLELLAND, UT
Wood - SP 138.00 138.00 6.00 1 2 JORDAN, UT TERMINAL, UT
Wood - SP 138.00 138.00 3.00 1 3 JORDAN, UT THIRD WEST, UT
Wood - SP 138.00 138.00 3.00 1 4 KEARNS, UT TAYLORSVILLE, UT
Wood - SP 138.00 138.00 2.00 1 5 KEARNS, UT WEST VALLEY, UT
Steel - SP 138.00 138.00 8.00 1 6 LONE PEAK, UT CAMP WILLIAMS, UT
Wood - SP 138.00 138.00 6.00 1 7 MCCLELLAND, UT MIDVALLEY, UT
Wood - H 138.00 138.00 11.00 1 8 MCFADDEN, UT BLACKHAWK, UT
Wood - H 138.00 138.00 9.00 1 9 MID VALLEY, UT 90TH SOUTH, UT
Wood - SP 138.00 138.00 3.00 1 10 MID VALLEY #2, UT COTTONWOOD, UT
Wood - SP 138.00 138.00 5.00 1 11 MID VALLEY #1, UT COTTONWOOD, UT
Wood - SP 138.00 138.00 2.00 4.00 1 12 MID VALLEY, UT TAYLORSVILLE, UT
Wood - H 138.00 138.00 1.00 1 13 MIDDLETON, UT ST. GEORGE, UT
Wood - H 138.00 138.00 68.00 1 14 MOAB, UT PINTO, UT
Wood - H 138.00 138.00 35.00 1 15 NAUGHTON, WY CANYON COMP, WY
Wood - H 138.00 138.00 44.00 1 16 NAUGHTON, WY PAINTER, WY
Wood - H 138.00 138.00 33.00 1 17 NEBO, UT DRY CREEK, UT
Wood - H 138.00 138.00 10.00 1 18 NUCOR STEEL, UT WHEELON, UT
Wood - H 138.00 138.00 23.00 1 19 ONEIDA, ID OVID, UT
Wood - H 138.00 138.00 19.00 1 20 ONIEDA, ID GRACE, ID
Wood - H 138.00 138.00 5.00 1 21 OQUIRRH, UT BARNEY, UT
Wood - H 138.00 138.00 8.00 1 22 OQUIRRH, UT BINGHAM CANYON, UT
Steel - SP 138.00 138.00 23.00 1 23 OQUIRRH, UT TOOELE, UT
Wood - H 138.00 138.00 7.00 1 24 PAINTER, UT RAILROAD, UT
Steel - SP 138.00 138.00 14.00 1 25 PARRISH #105, UT TERMINAL, UT
Wood - H 138.00 138.00 21.00 1 26 PAROWAN, UT WEST CEDAR, UT
Steel - SP 138.00 138.00 8.00 1 27 PARRISH, UT TAP TO N. SALT LAKE, UT
Steel - SP 138.00 138.00 16.00 1 28 PARRISH, UT TERMINAL #1, UT
Steel - SP 138.00 138.00 14.00 1 29 PARRISH, UT TERMINAL #2, UT
Wood - H 138.00 138.00 17.00 1 30 RAILROAD, UT CANYON COMP, WY
Wood - H 138.00 138.00 49.00 1 31 RED BUTTE, UT WEST CEDAR, UT
Steel - SP 138.00 138.00 7.00 1 32 RIVERDALE, UT EAST LAYTON, UT
Wood - H 138.00 138.00 10.00 1 33 SHICK, UT PARRISH, UT
Wood - SP 138.00 138.00 10.00 1 34 SILVER CREEK, UT JORDANELLE, UT
Wood - SP 138.00 138.00 72.00 1 35 SILVER CREEK, UT RAILROAD, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.7
36 TOTAL 17,272.00 656.00 308
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
/ /2020/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
795 AAC /37 1
1272 AAC/91 2
3
795 ACSR 26/7 4
5
1272 ACSR 45/7 6
795 ACSR 26/7 7
795 ACSR 26/7 8
1272 ACSR 45/7 9
10
11
12
397.5 ACSR 26/7 13
397.5 ACSR 26/7 14
795 ACSR 26/7 15
795 ACSR 26/7 16
795 ACSR 26/7 17
397.5 ACSR 26/7 18
336.4 ACSR 26/7 19
250 CUHD /12 20
795 ACSR 26/7 21
22
1272 ACSR 45/7 23
1272 ACSR 45/7 24
795 ACSR 45/7 25
397.5 ACSR 26/7 26
795 ACSR 26/7 27
795 ACSR 45/7 28
795 ACSR 26/7 29
795 ACSR 26/7 30
397.5 ACSR 26/7 31
795 ACSR 26/7 32
250 CUHD /12 33
795 ACSR 26/7 34
1272 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.7
36 274,562,517 3,717,200,904 3,991,763,421 1,038,503 16,623,016 2,217,342 19,878,861
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
/ /2020/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 10.00 1 1 SPANISH FORK, UT TANNER, UT
Wood - SP 138.00 138.00 10.00 2 2 ST. GEORGE, UT PURGATORY FLAT, UT
Wood - SP 138.00 138.00 2.00 1 3 SUNRISE, UT OQUIRRH, UT
Wood - SP 138.00 138.00 7.00 1 4 SYRACUSE, UT ANGEL #1, UT
Steel - SP 138.00 138.00 5.00 1 5 SYRACUSE, UT CLEARFIELD SOUTH, UT
Steel Tower 138.00 138.00 15.00 1 6 SYRACUSE, UT PARRISH, UT
Wood - H 138.00 138.00 4.00 1 7 TAP TO ANGEL NORTH, UT TAP TO PARRISH, UT
Wood - SP 138.00 138.00 2.00 6.00 1 8 TAYLORSVILLE, UT 90TH SOUTH, UT
Steel - SP 138.00 138.00 9.00 1 9 TERMINAL, UT KENNECOTT, UT
Wood - H 138.00 138.00 7.00 1 10 TERMINAL, UT MIDVALLEY #1, UT
Wood - H 138.00 138.00 7.00 1 11 TERMINAL, UT MIDVALLEY #2, UT
Wood - H 138.00 138.00 53.00 1 12 TERMINAL, UT ROWLEY, UT
Wood - H 138.00 138.00 6.00 24.00 1 13 TERMINAL, UT TOOELE, UT
Wood - SP 138.00 138.00 7.00 1 14 TERMINAL, UT WEST VALLEY, UT
Wood - H 138.00 138.00 17.00 1 15 THREEMILE KNOLL, ID GRACE #1, ID
Wood - H 138.00 138.00 17.00 1 16 THREEMILE KNOLL, ID GRACE #2, ID
Wood - H 138.00 138.00 2.00 1 17 THREEMILE KNOLL, ID MONSANTO #1, ID
Steel - SP 138.00 138.00 2.00 1 18 THREEMILE KNOLL, ID MONSANTO #2, ID
Steel - SP 138.00 138.00 2.00 1 19 TIMP #1, UT DYNAMO, UT
Steel - SP 138.00 138.00 2.00 1 20 TIMP #2, UT DYNAMO, UT
Steel - SP 138.00 138.00 4.00 1 21 TIMP, UT HALE, UT
Wood - H 138.00 138.00 20.00 1 22 TIMP, UT SPANISH FORK, UT
Wood - SP 138.00 138.00 2.00 1 23 TIMP, UT VINEYARD, UT
Steel Tower 138.00 138.00 25.00 1 24 TREASURETON, ID GRACE, ID
Steel Tower 138.00 138.00 25.00 1 25 TREASURETON, ID GRACE #2, ID
Wood - H 138.00 138.00 6.00 1 26 TREASURETON, ID ONEIDA, ID
Wood - SP 138.00 138.00 12.00 6.00 1 27 TRI-CITY, UT BANGERTER, UT
Wood - SP 138.00 138.00 22.00 1 28 TRI-CITY, UT SUNRISE, ID
Wood - H 138.00 138.00 15.00 1 29 TRI-CITY, UT WESTFIELD, UT
Wood - SP 138.00 138.00 1.00 1 30 VERNAL (WAPA), UT NAPLES, UT
Wood - SP 138.00 138.00 20.00 1 31 WEST CEDAR, UT THREE PEAKS, UT
Wood - H 138.00 138.00 9.00 1 32 WEST VALLEY, UT OQUIRRH, UT
Wood - H 138.00 138.00 13.00 1 33 WESTFIELD, UT HALE, UT
Wood - H 138.00 138.00 87.00 1 34 WHEELON, UT AMERICAN FALLS, ID
Steel Tower 138.00 138.00 29.00 1 35 WHEELON #1, UT TREASURETON, ID
FERC FORM NO. 1 (ED. 12-87) Page 422.8
36 TOTAL 17,272.00 656.00 308
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
/ /2020/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
1272 ACSR 45/7 1
1272 ACSR 45/7 2
3
250 CUHD /12 4
1272 ACSR 45/7 5
1272 ACSR 45/7 6
795 AAC /37 7
795 AAC /37 8
795 ACSR 26/7 9
1272 ACSR 45/7 10
11
795 AAC /37 12
397.5 ACSR 26/7 13
14
250 CUHD /12 15
1272 ACSR 45/7 16
17
1272 ACSR 45/7 18
19
20
21
22
1272 ACSR 45/7 23
250 CUHD /12 24
250 CUHD /12 25
250 CUHD /12 26
27
28
1272 ACSR 45/7 29
30
795 ACSR 26/7 31
32
795 ACSR 26/7 33
250 CUHD /12 34
250 CUHD /12 35
FERC FORM NO. 1 (ED. 12-87) Page 423.8
36 274,562,517 3,717,200,904 3,991,763,421 1,038,503 16,623,016 2,217,342 19,878,861
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
/ /2020/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 29.00 1 1 WHEELON #2, UT TREASURETON, ID
Wood - H 138.00 138.00 29.00 1 2 WHEELON #3, UT TREASURETON, ID
3 138kV costs and expenses
209.00 2,225.00 152 4 Subtotal 138kV
5
1,661.00 6 All 115kV Lines
7
2,911.00 8 All 69kV Lines
9
107.00 10 All 57kV Lines
11
2,514.00 12 All 46kV Lines
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 422.9
36 TOTAL 17,272.00 656.00 308
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
/ /2020/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
250 CUHD /12 2
456,802,089 422,462,122 34,339,967 1,568,897 102,117 1,180,558 286,222 3
456,802,089 422,462,122 34,339,967 1,568,897 102,117 1,180,558 286,222 4
5
234,500,727 229,042,194 5,458,533 2,704,908 334,480 2,350,880 19,548 6
7
330,550,166 322,104,897 8,445,269 6,062,513 250,289 5,492,945 319,279 8
9
13,174,418 13,032,950 141,468 83,047 4,169 75,599 3,279 10
11
305,127,198 293,392,043 11,735,155 1,716,093 30,653 1,502,417 183,023 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 423.9
36 274,562,517 3,717,200,904 3,991,763,421 1,038,503 16,623,016 2,217,342 19,878,861
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 328-330, Transmission of
electricity for others in this Form No. 1.
Schedule Page: 422 Line No.: 3 Column: a
The Alvey - Dixonville 500kV line is jointly owned by PacifiCorp and Bonneville Power
Administration ("BPA"), each with an undivided interest of 50.0%. Plant cost reported for
this line represents PacifiCorp's 50.0% share. Operations 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.: 4 Column: a
The Broadview - Colstrip A 500kV line is jointly owned by PacifiCorp, NorthWestern Energy,
Puget Sound Energy, Avista Corporation and Portland General Electric Company, in which
PacifiCorp owns 6.8% of the line. Plant cost and operations and maintenance costs reported
for this line represents PacifiCorp's share.

Schedule Page: 422 Line No.: 5 Column: a
The Broadview - Colstrip B 500kV line is jointly owned by PacifiCorp, NorthWestern Energy,
Puget Sound Energy, Avista Corporation and Portland General Electric Company, in which
PacifiCorp owns 6.8% of the line. Plant cost and operations and maintenance costs reported
for this line represents PacifiCorp's share.
Schedule Page: 422 Line No.: 6 Column: a
The Broadview - Townsend A 500kV line is jointly owned by PacifiCorp, NorthWestern Energy,
Puget Sound Energy, Avista Corporation and Portland General Electric Company, in which
PacifiCorp owns 8.1% of the line. Plant cost and operations and maintenance costs reported
for this line represents PacifiCorp's share.

Schedule Page: 422 Line No.: 7 Column: a
The Broadview - Townsend B 500kV line is jointly owned by PacifiCorp, NorthWestern Energy,
Puget Sound Energy, Avista Corporation and Portland General Electric Company, in which
PacifiCorp owns 8.1% of the line. Plant cost and operations and maintenance costs reported
for this line represents PacifiCorp's share.

Schedule Page: 422 Line No.: 9 Column: a
The Colstrip 4 - Colstrip 500kV line is jointly owned by PacifiCorp, NorthWestern Energy,
Puget Sound Energy, Avista Corporation and Portland General Electric Company, in which
PacifiCorp owns 6.8% of the line. Plant cost and operations and maintenance costs reported
for this line represents PacifiCorp’s share.

Schedule Page: 422 Line No.: 10 Column: a
The Dixonville - Meridian 500kV line is jointly owned by PacifiCorp and BPA, each with an
undivided interest of 50.0%. Plant cost reported for this line represents PacifiCorp's
50.0% share. Operations 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.: 11 Column: a
The Hemingway - Summer Lake 500kV line is jointly owned by PacifiCorp and Idaho Power
Company with an undivided interest of 78.0% and 22.0%, respectively. Plant cost and
operations and maintenance costs reported for this line represents PacifiCorp’s share.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 422 Line No.: 15 Column: a
The Midpoint - Hemingway 500kV line is jointly owned by PacifiCorp and Idaho Power Company
with an undivided interest of 63.0% and 37.0%, respectively. Plant cost and operations and
maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422 Line No.: 21 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422 Line No.: 22 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422 Line No.: 31 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 operations and maintenance costs reported
for this line represents PacifiCorp’s share.
Schedule Page: 422 Line No.: 32 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 operations and maintenance costs reported
for this line represents PacifiCorp’s share.
Schedule Page: 422.1 Line No.: 9 Column: a
The Goshen - Kinport 345kV line is jointly owned by PacifiCorp and Idaho Power Company
with an undivided interest of 81.7% and 18.3%, respectively. Plant cost and operations and
maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.1 Line No.: 14 Column: a
The Jim Bridger - Goshen 345kV line is jointly owned by PacifiCorp and Idaho Power Company
with an undivided interest of 70.8% and 29.2%, respectively. Plant cost and operations and
maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.1 Line No.: 15 Column: a
The Jim Bridger - Borah 345kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line designation 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 operations and maintenance costs reported for this line represents
PacifiCorp’s share.
Schedule Page: 422.1 Line No.: 16 Column: a
The Jim Bridger - Kinport 345kV line is jointly owned by PacifiCorp and Idaho Power
Company. Ownership of the line designation 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 operations and maintenance costs reported for this line represents
PacifiCorp’s share.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 422.1 Line No.: 17 Column: a
The Kinport - Midpoint 345kV line is jointly owned by PacifiCorp and Idaho Power Company
with an undivided interest of 26.8% and 73.2%, respectively. Plant cost and operations and
maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.2 Line No.: 11 Column: a
A 1.5 mile segment of the Casper - Dave Johnston 230kV line is jointly owned by PacifiCorp
and Black Hills Power with an undivided interest of 43.75% and 56.25%, respectively. Plant
cost and operations and maintenance costs reported for this line represents PacifiCorp's
share.
Schedule Page: 422.2 Line No.: 11 Column: i
1557.4 ACSS/TW 45/7
Schedule Page: 422.2 Line No.: 16 Column: i
1557.4 ACSR/TW 36/7

Schedule Page: 422.2 Line No.: 17 Column: i
1557.4 ACSR/TW 36/7

Schedule Page: 422.2 Line No.: 25 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.2 Line No.: 26 Column: i
1557.4 ACSR/TW 36/7

Schedule Page: 422.2 Line No.: 30 Column: a
Complete name is Gonder (NV Energy), Utah-Nevada State Line
Schedule Page: 422.2 Line No.: 33 Column: a
The Hurricane - Walla Walla 230kV line is jointly owned by PacifiCorp and Idaho Power
Company with an undivided interest of 59.2% and 40.8%, respectively. Plant cost and
operations and maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.3 Line No.: 2 Column: b
Complete name is Robertson Creek Metering Station, WY.

Schedule Page: 422.3 Line No.: 7 Column: i
1158.4 ACSS/TW 25/7
Schedule Page: 422.4 Line No.: 12 Column: a
The Antelope - Goshen 161kV line is jointly owned by PacifiCorp and Idaho Power Company
with an undivided interest of 78.1% and 21.9%, respectively. Plant cost and operations and
maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.4 Line No.: 13 Column: a
The Big Grassy - Jefferson 161kV line is jointly owned by PacifiCorp and Idaho Power
company with an undivided interest of 62.2% and 37.8%, respectively. Plant costs and
operations and maintenance costs reported for this line represents PacifiCorp's share.
Schedule Page: 422.4 Line No.: 16 Column: i
1557.4 ACSR/TW 36/7

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 422.4 Line No.: 18 Column: a
The Goshen - Jefferson 161kV line is jointly owned by PacifiCorp and Idaho Power Company
with an undivided interest of 77.0% and 23.0%, respectively. Plant cost and operations and
maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.5 Line No.: 1 Column: a
The Antelope - Scoville #1 138kV line is jointly owned by PacifiCorp and Idaho Power
Company with an undivided interest of 33.3% and 66.7%, respectively. Plant cost and
operations and maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.5 Line No.: 2 Column: a
The Antelope - Scoville #2 138kV line is jointly owned by PacifiCorp and Idaho Power
Company with an undivided interest of 33.3% and 66.7%, respectively. Plant cost and
operations and maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.5 Line No.: 6 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.5 Line No.: 7 Column: i
1557.4 ACSR/TW 36/7

Schedule Page: 422.5 Line No.: 30 Column: a
The Central #2 - Saint George 138kV line is jointly owned by PacifiCorp and Utah
Associated Municipal Power Systems with an undivided interest of 43.26% and 56.74%,
respectively. Plant cost and operations and maintenance costs reported for this line
represents PacifiCorp's share.
Schedule Page: 422.5 Line No.: 31 Column: a
The Central #3 - Saint George 138kV line is jointly owned by PacifiCorp and Utah
Associated Municipal Power Systems with an undivided interest of 43.26% and 56.74%,
respectively. Plant cost and operations and maintenance costs reported for this line
represents PacifiCorp's share.
Schedule Page: 422.5 Line No.: 33 Column: b
Complete name is Burraston Ponds Metering, UT
Schedule Page: 422.6 Line No.: 16 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: 422.7 Line No.: 3 Column: i
1557.4 ACSR/TW 37/7

Schedule Page: 422.7 Line No.: 5 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 10 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 11 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 12 Column: i
1557.4 ACSR/TW 36/7
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 422.7 Line No.: 22 Column: b
Complete name is Bingham Canyon (KCC), UT
Schedule Page: 422.7 Line No.: 22 Column: i
1557.4 ACSR/TW 36/7

Schedule Page: 422.8 Line No.: 3 Column: i
1557.4 ACSR/TW 36/7

Schedule Page: 422.8 Line No.: 11 Column: i
1557.4 ACSR/TW 36/7

Schedule Page: 422.8 Line No.: 14 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 17 Column: i
1557.4 ACSR/TW 36/7

Schedule Page: 422.8 Line No.: 19 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 20 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 21 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 22 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 27 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 28 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 30 Column: i
1557.4 ACSR/TW 36/7

Schedule Page: 422.8 Line No.: 32 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 34 Column: a
The Wheelon - American Falls 138kV line is jointly owned by PacifiCorp and Idaho Power
Company with an undivided interest of 96.4% and 3.6%, respectively. Plant cost and
operations and maintenance costs reported for this line represents PacifiCorp’s share.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
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 LINES ADDED DURING YEAR
PacifiCorp X
/ /2020/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
4.00Steel Tower 1 1 1 AEOLUS, WY ANTICLINE, WY 138.00
15.00Steel - H 1 1 2 ANTICLINE, WY JIM BRIDGER, WY 5.00
8.00Steel - H 1 1 3 AEOLUS, WY FREEZEOUT, WY 4.00
8.00Steel - H 1 1 4 AEOLUS, WY SHIRLEY BASIN #1, WY 17.00
8.00Steel - H 1 1 5 AEOLUS, WY SHIRLEY BASIN #2, WY 16.00
8.00Wood - H 1 1 6 CORRAL, OR OCHOCO #2, OR 10.00
16.00Steel - SP 2 2 7 FRIEND, OR OCHOCO, OR 2.00
5.00Wood - H 1 1 8 POMONA, WA VANTAGE, WA 40.00
18.00Wood - SP 1 1 9 GOSHEN, ID AMMON, ID 15.00
7.00Wood - SP 1 1 10 VERNAL (WAPA), UT NAPLES, UT 1.00
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
248.00 97.00 11 11
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
/ /2020/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
Horiz. 30'ACSR3-1272 133,834,314 268,682,205133,834,314 1,013,577 500 1
Horiz. 27'ACSR3-1272 7,072,036 15,108,115 7,072,036 964,043 345 2
Horiz. 20'ACSR1272 12,396,866 25,993,069 12,396,866 1,199,337 230 3
Horiz. 20'ACSS1158.4 12,046,633 24,171,742 12,046,633 78,476 230 4
Horiz. 20'ACSS1158.4 11,957,440 24,165,231 11,957,440 250,351 230 5
Vertical 18'ACSR1557.4 5,328,463 7,269,134 494,994 1,445,677 230 6
Vertical 18'ACSR1557.4 1,994,961 5,490,232 3,495,271 230 7
Horiz. 20'ACSR1272 2,612,165 5,813,539 1,689,111 1,512,263 230 8
Vertical 10'ACSR1557.4 9,744,314 19,609,186 9,744,314 120,558 161 9
Vertical 10'ACSR1557.4 629,391 1,576,827 629,391 318,045 138 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
197,616,583 193,360,370
FERC FORM NO. 1 (REV. 12-03) Page 425
44 6,902,327 397,879,280
Schedule Page: 424 Line No.: 1 Column: o
Costs are estimated between Poles, Towers and Fixtures in column (m) and Conductors and
Devices in column (n).

Schedule Page: 424 Line No.: 2 Column: o
Costs are estimated between Poles, Towers and Fixtures in column (m) and Conductors and
Devices in column (n).

Schedule Page: 424 Line No.: 3 Column: o
Costs are estimated between Poles, Towers and Fixtures in column (m) and Conductors and
Devices in column (n).

Schedule Page: 424 Line No.: 4 Column: o
Costs are estimated between Poles, Towers and Fixtures in column (m) and Conductors and
Devices in column (n).

Schedule Page: 424 Line No.: 5 Column: o
Costs are estimated between Poles, Towers and Fixtures in column (m) and Conductors and
Devices in column (n).

Schedule Page: 424 Line No.: 6 Column: o
Costs are estimated between Poles, Towers and Fixtures in column (m) and Conductors and
Devices in column (n).

Schedule Page: 424 Line No.: 7 Column: b
Includes the line designations in Oregon for Friend - Ochoco #1 and Friend - Ochoco #2.

Schedule Page: 424 Line No.: 7 Column: o
Costs are estimated between Poles, Towers and Fixtures in column (m) and Conductors and
Devices in column (n).

Schedule Page: 424 Line No.: 8 Column: o
Costs are estimated between Poles, Towers and Fixtures in column (m) and Conductors and
Devices in column (n).

Schedule Page: 424 Line No.: 9 Column: o
Costs are estimated between Poles, Towers and Fixtures in column (m) and Conductors and
Devices in column (n).

Schedule Page: 424 Line No.: 10 Column: o
Costs are estimated between Poles, Towers and Fixtures in column (m) and Conductors and
Devices in column (n).

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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 / /2020/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 12.47 69.00DISTRIBUTION-UNATTEN 2
BIG SPRINGS 12.47 69.00DISTRIBUTION-UNATTEN 3
CASTELLA 2.40 69.00DISTRIBUTION-UNATTEN 4
CLEAR LAKE 12.47 69.00DISTRIBUTION-UNATTEN 5
DOG CREEK 2.40 69.00DISTRIBUTION-UNATTEN 6
DORRIS 12.47 69.00DISTRIBUTION-UNATTEN 7
FORT JONES 12.47 69.00DISTRIBUTION-UNATTEN 8
GASQUET 12.47 115.00DISTRIBUTION-UNATTEN 9
GREENHORN 12.47 69.00DISTRIBUTION-UNATTEN 10
HAMBURG 2.40 69.00DISTRIBUTION-UNATTEN 11
HAPPY CAMP 12.47 69.00DISTRIBUTION-UNATTEN 12
HORNBROOK 12.47 69.00DISTRIBUTION-UNATTEN 13
INTERNATIONAL PAPER 2.40 69.00DISTRIBUTION-UNATTEN 14
LAKE EARL 12.47 69.00DISTRIBUTION-UNATTEN 15
LITTLE SHASTA 7.20 69.00 2.40DISTRIBUTION-UNATTEN 16
LUCERNE 12.47 115.00DISTRIBUTION-UNATTEN 17
MACDOEL 20.80 69.00DISTRIBUTION-UNATTEN 18
MCCLOUD 12.47 69.00DISTRIBUTION-UNATTEN 19
MILLER REDWOOD 12.47 69.00DISTRIBUTION-UNATTEN 20
MONTAGUE 12.47 69.00DISTRIBUTION-UNATTEN 21
MORRISON CREEK 12.47 69.00DISTRIBUTION-UNATTEN 22
MOUNT SHASTA 12.47 69.00DISTRIBUTION-UNATTEN 23
NEWELL 12.47 69.00DISTRIBUTION-UNATTEN 24
NORTH DUNSMUIR 12.47 69.00DISTRIBUTION-UNATTEN 25
NORTHCREST 12.47 69.00DISTRIBUTION-UNATTEN 26
NUTGLADE 2.40 69.00DISTRIBUTION-UNATTEN 27
PATRICKS CREEK 7.20 115.00DISTRIBUTION-UNATTEN 28
PEREZ 12.47 69.00DISTRIBUTION-UNATTEN 29
REDWOOD 12.47 69.00DISTRIBUTION-UNATTEN 30
SCOTT BAR 12.47 69.00DISTRIBUTION-UNATTEN 31
SEIAD 12.47 69.00DISTRIBUTION-UNATTEN 32
SHASTINA 20.80 69.00DISTRIBUTION-UNATTEN 33
SHOTGUN CREEK 12.47 69.00DISTRIBUTION-UNATTEN 34
SMITH RIVER 12.47 69.00DISTRIBUTION-UNATTEN 35
SNOW BRUSH 7.20 69.00DISTRIBUTION-UNATTEN 36
SOUTH DUNSMUIR 4.16 69.00DISTRIBUTION-UNATTEN 37
TULELAKE 12.47 69.00DISTRIBUTION-UNATTEN 38
TUNNEL 12.47 69.00 2.40DISTRIBUTION-UNATTEN 39
WALKER BRYAN 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 / /2020/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
6 4 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
9 1 17
37 2 18
6 1 19
4 3 20
6 1 21
14 1 22
29 5 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
18 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 / /2020/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).
YUBA 12.47 69.00DISTRIBUTION-UNATTEN 1
YUROK 12.47 69.00DISTRIBUTION-UNATTEN 2
Total (Number of substations - 41) 453.46 2967.00 4.80 3
4
ALTURAS 69.00 115.00 12.47T/D-UNATTENDED 5
WEED 69.00 115.00T/D-UNATTENDED 6
YREKA 69.00 115.00 12.47T/D-UNATTENDED 7
Total (Number of substations - 3) 207.00 345.00 24.94 8
9
COPCO #2 230 115.00 230.00 12.47TRANSMISSION-ATTENDE 10
COPCO #2 69.00 115.00 12.47TRANSMISSION-ATTENDE 11
AGER 69.00 115.00 12.47TRANSMISSION-UNATTEN 12
CRAG VIEW 69.00 115.00 12.47TRANSMISSION-UNATTEN 13
DEL NORTE 69.00 115.00 13.20TRANSMISSION-UNATTEN 14
Total (Number of substations - 5) 391.00 690.00 63.08 15
16
IDAHO 17
ASHTON 12.47 46.00 2.40DISTRIBUTION-ATTENDE 18
TANNER 12.47 46.00DISTRIBUTION-ATTENDE 19
ALEXANDER 12.47 46.00DISTRIBUTION-UNATTEN 20
AMMON 13.20 161.00DISTRIBUTION-UNATTEN 21
AMPS 69.00 230.00 12.47DISTRIBUTION-UNATTEN 22
ANDERSON 12.47 69.00DISTRIBUTION-UNATTEN 23
ARCO 12.47 69.00DISTRIBUTION-UNATTEN 24
ARIMO 12.47 46.00DISTRIBUTION-UNATTEN 25
BANCROFT 12.47 46.00DISTRIBUTION-UNATTEN 26
BELSON 12.47 69.00DISTRIBUTION-UNATTEN 27
BERENICE 12.47 69.00DISTRIBUTION-UNATTEN 28
CAMAS 12.47 69.00DISTRIBUTION-UNATTEN 29
CANYON CREEK 24.90 69.00DISTRIBUTION-UNATTEN 30
CHESTERFIELD 12.47 46.00DISTRIBUTION-UNATTEN 31
CINDER BUTTE 12.47 161.00DISTRIBUTION-UNATTEN 32
CLEMENTS 12.47 69.00DISTRIBUTION-UNATTEN 33
CLIFTON 12.47 46.00DISTRIBUTION-UNATTEN 34
COVE 12.47 46.00DISTRIBUTION-UNATTEN 35
DOWNEY 12.47 46.00DISTRIBUTION-UNATTEN 36
DUBOIS 12.47 69.00DISTRIBUTION-UNATTEN 37
EASTMONT 12.47 69.00DISTRIBUTION-UNATTEN 38
EGIN 12.47 69.00DISTRIBUTION-UNATTEN 39
EIGHT MILE 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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 3 1
4 3 2
337 100 3
4
35 4 5
75 2 6
95 2 7
205 8 8
9
500 2 10
51 4 11
5 3 12
19 3 13
150 2 14
725 14 15
16
17
15 2 18
4 1 19
4 1 20
44 2 21
75 1 22
20 1 23
6 1 24
7 1 25
4 1 26
14 1 27
10 1 28
14 1 29
20 1 30
5 1 31
30 1 32
13 1 33
11 1 34
6 1 35
5 1 36
12 1 37
14 1 38
14 1 39
4 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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).
FRANKLIN 69.00 138.00 13.80DISTRIBUTION-UNATTEN 1
GEORGETOWN 12.47 69.00DISTRIBUTION-UNATTEN 2
GRACE CITY 12.47 46.00DISTRIBUTION-UNATTEN 3
HAMER 12.47 69.00DISTRIBUTION-UNATTEN 4
HAYES 12.47 69.00DISTRIBUTION-UNATTEN 5
HENRY 7.20 46.00DISTRIBUTION-UNATTEN 6
HOLBROOK 12.47 69.00DISTRIBUTION-UNATTEN 7
HOOPES 12.47 69.00DISTRIBUTION-UNATTEN 8
HORSLEY 12.47 46.00DISTRIBUTION-UNATTEN 9
IDAHO FALLS 12.47 46.00DISTRIBUTION-UNATTEN 10
INDIAN CREEK 7.20 69.00DISTRIBUTION-UNATTEN 11
JEFFCO 24.90 69.00DISTRIBUTION-UNATTEN 12
KETTLE 24.90 69.00DISTRIBUTION-UNATTEN 13
LAVA 12.47 46.00DISTRIBUTION-UNATTEN 14
LUND 12.47 46.00DISTRIBUTION-UNATTEN 15
MCCAMMON 12.47 46.00DISTRIBUTION-UNATTEN 16
MENAN 12.47 69.00DISTRIBUTION-UNATTEN 17
MERRILL 12.47 69.00DISTRIBUTION-UNATTEN 18
MILLER 12.47 69.00DISTRIBUTION-UNATTEN 19
MONTPELIER 12.47 69.00DISTRIBUTION-UNATTEN 20
MOODY 24.90 69.00DISTRIBUTION-UNATTEN 21
MUD LAKE 12.47 69.00DISTRIBUTION-UNATTEN 22
NEWDALE 12.47 69.00DISTRIBUTION-UNATTEN 23
OSGOOD 12.47 69.00DISTRIBUTION-UNATTEN 24
PRESTON 12.47 46.00DISTRIBUTION-UNATTEN 25
RAYMOND 12.47 69.00DISTRIBUTION-UNATTEN 26
RENO 12.47 69.00DISTRIBUTION-UNATTEN 27
REXBURG 69.00 161.00DISTRIBUTION-UNATTEN 28
ROBERTS 12.47 69.00DISTRIBUTION-UNATTEN 29
RUBY 12.47 69.00DISTRIBUTION-UNATTEN 30
SAND CREEK 12.47 69.00DISTRIBUTION-UNATTEN 31
SANDUNE 24.90 69.00DISTRIBUTION-UNATTEN 32
SHELLEY 12.47 46.00DISTRIBUTION-UNATTEN 33
SMITH 12.47 69.00DISTRIBUTION-UNATTEN 34
SOUTH FORK 12.47 69.00DISTRIBUTION-UNATTEN 35
SPUD 12.47 46.00DISTRIBUTION-UNATTEN 36
ST. CHARLES 12.47 69.00DISTRIBUTION-UNATTEN 37
SUGAR CITY 12.47 69.00DISTRIBUTION-UNATTEN 38
SUNNYDELL 12.47 69.00DISTRIBUTION-UNATTEN 39
TARGHEE 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
75 1 1
6 1 2
14 1 3
14 1 4
9 1 5
1 1 6
6 1 7
9 1 8
4 1 9
20 1 10
3 1 11
22 1 12
14 1 13
6 1 14
5 1 15
3 1 16
10 1 17
20 1 18
5 1 19
11 1 20
14 1 21
14 1 22
20 1 23
20 1 24
12 1 25
6 1 26
20 1 27
32 2 28
8 1 29
7 1 30
40 2 31
30 1 32
20 1 33
20 1 34
14 1 35
8 1 36
5 1 37
12 1 38
13 1 39
4 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
THORNTON 12.47 69.00DISTRIBUTION-UNATTEN 1
TREASURETON 138.00 230.00 13.80DISTRIBUTION-UNATTEN 2
UCON 12.47 69.00DISTRIBUTION-UNATTEN 3
WATKINS 24.90 69.00DISTRIBUTION-UNATTEN 4
WEBSTER 12.47 69.00DISTRIBUTION-UNATTEN 5
WESTON 12.47 46.00DISTRIBUTION-UNATTEN 6
WESTWOOD 13.20 161.00DISTRIBUTION-UNATTEN 7
WINSPER 24.90 69.00DISTRIBUTION-UNATTEN 8
Total (Number of substations - 71) 1258.42 5152.00 42.47 9
10
GOSHEN 161.00 345.00 13.80T/D-UNATTENDED 11
MALAD 69.00 138.00 6.60T/D-UNATTENDED 12
RIGBY 69.00 161.00 13.80T/D-UNATTENDED 13
SAINT ANTHONY 46.00 69.00 2.40T/D-UNATTENDED 14
Total (Number of substations - 4) 345.00 713.00 36.60 15
16
GRACE 138.00 161.00 12.47TRANSMISSION-ATTENDE 17
ANTELOPE 161.00 230.00 13.80TRANSMISSION-UNATTEN 18
BIG GRASSY 69.00 161.00 12.47TRANSMISSION-UNATTEN 19
BONNEVILLE 69.00 161.00 6.60TRANSMISSION-UNATTEN 20
CONDA 46.00 138.00 12.47TRANSMISSION-UNATTEN 21
FISH CREEK 46.00 161.00 6.60TRANSMISSION-UNATTEN 22
JEFFERSON 69.00 161.00 6.60TRANSMISSION-UNATTEN 23
MIDPOINT 345.00 500.00 34.50TRANSMISSION-UNATTEN 24
OVID 69.00 138.00TRANSMISSION-UNATTEN 25
SCOVILLE 69.00 138.00 13.80TRANSMISSION-UNATTEN 26
SUGARMILL 69.00 161.00 12.47TRANSMISSION-UNATTEN 27
THREEMILE KNOLL 138.00 345.00 13.20TRANSMISSION-UNATTEN 28
Total (Number of substations - 12) 1288.00 2455.00 144.98 29
30
MONTANA 31
COLSTRIP 230.00 500.00TRANSMISSION-ATTENDE 32
BROADVIEW 230.00 500.00TRANSMISSION-UNATTEN 33
YELLOWTAIL 161.00 230.00 13.20TRANSMISSION-UNATTEN 34
Total (Number of substations - 3) 621.00 1230.00 13.20 35
36
OREGON 37
WESTSIDE 12.47 69.00DISTRIBUTION-ATTENDE 38
26TH STREET 4.16 20.80DISTRIBUTION-UNATTEN 39
35TH STREET 2.40 20.80DISTRIBUTION-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 / /2020/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
534 2 2
7 1 3
14 1 4
20 1 5
4 1 6
30 1 7
22 1 8
1565 76 9
10
948 5 11
39 4 1 12
228 4 2 13
33 2 14
1248 15 3 15
16
217 2 17
419 3 18
67 1 19
67 1 20
67 1 21
25 3 22
133 2 23
1500 3 1 24
105 2 25
67 1 26
267 4 27
775 2 28
3709 25 1 29
30
31
68 2 32
32 2 33
100 1 34
200 5 35
36
37
22 9 38
5 1 39
15 3 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 / /2020/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).
AGNESS AVE 12.47 115.00DISTRIBUTION-UNATTEN 1
ALBINA 12.47 115.00DISTRIBUTION-UNATTEN 2
ALCAN 12.47 20.80DISTRIBUTION-UNATTEN 3
ALDERWOOD 12.47 69.00DISTRIBUTION-UNATTEN 4
ARLINGTON 12.47 69.00DISTRIBUTION-UNATTEN 5
ASHLAND 12.47 115.00DISTRIBUTION-UNATTEN 6
ATHENA 12.47 69.00DISTRIBUTION-UNATTEN 7
BANDON TIE 12.47 20.80DISTRIBUTION-UNATTEN 8
BEACON 12.47 69.00DISTRIBUTION-UNATTEN 9
BEALL LANE 12.47 115.00DISTRIBUTION-UNATTEN 10
BEATTY 12.47 69.00DISTRIBUTION-UNATTEN 11
BLALOCK 12.47 69.00DISTRIBUTION-UNATTEN 12
BLOSS 12.47 115.00DISTRIBUTION-UNATTEN 13
BLY 12.47 69.00DISTRIBUTION-UNATTEN 14
BOISE CASCADE 12.47 69.00 4.16DISTRIBUTION-UNATTEN 15
BONANZA 12.47 69.00DISTRIBUTION-UNATTEN 16
BOND STREET 12.47 69.00DISTRIBUTION-UNATTEN 17
BROOKHURST 12.47 115.00DISTRIBUTION-UNATTEN 18
BROWNSVILLE 20.80 69.00DISTRIBUTION-UNATTEN 19
BRYANT 12.47 69.00DISTRIBUTION-UNATTEN 20
BUCHANAN 20.80 115.00DISTRIBUTION-UNATTEN 21
BUCKAROO 12.47 69.00DISTRIBUTION-UNATTEN 22
CAMPBELL 12.47 115.00DISTRIBUTION-UNATTEN 23
CANNON BEACH 12.47 115.00DISTRIBUTION-UNATTEN 24
CANYONVILLE 12.47 115.00DISTRIBUTION-UNATTEN 25
CARNES 12.47 69.00DISTRIBUTION-UNATTEN 26
CASEBEER 20.80 69.00DISTRIBUTION-UNATTEN 27
CAVEMAN 12.47 115.00DISTRIBUTION-UNATTEN 28
CHERRY LANE 12.47 69.00DISTRIBUTION-UNATTEN 29
CHILOQUIN MARKET 12.47 69.00DISTRIBUTION-UNATTEN 30
CHINA HAT 12.47 69.00DISTRIBUTION-UNATTEN 31
CIRCLE BLVD 20.80 115.00DISTRIBUTION-UNATTEN 32
CLEVELAND AVE 12.47 69.00DISTRIBUTION-UNATTEN 33
CLOAKE 20.80 69.00DISTRIBUTION-UNATTEN 34
COBURG 20.80 69.00 2.40DISTRIBUTION-UNATTEN 35
COLISEUM 4.16 20.80DISTRIBUTION-UNATTEN 36
COLUMBIA 69.00 115.00 7.20DISTRIBUTION-UNATTEN 37
COOS RIVER 20.80 115.00DISTRIBUTION-UNATTEN 38
COQUILLE 20.80 115.00DISTRIBUTION-UNATTEN 39
CREEK 34.50 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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
120 2 2
4 1 3
45 2 4
5 1 5
20 1 6
9 1 7
8 3 1 8
11 3 9
25 1 10
6 1 11
2 3 12
32 2 13
8 3 14
3 1 15
8 3 16
25 1 17
50 2 18
13 1 19
40 2 20
45 2 21
34 2 22
45 2 23
13 1 24
25 1 25
9 3 26
20 1 27
45 2 28
25 1 29
9 3 30
25 1 31
80 2 32
45 2 33
20 1 34
10 3 35
12 2 36
128 3 1 37
20 1 38
40 2 39
5 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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).
CROOKED RIVER RANCH 20.80 69.00DISTRIBUTION-UNATTEN 1
CROWFOOT 20.80 115.00DISTRIBUTION-UNATTEN 2
CULLY 12.47 115.00DISTRIBUTION-UNATTEN 3
CULVER 12.47 69.00 7.20DISTRIBUTION-UNATTEN 4
DAIRY 12.47 69.00DISTRIBUTION-UNATTEN 5
DALLAS 20.80 115.00DISTRIBUTION-UNATTEN 6
DALREED 34.50 230.00 13.20DISTRIBUTION-UNATTEN 7
DEVILS LAKE 20.80 115.00DISTRIBUTION-UNATTEN 8
DIXON 4.16 115.00 7.20DISTRIBUTION-UNATTEN 9
DODGE BRIDGE 20.80 69.00DISTRIBUTION-UNATTEN 10
DOWELL 12.47 115.00DISTRIBUTION-UNATTEN 11
EASY VALLEY 12.47 115.00DISTRIBUTION-UNATTEN 12
EMPIRE 20.80 115.00DISTRIBUTION-UNATTEN 13
ENTERPRISE 20.80 69.00DISTRIBUTION-UNATTEN 14
FERN HILL 12.47 115.00 7.20DISTRIBUTION-UNATTEN 15
FIELDER CREEK 20.80 115.00DISTRIBUTION-UNATTEN 16
FISH HOLE 69.00 115.00 12.47DISTRIBUTION-UNATTEN 17
FOOTHILLS 12.47 69.00DISTRIBUTION-UNATTEN 18
FORT KLAMATH 12.47 20.80DISTRIBUTION-UNATTEN 19
FRALEY 12.47 69.00DISTRIBUTION-UNATTEN 20
GARDEN VALLEY 20.80 69.00DISTRIBUTION-UNATTEN 21
GLENDALE 12.47 230.00DISTRIBUTION-UNATTEN 22
GLENEDEN 4.16 20.80DISTRIBUTION-UNATTEN 23
GLIDE 12.47 115.00DISTRIBUTION-UNATTEN 24
GOLD HILL 12.47 69.00DISTRIBUTION-UNATTEN 25
GORDON HOLLOW 20.80 69.00DISTRIBUTION-UNATTEN 26
GOSHEN 20.80 115.00DISTRIBUTION-UNATTEN 27
GRANT STREET 20.80 115.00DISTRIBUTION-UNATTEN 28
GREEN 12.47 69.00DISTRIBUTION-UNATTEN 29
GRIFFIN CREEK 12.47 115.00DISTRIBUTION-UNATTEN 30
HAMAKER 12.47 69.00DISTRIBUTION-UNATTEN 31
HARRISBURG 20.80 69.00DISTRIBUTION-UNATTEN 32
HENLEY 12.47 69.00DISTRIBUTION-UNATTEN 33
HERMISTON 12.47 69.00DISTRIBUTION-UNATTEN 34
HILLVIEW 20.80 115.00DISTRIBUTION-UNATTEN 35
HINKLE 12.47 69.00DISTRIBUTION-UNATTEN 36
HOLLADAY 12.47 115.00DISTRIBUTION-UNATTEN 37
HOLLYWOOD 12.47 115.00DISTRIBUTION-UNATTEN 38
HOOD RIVER 12.47 69.00DISTRIBUTION-UNATTEN 39
HORNET 12.47 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
25 2 1
20 1 2
25 1 3
13 1 4
25 1 5
50 2 6
95 4 1 7
50 2 8
7 1 9
25 2 10
25 1 11
45 2 12
20 1 13
19 2 14
12 1 15
20 1 16
19 3 17
21 4 18
2 1 19
5 3 20
20 1 21
25 2 22
6 1 23
12 1 24
11 3 25
6 1 26
20 1 27
45 2 28
25 1 29
20 1 30
8 3 31
13 1 32
6 3 33
20 1 34
45 2 35
20 1 36
75 3 37
50 2 38
40 2 39
20 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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).
HUMBUG CREEK 12.47 69.00DISTRIBUTION-UNATTEN 1
HUNTERS CIRCLE 12.47 69.00DISTRIBUTION-UNATTEN 2
ILLAHEE FLATS 7.20 115.00DISTRIBUTION-UNATTEN 3
INDEPENDENCE 20.80 69.00DISTRIBUTION-UNATTEN 4
JEFFERSON 20.80 69.00DISTRIBUTION-UNATTEN 5
JEROME PRAIRIE 12.47 115.00DISTRIBUTION-UNATTEN 6
JORDAN POINT 12.47 115.00DISTRIBUTION-UNATTEN 7
JOSEPH 12.47 20.80DISTRIBUTION-UNATTEN 8
JUNCTION CITY 20.80 69.00DISTRIBUTION-UNATTEN 9
KENWOOD 12.47 69.00DISTRIBUTION-UNATTEN 10
KILLINGSWORTH 12.47 69.00DISTRIBUTION-UNATTEN 11
KNAPPA SVENSEN 12.47 115.00 4.16DISTRIBUTION-UNATTEN 12
LAKEPORT 12.47 69.00DISTRIBUTION-UNATTEN 13
LANCASTER 20.80 69.00DISTRIBUTION-UNATTEN 14
LEBANON 20.80 115.00DISTRIBUTION-UNATTEN 15
LINCOLN 12.47 115.00DISTRIBUTION-UNATTEN 16
LOCKHART STREET 20.80 115.00DISTRIBUTION-UNATTEN 17
LYONS 20.80 69.00DISTRIBUTION-UNATTEN 18
MADRAS 12.47 69.00 7.20DISTRIBUTION-UNATTEN 19
MALLORY 12.47 115.00DISTRIBUTION-UNATTEN 20
MARYS RIVER 20.80 115.00DISTRIBUTION-UNATTEN 21
MCKAY 12.47 69.00 2.40DISTRIBUTION-UNATTEN 22
MEDCO 12.47 115.00DISTRIBUTION-UNATTEN 23
MEDFORD 12.47 115.00DISTRIBUTION-UNATTEN 24
MERLIN 12.47 115.00DISTRIBUTION-UNATTEN 25
MERRILL 12.47 69.00DISTRIBUTION-UNATTEN 26
MINAM 12.47 69.00DISTRIBUTION-UNATTEN 27
MODOC 12.47 69.00DISTRIBUTION-UNATTEN 28
MONPAC 69.00 115.00 13.20DISTRIBUTION-UNATTEN 29
MURDER CREEK 20.80 115.00DISTRIBUTION-UNATTEN 30
MYRTLE CREEK 12.47 69.00DISTRIBUTION-UNATTEN 31
MYRTLE POINT 20.80 115.00DISTRIBUTION-UNATTEN 32
NELSCOTT 4.16 20.80DISTRIBUTION-UNATTEN 33
NEW DESCHUTES 12.47 69.00DISTRIBUTION-UNATTEN 34
NEW O'BRIEN 12.47 115.00DISTRIBUTION-UNATTEN 35
OAK KNOLL 12.47 115.00DISTRIBUTION-UNATTEN 36
OAKLAND 12.47 115.00DISTRIBUTION-UNATTEN 37
OREMET 20.80 115.00DISTRIBUTION-UNATTEN 38
OREMET FORGE 4.16 20.80DISTRIBUTION-UNATTEN 39
OVERPASS 12.47 69.00 7.20DISTRIBUTION-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 / /2020/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
9 1 1
12 1 2
2 1 3
25 1 4
12 1 5
25 1 6
20 1 7
6 1 1 8
22 2 9
3 3 10
40 2 11
6 1 12
50 2 13
12 3 14
45 2 15
105 3 16
40 2 17
25 2 18
25 2 19
25 1 20
20 1 21
8 1 22
20 1 23
67 8 24
45 2 25
17 6 26
1 27
6 3 28
50 1 29
100 4 30
14 1 31
9 1 32
4 1 33
25 1 34
9 1 35
45 2 36
8 1 37
75 3 38
2 3 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 / /2020/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).
PACIFIC CAST 4.16 20.80DISTRIBUTION-UNATTEN 1
PALLETTE 20.80 69.00DISTRIBUTION-UNATTEN 2
PARK STREET 12.47 115.00DISTRIBUTION-UNATTEN 3
PARKROSE 12.47 115.00DISTRIBUTION-UNATTEN 4
PENDLETON 12.47 69.00DISTRIBUTION-UNATTEN 5
PILOT ROCK 12.47 69.00DISTRIBUTION-UNATTEN 6
POWELL BUTTE 12.47 115.00DISTRIBUTION-UNATTEN 7
PRINEVILLE 12.47 115.00DISTRIBUTION-UNATTEN 8
PROVOLT 12.47 69.00DISTRIBUTION-UNATTEN 9
QUEEN AVE 20.80 69.00DISTRIBUTION-UNATTEN 10
RED BLANKET 4.16 69.00DISTRIBUTION-UNATTEN 11
REDMOND 12.47 115.00DISTRIBUTION-UNATTEN 12
RIDDLE VENEER 12.47 115.00 7.20DISTRIBUTION-UNATTEN 13
ROBERTS CREEK 69.00 115.00 13.20DISTRIBUTION-UNATTEN 14
ROGUE RIVER 12.47 69.00DISTRIBUTION-UNATTEN 15
ROSEBURG 20.80 115.00DISTRIBUTION-UNATTEN 16
ROSS AVENUE 12.47 69.00DISTRIBUTION-UNATTEN 17
ROXY ANN 12.47 115.00DISTRIBUTION-UNATTEN 18
RUCH 12.47 115.00DISTRIBUTION-UNATTEN 19
RUNNING Y 20.80 69.00DISTRIBUTION-UNATTEN 20
RUSSELLVILLE 12.47 115.00DISTRIBUTION-UNATTEN 21
SAGE ROAD 12.47 115.00DISTRIBUTION-UNATTEN 22
SCIO 12.47 69.00DISTRIBUTION-UNATTEN 23
SEASIDE 12.47 115.00DISTRIBUTION-UNATTEN 24
SELMA 12.47 115.00DISTRIBUTION-UNATTEN 25
SHASTA VIEW 4.16 20.80DISTRIBUTION-UNATTEN 26
SHASTA WAY 4.16 12.47DISTRIBUTION-UNATTEN 27
SHEVLIN PARK 12.47 69.00 7.20DISTRIBUTION-UNATTEN 28
SIMTAG BOOSTER PUMP 4.16 34.50DISTRIBUTION-UNATTEN 29
SOUTH DUNES 12.47 115.00DISTRIBUTION-UNATTEN 30
SOUTHGATE 20.80 69.00DISTRIBUTION-UNATTEN 31
SPRAGUE RIVER 12.47 69.00DISTRIBUTION-UNATTEN 32
STATE STREET 20.80 115.00DISTRIBUTION-UNATTEN 33
STAYTON 20.80 69.00DISTRIBUTION-UNATTEN 34
STEAMBOAT 7.20 115.00DISTRIBUTION-UNATTEN 35
STEVENS ROAD 20.80 115.00DISTRIBUTION-UNATTEN 36
SUTHERLIN 12.47 115.00DISTRIBUTION-UNATTEN 37
SWAN LAKE 12.47 20.80DISTRIBUTION-UNATTEN 38
SWEET HOME 20.80 115.00DISTRIBUTION-UNATTEN 39
TAKELMA 20.80 115.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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
1 1 1 2
40 2 3
37 2 4
43 6 1 5
22 2 6
12 1 7
50 2 8
11 3 9
50 2 10
2 3 11
50 2 12
25 1 13
50 1 14
13 1 15
50 2 16
9 3 17
25 1 18
9 1 19
9 1 20
45 2 21
40 2 22
8 1 23
40 2 24
9 1 25
3 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
5 2 38
42 2 39
12 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
TALENT 12.47 115.00DISTRIBUTION-UNATTEN 1
TEXUM 12.47 69.00DISTRIBUTION-UNATTEN 2
TILLER 12.47 115.00DISTRIBUTION-UNATTEN 3
TOLO 12.47 69.00DISTRIBUTION-UNATTEN 4
TURKEY HILL 12.47 69.00DISTRIBUTION-UNATTEN 5
UMAPINE 12.47 69.00DISTRIBUTION-UNATTEN 6
UMATILLA 12.47 69.00DISTRIBUTION-UNATTEN 7
USBR PUMP 2.40 12.47DISTRIBUTION-UNATTEN 8
VERNON 12.47 115.00 7.20DISTRIBUTION-UNATTEN 9
VILAS 12.47 115.00DISTRIBUTION-UNATTEN 10
VILLAGE GREEN 20.80 115.00DISTRIBUTION-UNATTEN 11
VINE STREET 20.80 69.00DISTRIBUTION-UNATTEN 12
WALLOWA 12.47 69.00DISTRIBUTION-UNATTEN 13
WARM SPRINGS 20.80 69.00DISTRIBUTION-UNATTEN 14
WARRENTON 12.47 115.00DISTRIBUTION-UNATTEN 15
WASCO 4.16 20.80DISTRIBUTION-UNATTEN 16
WECOMA BEACH 4.16 20.80DISTRIBUTION-UNATTEN 17
WESTON 12.47 69.00DISTRIBUTION-UNATTEN 18
WEYERHAEUSER 12.47 69.00DISTRIBUTION-UNATTEN 19
WHITE CITY 12.47 115.00DISTRIBUTION-UNATTEN 20
WILLOW COVE 4.16 34.50DISTRIBUTION-UNATTEN 21
WINSTON 12.47 69.00DISTRIBUTION-UNATTEN 22
YEW AVENUE 12.47 115.00DISTRIBUTION-UNATTEN 23
YOUNGS BAY 12.47 115.00DISTRIBUTION-UNATTEN 24
Total (Number of substations - 187) 2838.23 16091.94 129.99 25
26
BEND 12.47 69.00T/D-ATTENDED 27
APPLEGATE 69.00 115.00 12.47T/D-UNATTENDED 28
BELKNAP 69.00 115.00 13.20T/D-UNATTENDED 29
CALAPOOYA 20.80 230.00 12.47T/D-UNATTENDED 30
CAVE JUNCTION 69.00 115.00 13.20T/D-UNATTENDED 31
CHILOQUIN 115.00 230.00 12.47T/D-UNATTENDED 32
COVE 69.00 230.00 2.40T/D-UNATTENDED 33
HAZELWOOD 69.00 115.00 12.47T/D-UNATTENDED 34
HURRICANE 69.00 230.00T/D-UNATTENDED 35
JACKSONVILLE 69.00 115.00 13.20T/D-UNATTENDED 36
KNOTT 57.00 115.00 12.47T/D-UNATTENDED 37
MILE HI 69.00 115.00 12.47T/D-UNATTENDED 38
PILOT BUTTE 69.00 230.00T/D-UNATTENDED 39
RIDDLE 69.00 115.00T/D-UNATTENDED 40
FERC FORM NO. 1 (ED. 12-96) Page 426.8
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
50 2 1
25 1 2
1 1 3
11 1 4
13 3 5
20 1 6
25 2 7
1 3 8
50 2 9
25 1 10
40 2 11
30 1 12
7 1 13
12 3 14
38 2 15
2 3 16
3 1 17
25 1 18
40 2 19
65 3 20
28 3 21
22 3 22
25 1 23
37 2 24
4806 348 6 25
26
31 3 27
65 2 28
65 3 29
87 2 30
70 2 31
131 5 1 32
127 3 33
106 3 34
29 2 35
75 2 36
172 5 37
39 4 38
400 4 39
75 2 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 / /2020/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).
ROUNDUP 69.00 230.00T/D-UNATTENDED 1
SCENIC 69.00 115.00 13.20T/D-UNATTENDED 2
SNOW GOOSE 230.00 500.00 34.50T/D-UNATTENDED 3
WINCHESTER 69.00 115.00 12.47T/D-UNATTENDED 4
Total (Number of substations - 18) 1332.27 3099.00 176.99 5
6
LEMOLO #1 7.20 12.47TRANSMISSION-ATTENDE 7
PARRISH GAP 69.00 230.00 12.47TRANSMISSION-ATTENDE 8
COLD SPRINGS 69.00 230.00TRANSMISSION-UNATTEN 9
DIAMOND HILL 69.00 230.00 12.47TRANSMISSION-UNATTEN 10
DIXONVILLE 230 115.00 230.00 13.80TRANSMISSION-UNATTEN 11
DIXONVILLE 500 230.00 500.00 34.50TRANSMISSION-UNATTEN 12
FRIEND 115.00 230.00TRANSMISSION-UNATTEN 13
FRY 115.00 230.00 12.47TRANSMISSION-UNATTEN 14
GRANTS PASS 115.00 230.00 12.47TRANSMISSION-UNATTEN 15
ISTHMUS 115.00 230.00 13.80TRANSMISSION-UNATTEN 16
KLAMATH FALLS 69.00 230.00 13.80TRANSMISSION-UNATTEN 17
LONE PINE 115.00 230.00 13.80TRANSMISSION-UNATTEN 18
MALIN 230.00 500.00 13.80TRANSMISSION-UNATTEN 19
MERIDIAN 230.00 500.00 34.50TRANSMISSION-UNATTEN 20
NICKEL MOUNTAIN 115.00 230.00 12.47TRANSMISSION-UNATTEN 21
PONDEROSA 115.00 230.00 12.47TRANSMISSION-UNATTEN 22
PROSPECT CENTRAL 69.00 115.00 12.47TRANSMISSION-UNATTEN 23
SANTIAM TIE 69.00 230.00 12.47TRANSMISSION-UNATTEN 24
TROUTDALE 115.00 230.00 13.20TRANSMISSION-UNATTEN 25
TUCKER 69.00 115.00 12.47TRANSMISSION-UNATTEN 26
WHETSTONE 115.00 230.00 12.47TRANSMISSION-UNATTEN 27
Total (Number of substations - 21) 2330.20 5192.47 275.90 28
29
UTAH 30
PIONEER PLANT 12.47 138.00DISTRIBUTION-ATTENDE 31
WEST VALLEY 12.47 138.00DISTRIBUTION-ATTENDE 32
106TH SOUTH 12.47 138.00DISTRIBUTION-UNATTEN 33
118TH SOUTH 12.47 138.00DISTRIBUTION-UNATTEN 34
23RD STREET 12.47 46.00DISTRIBUTION-UNATTEN 35
70TH SOUTH 12.47 138.00DISTRIBUTION-UNATTEN 36
ALTAVIEW 12.47 46.00DISTRIBUTION-UNATTEN 37
AMALGA 12.47 46.00DISTRIBUTION-UNATTEN 38
AMERICAN FORK 12.47 138.00DISTRIBUTION-UNATTEN 39
ANGEL 46.00 138.00 12.47DISTRIBUTION-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 / /2020/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
70 3 2
650 3 1 3
75 5 4
2334 55 2 5
6
2 3 7
150 1 8
66 2 9
75 1 10
344 6 11
650 3 1 12
250 1 13
500 2 2 14
583 4 2 15
250 1 16
251 6 17
733 10 18
775 4 1 19
1300 6 1 20
125 1 21
500 2 22
45 3 1 23
75 1 24
500 3 25
100 2 26
250 1 27
7524 63 8 28
29
30
30 1 31
30 1 32
30 1 33
30 1 34
13 1 35
30 1 36
45 2 37
11 1 38
30 1 39
135 3 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 / /2020/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 12.47 46.00DISTRIBUTION-UNATTEN 1
AURORA 12.47 46.00DISTRIBUTION-UNATTEN 2
BANGERTER 13.20 138.00DISTRIBUTION-UNATTEN 3
BDO 12.47 138.00DISTRIBUTION-UNATTEN 4
BEAR RIVER 12.47 46.00DISTRIBUTION-UNATTEN 5
BENJAMIN 12.47 46.00DISTRIBUTION-UNATTEN 6
BINGHAM 13.20 46.00DISTRIBUTION-UNATTEN 7
BLACK MOUNTAIN 7.20 46.00DISTRIBUTION-UNATTEN 8
BLUE CREEK 12.47 46.00DISTRIBUTION-UNATTEN 9
BLUFF 12.47 69.00DISTRIBUTION-UNATTEN 10
BLUFFDALE 12.47 46.00DISTRIBUTION-UNATTEN 11
BOTHWELL 12.47 46.00DISTRIBUTION-UNATTEN 12
BRIAN HEAD 12.47 34.50DISTRIBUTION-UNATTEN 13
BRIGHTON 24.90 46.00DISTRIBUTION-UNATTEN 14
BROOKLAWN 12.47 46.00DISTRIBUTION-UNATTEN 15
BRUNSWICK 12.47 46.00 7.20DISTRIBUTION-UNATTEN 16
BURTON 12.47 34.50DISTRIBUTION-UNATTEN 17
BUSH 12.47 46.00DISTRIBUTION-UNATTEN 18
CANNON 12.47 46.00DISTRIBUTION-UNATTEN 19
CANYONLANDS 12.47 69.00DISTRIBUTION-UNATTEN 20
CAPITOL 12.47 46.00DISTRIBUTION-UNATTEN 21
CARBIDE 12.47 69.00DISTRIBUTION-UNATTEN 22
CARBONVILLE 12.47 46.00DISTRIBUTION-UNATTEN 23
CARLISLE 12.47 138.00DISTRIBUTION-UNATTEN 24
CASTO 12.47 46.00DISTRIBUTION-UNATTEN 25
CENTENNIAL 12.47 138.00DISTRIBUTION-UNATTEN 26
CENTERVILLE 12.47 46.00DISTRIBUTION-UNATTEN 27
CENTRAL 12.47 46.00DISTRIBUTION-UNATTEN 28
CHAPEL HILL 12.47 138.00DISTRIBUTION-UNATTEN 29
CHERRYWOOD 12.47 138.00DISTRIBUTION-UNATTEN 30
CIRCLEVILLE 12.47 69.00DISTRIBUTION-UNATTEN 31
CLEAR CREEK 12.47 46.00DISTRIBUTION-UNATTEN 32
CLEAR LAKE 12.47 69.00DISTRIBUTION-UNATTEN 33
CLEARFIELD SOUTH 12.47 138.00DISTRIBUTION-UNATTEN 34
CLINTON 12.47 138.00DISTRIBUTION-UNATTEN 35
CLIVE 12.47 46.00DISTRIBUTION-UNATTEN 36
COALVILLE 12.47 138.00DISTRIBUTION-UNATTEN 37
COLD WATER CANYON 12.47 138.00DISTRIBUTION-UNATTEN 38
COLEMAN 69.00 138.00 6.60DISTRIBUTION-UNATTEN 39
COLTON WELL 2.40 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.10
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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
30 1 4
17 2 5
4 1 6
25 1 7
1 1 8
2 3 9
1 3 10
14 1 11
4 1 12
14 1 13
29 2 14
6 1 15
62 3 16
11 3 17
14 1 18
12 1 19
1 1 20
20 1 21
3 1 22
6 1 23
30 1 24
28 1 25
40 2 26
22 1 27
9 1 28
30 1 29
55 2 30
3 1 31
4 1 32
3 33
60 2 34
50 2 35
4 1 36
22 1 37
30 1 38
106 4 39
1 3 40
FERC FORM NO. 1 (ED. 12-96) Page 427.10
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
COMMERCE 12.47 138.00DISTRIBUTION-UNATTEN 1
COPPER HILLS 13.20 138.00DISTRIBUTION-UNATTEN 2
CORRINE 12.47 46.00DISTRIBUTION-UNATTEN 3
COVE FORT 12.47 46.00DISTRIBUTION-UNATTEN 4
COZYDALE 12.47 138.00DISTRIBUTION-UNATTEN 5
CRANER FLAT 7.20 138.00DISTRIBUTION-UNATTEN 6
CROSS HOLLOW 12.47 138.00DISTRIBUTION-UNATTEN 7
CROYDON 46.00 138.00 12.47DISTRIBUTION-UNATTEN 8
CUDAHY 12.47 138.00DISTRIBUTION-UNATTEN 9
DAMMERON VALLEY 12.47 34.50DISTRIBUTION-UNATTEN 10
DECADE 13.20 138.00DISTRIBUTION-UNATTEN 11
DECKER LAKE 12.47 138.00DISTRIBUTION-UNATTEN 12
DELLE 12.47 46.00DISTRIBUTION-UNATTEN 13
DELTA 46.00 69.00 13.20DISTRIBUTION-UNATTEN 14
DEWEYVILLE 12.47 46.00DISTRIBUTION-UNATTEN 15
DIMPLE DELL 12.47 138.00DISTRIBUTION-UNATTEN 16
DRAPER 13.20 138.00DISTRIBUTION-UNATTEN 17
DUMAS 12.47 138.00DISTRIBUTION-UNATTEN 18
EAST BENCH 12.47 138.00DISTRIBUTION-UNATTEN 19
EAST HYRUM 12.47 46.00DISTRIBUTION-UNATTEN 20
EAST LAYTON 12.47 138.00DISTRIBUTION-UNATTEN 21
EAST MILLCREEK 12.47 46.00DISTRIBUTION-UNATTEN 22
EDEN 12.47 46.00DISTRIBUTION-UNATTEN 23
ELBERTA 12.47 46.00DISTRIBUTION-UNATTEN 24
ELK MEADOWS 12.47 46.00DISTRIBUTION-UNATTEN 25
ELSINORE 12.47 46.00DISTRIBUTION-UNATTEN 26
EMERY CITY 12.47 69.00DISTRIBUTION-UNATTEN 27
EMIGRATION 12.47 46.00DISTRIBUTION-UNATTEN 28
ENOCH 12.47 138.00DISTRIBUTION-UNATTEN 29
ENTERPRISE VALLEY 12.47 138.00DISTRIBUTION-UNATTEN 30
EUREKA 12.47 46.00DISTRIBUTION-UNATTEN 31
FARMINGTON 13.20 138.00DISTRIBUTION-UNATTEN 32
FAYETTE 12.47 46.00DISTRIBUTION-UNATTEN 33
FERRON 12.47 69.00DISTRIBUTION-UNATTEN 34
FIELDING 12.47 46.00DISTRIBUTION-UNATTEN 35
FIFTH WEST 13.20 138.00DISTRIBUTION-UNATTEN 36
FLUX 12.47 46.00DISTRIBUTION-UNATTEN 37
FOOL CREEK 12.47 46.00DISTRIBUTION-UNATTEN 38
FORT DOUGLAS 13.20 138.00DISTRIBUTION-UNATTEN 39
FOUNTAIN GREEN 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 / /2020/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
30 1 1
30 1 2
3 1 3
2 3 4
30 1 5
40 2 6
20 1 7
81 2 8
30 1 9
5 1 10
60 2 11
55 2 12
6 1 13
48 3 14
4 1 15
60 2 16
60 2 17
60 2 18
30 1 19
6 1 20
60 2 21
20 1 22
19 2 23
5 1 24
3 1 25
2 1 26
3 3 27
25 1 28
14 1 29
10 1 30
3 1 31
60 2 32
1 2 33
5 1 34
6 1 35
60 2 36
4 1 37
2 1 38
40 1 39
7 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 / /2020/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).
FREEDOM 7.20 46.00DISTRIBUTION-UNATTEN 1
FRUIT HEIGHTS 12.47 46.00DISTRIBUTION-UNATTEN 2
GARDEN CITY 12.47 69.00DISTRIBUTION-UNATTEN 3
GATEWAY 34.50 69.00DISTRIBUTION-UNATTEN 4
GOLD RUSH 13.20 138.00DISTRIBUTION-UNATTEN 5
GORDON AVENUE 12.47 138.00DISTRIBUTION-UNATTEN 6
GOSHEN 12.47 46.00DISTRIBUTION-UNATTEN 7
GRANGER 12.47 46.00DISTRIBUTION-UNATTEN 8
GRANTSVILLE 12.47 46.00DISTRIBUTION-UNATTEN 9
GRAVEL PIT 12.47 46.00DISTRIBUTION-UNATTEN 10
GROW 12.47 138.00DISTRIBUTION-UNATTEN 11
GUNNISON 12.47 46.00DISTRIBUTION-UNATTEN 12
HAMMER 12.47 138.00DISTRIBUTION-UNATTEN 13
HAVASU 12.47 69.00DISTRIBUTION-UNATTEN 14
HELPER CITY 4.16 46.00DISTRIBUTION-UNATTEN 15
HERRIMAN 13.20 138.00DISTRIBUTION-UNATTEN 16
HIGHLAND DISTRIBUTION 12.47 46.00DISTRIBUTION-UNATTEN 17
HOGGARD 12.47 138.00DISTRIBUTION-UNATTEN 18
HOLDEN 12.47 46.00DISTRIBUTION-UNATTEN 19
HOLLADAY 12.47 46.00DISTRIBUTION-UNATTEN 20
HONEYVILLE 46.00 138.00 6.60DISTRIBUTION-UNATTEN 21
HUNTER 12.47 46.00DISTRIBUTION-UNATTEN 22
HUNTINGTON CITY 12.47 69.00DISTRIBUTION-UNATTEN 23
IRON MOUNTAIN 12.47 34.50DISTRIBUTION-UNATTEN 24
IRONTON 12.47 46.00DISTRIBUTION-UNATTEN 25
IVINS 12.47 69.00DISTRIBUTION-UNATTEN 26
JORDAN NARROWS 4.16 46.00DISTRIBUTION-UNATTEN 27
JORDAN PARK 12.47 138.00DISTRIBUTION-UNATTEN 28
JORDANELLE 12.47 138.00DISTRIBUTION-UNATTEN 29
JUAB 12.47 46.00DISTRIBUTION-UNATTEN 30
JUDGE 12.47 46.00DISTRIBUTION-UNATTEN 31
JUNCTION 12.47 69.00DISTRIBUTION-UNATTEN 32
KAIBAB 12.47 69.00DISTRIBUTION-UNATTEN 33
KAMAS 12.47 46.00DISTRIBUTION-UNATTEN 34
KEARNS 12.47 138.00DISTRIBUTION-UNATTEN 35
KENSINGTON 4.16 46.00DISTRIBUTION-UNATTEN 36
KYUNE 7.20 46.00DISTRIBUTION-UNATTEN 37
LAKE PARK 12.47 138.00DISTRIBUTION-UNATTEN 38
LAMPO 46.00 138.00 12.47DISTRIBUTION-UNATTEN 39
LAYTON 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.12
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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
22 1 2
12 1 3
14 1 2 4
30 1 5
30 1 6
7 1 7
50 2 8
23 1 9
3 1 10
78 3 11
20 1 12
60 2 13
3 1 14
3 3 15
60 2 16
25 1 17
50 2 18
4 1 19
32 2 20
35 1 21
22 1 22
7 1 23
1 3 24
2 1 25
30 1 26
13 2 27
30 1 28
30 1 29
4 1 30
22 1 31
3 1 32
5 1 33
11 1 34
60 2 35
7 1 36
1 37
53 2 38
75 1 39
40 2 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 / /2020/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).
LEGRANDE 12.47 46.00DISTRIBUTION-UNATTEN 1
LEWISTON 7.20 46.00DISTRIBUTION-UNATTEN 2
LINCOLN 12.47 46.00DISTRIBUTION-UNATTEN 3
LINDON 12.47 46.00DISTRIBUTION-UNATTEN 4
LISBON 12.47 69.00DISTRIBUTION-UNATTEN 5
LOAFER 7.20 46.00DISTRIBUTION-UNATTEN 6
LOGAN CANYON 7.20 46.00DISTRIBUTION-UNATTEN 7
LONE TREE 12.47 34.50DISTRIBUTION-UNATTEN 8
LOWER BEAVER 13.20 46.00DISTRIBUTION-UNATTEN 9
LYNNDYL 12.47 46.00DISTRIBUTION-UNATTEN 10
MAESER 12.47 69.00DISTRIBUTION-UNATTEN 11
MAGNA 12.47 138.00DISTRIBUTION-UNATTEN 12
MANILA 12.47 138.00DISTRIBUTION-UNATTEN 13
MANTUA 12.47 46.00DISTRIBUTION-UNATTEN 14
MAPLETON 12.47 46.00DISTRIBUTION-UNATTEN 15
MARRIOTT 12.47 46.00DISTRIBUTION-UNATTEN 16
MARYSVALE 12.47 46.00DISTRIBUTION-UNATTEN 17
MATHIS 12.47 46.00DISTRIBUTION-UNATTEN 18
MCCORNICK 12.47 46.00DISTRIBUTION-UNATTEN 19
MCKAY 12.47 46.00DISTRIBUTION-UNATTEN 20
MEADOWBROOK 12.47 138.00 46.00DISTRIBUTION-UNATTEN 21
MEDICAL 12.47 46.00DISTRIBUTION-UNATTEN 22
MIDLAND 12.47 138.00DISTRIBUTION-UNATTEN 23
MIDVALE 12.47 46.00DISTRIBUTION-UNATTEN 24
MILFORD 46.00 138.00 13.20DISTRIBUTION-UNATTEN 25
MILFORD TV 13.20 46.00DISTRIBUTION-UNATTEN 26
MINERSVILLE 12.47 46.00DISTRIBUTION-UNATTEN 27
MOAB CITY 12.47 69.00DISTRIBUTION-UNATTEN 28
MOORE 12.47 69.00DISTRIBUTION-UNATTEN 29
MORGAN 12.47 46.00DISTRIBUTION-UNATTEN 30
MORONI 12.47 46.00DISTRIBUTION-UNATTEN 31
MORTON COURT 12.47 138.00DISTRIBUTION-UNATTEN 32
MOUNTAIN DELL 12.47 46.00DISTRIBUTION-UNATTEN 33
MOUNTAIN GREEN 12.47 46.00DISTRIBUTION-UNATTEN 34
MYTON 12.47 69.00DISTRIBUTION-UNATTEN 35
NAPLES 13.20 138.00DISTRIBUTION-UNATTEN 36
NEW HARMONY 12.47 69.00DISTRIBUTION-UNATTEN 37
NEWGATE 12.47 46.00DISTRIBUTION-UNATTEN 38
NEWTON 12.47 46.00DISTRIBUTION-UNATTEN 39
NIBLEY 24.90 138.00DISTRIBUTION-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 / /2020/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
2 1 1
22 1 2
20 1 3
25 1 4
3 1 5
1 6
1 1 7
20 1 8
1 9
4 1 10
20 1 11
30 1 12
30 1 13
2 1 14
25 1 15
20 1 16
3 1 17
9 1 18
6 1 19
28 1 20
42 2 21
50 3 22
30 1 23
25 1 24
89 2 25
1 26
2 1 27
19 2 28
3 1 29
5 1 30
6 1 31
65 2 32
5 1 33
9 1 34
6 1 35
30 1 36
7 1 37
16 1 38
5 1 39
54 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 / /2020/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 BENCH 12.47 46.00DISTRIBUTION-UNATTEN 1
NORTH FIELDS 12.47 46.00DISTRIBUTION-UNATTEN 2
NORTH LOGAN 12.47 46.00DISTRIBUTION-UNATTEN 3
NORTH OGDEN 12.47 46.00DISTRIBUTION-UNATTEN 4
NORTH SALT LAKE 13.20 46.00DISTRIBUTION-UNATTEN 5
NORTHEAST 12.47 46.00DISTRIBUTION-UNATTEN 6
NORTHRIDGE 12.47 46.00DISTRIBUTION-UNATTEN 7
OAKLAND AVENUE 12.47 46.00DISTRIBUTION-UNATTEN 8
OAKLEY 12.47 46.00DISTRIBUTION-UNATTEN 9
OLYMPUS 12.47 46.00DISTRIBUTION-UNATTEN 10
OPHIR 12.47 46.00DISTRIBUTION-UNATTEN 11
ORANGE 12.47 46.00DISTRIBUTION-UNATTEN 12
ORANGEVILLE 12.47 69.00DISTRIBUTION-UNATTEN 13
OREM 12.47 46.00DISTRIBUTION-UNATTEN 14
PANGUITCH 12.47 69.00DISTRIBUTION-UNATTEN 15
PARIETTE 24.90 69.00DISTRIBUTION-UNATTEN 16
PARK CITY 12.47 46.00DISTRIBUTION-UNATTEN 17
PARKSIDE 12.47 138.00DISTRIBUTION-UNATTEN 18
PARKWAY 12.47 138.00DISTRIBUTION-UNATTEN 19
PARLEYS 12.47 46.00DISTRIBUTION-UNATTEN 20
PELICAN POINT 12.47 46.00DISTRIBUTION-UNATTEN 21
PINE CANYON 12.47 138.00DISTRIBUTION-UNATTEN 22
PINE CREEK 12.47 46.00DISTRIBUTION-UNATTEN 23
PINNACLE 12.47 46.00DISTRIBUTION-UNATTEN 24
PLAIN CITY 12.47 138.00DISTRIBUTION-UNATTEN 25
PLEASANT GROVE 12.47 138.00DISTRIBUTION-UNATTEN 26
PLEASANT VIEW 12.47 46.00DISTRIBUTION-UNATTEN 27
PONY EXPRESS 12.47 138.00DISTRIBUTION-UNATTEN 28
PORTER ROCKWELL 13.20 138.00DISTRIBUTION-UNATTEN 29
PROMONTORY 12.47 46.00DISTRIBUTION-UNATTEN 30
QUAIL CREEK 12.47 69.00DISTRIBUTION-UNATTEN 31
QUARRY 12.47 138.00DISTRIBUTION-UNATTEN 32
QUICHAPA 7.20 34.50DISTRIBUTION-UNATTEN 33
RAINS 7.20 46.00DISTRIBUTION-UNATTEN 34
RANDOLPH 12.47 46.00DISTRIBUTION-UNATTEN 35
RASMUSON 12.47 46.00DISTRIBUTION-UNATTEN 36
RATTLESNAKE 24.90 69.00DISTRIBUTION-UNATTEN 37
RED MOUNTAIN 34.50 69.00DISTRIBUTION-UNATTEN 38
REDWOOD 12.47 46.00DISTRIBUTION-UNATTEN 39
RESEARCH PARK 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.14
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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
2 1 2
25 1 3
22 1 4
25 1 5
45 2 6
14 1 7
22 1 8
6 1 9
22 1 10
3 1 11
20 1 12
14 1 13
48 2 14
5 1 15
14 1 16
42 2 17
60 2 18
50 2 19
16 2 20
6 1 21
55 2 22
2 1 23
14 1 24
22 1 25
30 1 26
14 1 27
60 2 28
60 2 29
2 1 30
13 1 31
60 2 32
4 1 33
1 34
2 1 35
1 3 36
14 1 37
12 1 38
45 2 39
45 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 / /2020/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).
RICH 12.47 69.00DISTRIBUTION-UNATTEN 1
RICHFIELD 12.47 46.00DISTRIBUTION-UNATTEN 2
RICHMOND 12.47 46.00DISTRIBUTION-UNATTEN 3
RIDGELAND 12.47 138.00DISTRIBUTION-UNATTEN 4
RITER 12.47 46.00DISTRIBUTION-UNATTEN 5
RIVERDALE 46.00 138.00 6.60DISTRIBUTION-UNATTEN 6
ROCK CANYON 12.47 69.00DISTRIBUTION-UNATTEN 7
ROCKVILLE 12.47 34.50DISTRIBUTION-UNATTEN 8
ROCKY POINT 12.47 138.00DISTRIBUTION-UNATTEN 9
ROSE PARK 12.47 46.00DISTRIBUTION-UNATTEN 10
ROYAL 4.16 46.00DISTRIBUTION-UNATTEN 11
SALINA 12.47 46.00DISTRIBUTION-UNATTEN 12
SANDY 12.47 138.00DISTRIBUTION-UNATTEN 13
SARATOGA 13.20 138.00DISTRIBUTION-UNATTEN 14
SCHOO MINE 12.47 46.00DISTRIBUTION-UNATTEN 15
SCOFIELD 12.47 46.00DISTRIBUTION-UNATTEN 16
SCOFIELD RESERVOIR 7.20 46.00DISTRIBUTION-UNATTEN 17
SEGO CANYON 12.47 69.00DISTRIBUTION-UNATTEN 18
SEVEN MILE 12.47 69.00DISTRIBUTION-UNATTEN 19
SHARON 12.47 46.00DISTRIBUTION-UNATTEN 20
SHORELINE 13.20 138.00DISTRIBUTION-UNATTEN 21
SIXTH SOUTH 12.47 46.00DISTRIBUTION-UNATTEN 22
SKULL VALLEY 12.47 46.00DISTRIBUTION-UNATTEN 23
SKYPARK 13.20 138.00DISTRIBUTION-UNATTEN 24
SMITHFIELD 46.00 138.00 6.60DISTRIBUTION-UNATTEN 25
SNARR 12.47 46.00DISTRIBUTION-UNATTEN 26
SNOWVILLE 12.47 69.00DISTRIBUTION-UNATTEN 27
SOLDIER SUMMIT 12.47 46.00DISTRIBUTION-UNATTEN 28
SOUTH JORDAN 12.47 138.00DISTRIBUTION-UNATTEN 29
SOUTH MILFORD 24.90 46.00DISTRIBUTION-UNATTEN 30
SOUTH MOUNTAIN 12.47 138.00DISTRIBUTION-UNATTEN 31
SOUTH OGDEN 12.47 46.00DISTRIBUTION-UNATTEN 32
SOUTH PARK 12.47 138.00DISTRIBUTION-UNATTEN 33
SOUTH WEBER 12.47 138.00DISTRIBUTION-UNATTEN 34
SOUTHEAST 12.47 138.00DISTRIBUTION-UNATTEN 35
SOUTHWEST 12.47 46.00DISTRIBUTION-UNATTEN 36
SPANISH VALLEY 12.47 69.00DISTRIBUTION-UNATTEN 37
SPRINGDALE 12.47 34.50DISTRIBUTION-UNATTEN 38
ST. JOHN 12.47 46.00DISTRIBUTION-UNATTEN 39
STANSBURY 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 / /2020/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
35 2 2
11 1 3
40 2 4
20 1 5
180 3 6
5 1 7
4 1 8
30 1 9
42 2 10
3 11
11 1 12
60 2 13
60 2 14
9 1 15
1 3 16
1 1 17
14 1 18
5 1 1 19
20 1 20
60 2 21
20 1 22
2 1 23
40 1 24
63 2 25
40 2 26
5 1 27
2 1 28
60 2 29
28 2 30
60 2 31
25 1 32
30 1 33
22 1 34
60 2 35
22 2 36
14 1 37
14 1 38
4 1 39
20 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.15
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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).
SUMMIT CREEK 13.80 138.00DISTRIBUTION-UNATTEN 1
SUMMIT PARK 12.47 46.00DISTRIBUTION-UNATTEN 2
SUNRISE 12.47 138.00DISTRIBUTION-UNATTEN 3
SUTHERLAND 24.90 46.00DISTRIBUTION-UNATTEN 4
TAMARISK 12.47 138.00DISTRIBUTION-UNATTEN 5
TAYLOR 12.47 46.00DISTRIBUTION-UNATTEN 6
THIEF CREEK 24.90 138.00DISTRIBUTION-UNATTEN 7
THIRD WEST 13.20 138.00DISTRIBUTION-UNATTEN 8
THIRTEENTH SOUTH 12.47 46.00DISTRIBUTION-UNATTEN 9
TOOELE DEPOT 12.47 46.00DISTRIBUTION-UNATTEN 10
TOQUERVILLE 34.50 69.00DISTRIBUTION-UNATTEN 11
TRI-CITY 12.47 138.00DISTRIBUTION-UNATTEN 12
UINTAH 12.47 46.00DISTRIBUTION-UNATTEN 13
UNION 12.47 46.00DISTRIBUTION-UNATTEN 14
VALLEY CENTER 12.47 46.00DISTRIBUTION-UNATTEN 15
VERMILLION 12.47 46.00DISTRIBUTION-UNATTEN 16
VERNAL 12.47 69.00DISTRIBUTION-UNATTEN 17
VICKERS 12.47 46.00DISTRIBUTION-UNATTEN 18
VINEYARD 13.20 138.00DISTRIBUTION-UNATTEN 19
WALLSBURG 12.47 138.00DISTRIBUTION-UNATTEN 20
WALNUT GROVE 12.47 138.00DISTRIBUTION-UNATTEN 21
WARREN 12.47 138.00DISTRIBUTION-UNATTEN 22
WASATCH STATE PARK 12.47 46.00DISTRIBUTION-UNATTEN 23
WASHAKIE 4.16 138.00DISTRIBUTION-UNATTEN 24
WELBY 12.47 46.00DISTRIBUTION-UNATTEN 25
WELFARE 12.47 46.00DISTRIBUTION-UNATTEN 26
WEST COMMERCIAL 12.47 46.00DISTRIBUTION-UNATTEN 27
WEST JORDAN 12.47 138.00DISTRIBUTION-UNATTEN 28
WEST OGDEN 12.47 138.00DISTRIBUTION-UNATTEN 29
WEST POINT 13.20 138.00DISTRIBUTION-UNATTEN 30
WEST ROY 12.47 46.00DISTRIBUTION-UNATTEN 31
WEST TEMPLE 7.20 46.00DISTRIBUTION-UNATTEN 32
WESTFIELD 12.47 138.00DISTRIBUTION-UNATTEN 33
WESTWATER 12.47 69.00DISTRIBUTION-UNATTEN 34
WHITE ROCK 13.20 138.00DISTRIBUTION-UNATTEN 35
WILLOWCREEK 12.47 46.00DISTRIBUTION-UNATTEN 36
WILLOWRIDGE 12.47 46.00DISTRIBUTION-UNATTEN 37
WINCHESTER HILLS 12.47 34.50DISTRIBUTION-UNATTEN 38
WINKLEMAN 7.20 46.00DISTRIBUTION-UNATTEN 39
WOLF CREEK 12.47 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.16
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
30 1 1
7 1 2
60 2 3
9 1 4
20 1 5
14 1 6
14 1 7
100 2 8
22 1 9
25 1 10
34 2 11
30 1 1 12
39 2 13
50 2 14
22 1 15
3 1 16
33 2 17
4 1 18
30 1 19
13 1 20
30 1 21
30 1 22
2 3 23
14 1 24
42 2 25
10 1 26
22 1 27
28 1 28
60 2 29
40 1 30
25 1 31
52 3 32
20 1 33
5 1 34
30 1 35
1 1 36
24 1 37
4 1 38
1 39
6 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.16
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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).
WOODRUFF 12.47 46.00DISTRIBUTION-UNATTEN 1
WOODS CROSS 12.47 46.00DISTRIBUTION-UNATTEN 2
Total (Number of substations - 292) 4021.64 22827.50 143.41 3
4
90TH SOUTH 138.00 345.00 12.47T/D-UNATTENDED 5
BUTLERVILLE 46.00 138.00 13.80T/D-UNATTENDED 6
CAMP WILLIAMS 138.00 345.00 24.90T/D-UNATTENDED 7
COTTONWOOD 46.00 138.00 12.47T/D-UNATTENDED 8
EMMA PARK 12.47 138.00T/D-UNATTENDED 9
HALE 46.00 138.00 12.47T/D-UNATTENDED 10
HIGHLAND 46.00 138.00 12.47T/D-UNATTENDED 11
HORSESHOE 46.00 138.00 6.60T/D-UNATTENDED 12
JORDAN 46.00 138.00 12.47T/D-UNATTENDED 13
MCCLELLAND 46.00 138.00 13.80T/D-UNATTENDED 14
OQUIRRH 138.00 345.00 13.80T/D-UNATTENDED 15
PARRISH 46.00 138.00 13.80T/D-UNATTENDED 16
SEVIER 46.00 138.00 6.60T/D-UNATTENDED 17
SILVER CREEK 46.00 138.00 13.80T/D-UNATTENDED 18
SNYDERVILLE 46.00 138.00 13.80T/D-UNATTENDED 19
SYRACUSE 138.00 345.00 13.80T/D-UNATTENDED 20
TAYLORSVILLE 46.00 138.00 12.47T/D-UNATTENDED 21
TERMINAL 138.00 345.00 12.47T/D-UNATTENDED 22
TIMP 46.00 138.00 7.20T/D-UNATTENDED 23
TOOELE 46.00 138.00 13.20T/D-UNATTENDED 24
Total (Number of substations - 20) 1346.47 3795.00 242.39 25
26
CUTLER 46.00 138.00 6.60TRANSMISSION-ATTENDE 27
EMERY 138.00 345.00 12.47TRANSMISSION-ATTENDE 28
GADSBY 46.00 138.00 13.80TRANSMISSION-ATTENDE 29
ABAJO 69.00 138.00 13.80TRANSMISSION-UNATTEN 30
ASHLEY 69.00 138.00 12.47TRANSMISSION-UNATTEN 31
BEN LOMOND 230.00 345.00 13.80TRANSMISSION-UNATTEN 32
BLACK ROCK 69.00 230.00 13.20TRANSMISSION-UNATTEN 33
BLACKHAWK 69.00 138.00 7.20TRANSMISSION-UNATTEN 34
CAMERON 46.00 138.00 6.60TRANSMISSION-UNATTEN 35
CLOVER 138.00 345.00 24.90TRANSMISSION-UNATTEN 36
COLUMBIA 46.00 138.00 6.60TRANSMISSION-UNATTEN 37
EL MONTE 46.00 138.00 12.47TRANSMISSION-UNATTEN 38
GARKANE 46.00 69.00 2.40TRANSMISSION-UNATTEN 39
GREEN CANYON 46.00 138.00 6.60TRANSMISSION-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 / /2020/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
2 1 1
20 1 2
7042 402 4 3
4
1571 5 5
205 4 6
553 5 1 7
312 7 8
8 1 9
114 2 10
97 2 11
80 2 12
204 3 13
340 3 14
835 4 15
97 2 16
34 4 17
100 2 18
127 3 19
1300 6 20
358 4 21
1610 5 22
130 2 23
249 3 24
8324 69 1 25
26
50 1 27
411 3 28
318 2 29
67 2 30
134 2 31
2202 6 32
75 1 33
100 2 34
100 4 35
400 1 36
71 2 37
312 3 38
33 1 39
67 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.17
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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).
HELPER 46.00 138.00 12.47TRANSMISSION-UNATTEN 1
HUNTINGTON 138.00 345.00 12.47TRANSMISSION-UNATTEN 2
JERUSALEM 46.00 138.00 6.60TRANSMISSION-UNATTEN 3
MATHINGTON 46.00 138.00 13.20TRANSMISSION-UNATTEN 4
MCFADDEN 69.00 138.00 13.80TRANSMISSION-UNATTEN 5
MIDDLETON 69.00 138.00 6.60TRANSMISSION-UNATTEN 6
MIDVALLEY 138.00 345.00 13.80TRANSMISSION-UNATTEN 7
MIDWAY CITY 46.00 138.00 12.47TRANSMISSION-UNATTEN 8
MINERAL PRODUCTS 46.00 69.00 6.60TRANSMISSION-UNATTEN 9
MOAB 69.00 138.00 6.60TRANSMISSION-UNATTEN 10
NEBO 46.00 138.00 6.60TRANSMISSION-UNATTEN 11
PAROWAN VALLEY 138.00 230.00 13.80TRANSMISSION-UNATTEN 12
PAVANT 46.00 230.00 13.80TRANSMISSION-UNATTEN 13
PINTO 138.00 345.00 13.80TRANSMISSION-UNATTEN 14
PURGATORY FLAT 69.00 138.00 12.47TRANSMISSION-UNATTEN 15
RED BUTTE 138.00 345.00 24.90TRANSMISSION-UNATTEN 16
SCIPIO 12.47 46.00TRANSMISSION-UNATTEN 17
SIGURD 230.00 345.00 13.80TRANSMISSION-UNATTEN 18
SPANISH FORK 138.00 345.00 13.80TRANSMISSION-UNATTEN 19
ST. GEORGE 13.80 138.00TRANSMISSION-UNATTEN 20
THREE PEAKS 138.00 345.00 12.47TRANSMISSION-UNATTEN 21
WEST CEDAR 138.00 230.00 12.47TRANSMISSION-UNATTEN 22
Total (Number of substations - 36) 3062.27 7176.00 395.43 23
24
WASHINGTON 25
ATTALIA 12.47 69.00DISTRIBUTION-UNATTEN 26
BOWMAN 12.47 69.00DISTRIBUTION-UNATTEN 27
CASCADE KRAFT 12.47 69.00DISTRIBUTION-UNATTEN 28
CENTRAL 12.47 69.00DISTRIBUTION-UNATTEN 29
CLINTON 12.47 115.00DISTRIBUTION-UNATTEN 30
DAYTON 12.47 69.00DISTRIBUTION-UNATTEN 31
DODD ROAD 20.80 69.00DISTRIBUTION-UNATTEN 32
GROMORE 12.47 115.00DISTRIBUTION-UNATTEN 33
HOPLAND 12.47 115.00DISTRIBUTION-UNATTEN 34
LAYMAN LUMBER 7.20 12.47DISTRIBUTION-UNATTEN 35
MILL CREEK 12.47 69.00DISTRIBUTION-UNATTEN 36
NACHES 12.47 115.00DISTRIBUTION-UNATTEN 37
NOB HILL 12.47 115.00DISTRIBUTION-UNATTEN 38
NORTH PARK 12.47 115.00DISTRIBUTION-UNATTEN 39
ORCHARD 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 / /2020/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.
77 2 1
270 4 2
67 1 3
189 6 4
45 1 5
137 3 6
450 1 7
67 1 8
12 1 9
67 1 10
67 1 11
138 2 12
133 2 13
257 3 14
300 2 15
764 6 2 16
2 3 17
1075 6 18
1100 2 19
100 3 1 20
450 1 21
147 2 22
10254 86 3 23
24
25
25 1 26
45 2 27
151 7 28
14 1 29
25 1 30
23 2 31
25 4 32
25 1 33
50 2 34
3 1 35
45 2 36
25 1 37
42 2 38
45 2 39
50 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 / /2020/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).
PACIFIC 12.47 115.00DISTRIBUTION-UNATTEN 1
POMEROY 12.47 69.00DISTRIBUTION-UNATTEN 2
POMONA HEIGHTS 115.00 230.00 12.47DISTRIBUTION-UNATTEN 3
PROSPECT POINT 12.47 69.00DISTRIBUTION-UNATTEN 4
PUNKIN CENTER 13.20 115.00DISTRIBUTION-UNATTEN 5
RIVER ROAD 12.47 115.00DISTRIBUTION-UNATTEN 6
SELAH 12.47 115.00DISTRIBUTION-UNATTEN 7
SULPHUR CREEK 12.47 115.00DISTRIBUTION-UNATTEN 8
SUNNYSIDE 12.47 115.00DISTRIBUTION-UNATTEN 9
TIETON 34.50 115.00DISTRIBUTION-UNATTEN 10
TOPPENISH 12.47 115.00DISTRIBUTION-UNATTEN 11
TOUCHET 12.47 69.00DISTRIBUTION-UNATTEN 12
VOELKER 12.47 115.00DISTRIBUTION-UNATTEN 13
WAITSBURG 12.47 69.00DISTRIBUTION-UNATTEN 14
WAPATO 12.47 115.00DISTRIBUTION-UNATTEN 15
WENAS 12.47 115.00DISTRIBUTION-UNATTEN 16
WHITE SWAN 12.47 115.00DISTRIBUTION-UNATTEN 17
WILEY 12.47 115.00DISTRIBUTION-UNATTEN 18
Total (Number of substations - 33) 539.86 3301.47 12.47 19
20
GRANDVIEW 69.00 115.00 12.47T/D-UNATTENDED 21
PASCO 69.00 115.00 7.20T/D-UNATTENDED 22
UNION GAP 115.00 230.00 13.20T/D-UNATTENDED 23
Total (Number of substations - 3) 253.00 460.00 32.87 24
25
DRY GULCH 69.00 115.00TRANSMISSION-UNATTEN 26
OUTLOOK 115.00 230.00 12.47TRANSMISSION-UNATTEN 27
WALLA WALLA 69.00 230.00TRANSMISSION-UNATTEN 28
WALLULA 69.00 230.00TRANSMISSION-UNATTEN 29
WINE COUNTRY 115.00 230.00TRANSMISSION-UNATTEN 30
Total (Number of substations - 5) 437.00 1035.00 12.47 31
32
WYOMING 33
ANTELOPE MINE 34.50 230.00 13.20DISTRIBUTION-UNATTEN 34
ARROWHEAD 34.50 230.00 13.20DISTRIBUTION-UNATTEN 35
ASTLE STREET 13.20 34.50DISTRIBUTION-UNATTEN 36
BAILEY DOME 4.16 57.00DISTRIBUTION-UNATTEN 37
BAR X 34.50 230.00 13.20DISTRIBUTION-UNATTEN 38
BAR NUNN 12.47 115.00DISTRIBUTION-UNATTEN 39
BATTLE SPRINGS 13.80 34.50DISTRIBUTION-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 / /2020/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.
28 3 1
9 1 2
325 3 3
40 2 4
44 3 5
76 5 6
45 2 7
25 1 8
45 2 9
29 2 1 10
50 2 11
13 1 12
25 1 13
9 1 14
45 2 15
25 2 16
22 2 17
45 2 18
1493 68 1 19
20
58 2 21
39 9 22
595 5 23
692 16 24
25
50 1 26
250 1 27
300 3 28
120 2 1 29
250 1 30
970 8 1 31
32
33
25 1 34
150 2 35
12 1 36
2 1 37
25 1 38
30 1 39
2 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.19
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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).
BELLAMY 2 4.16 69.00DISTRIBUTION-UNATTEN 1
BIG MUDDY 12.47 69.00DISTRIBUTION-UNATTEN 2
BIG PINEY 24.90 69.00DISTRIBUTION-UNATTEN 3
BLACKS FORK 34.50 230.00 13.20DISTRIBUTION-UNATTEN 4
BRIDGER PUMP 34.50 230.00 7.20DISTRIBUTION-UNATTEN 5
BRYAN 12.47 115.00DISTRIBUTION-UNATTEN 6
BUFFALO 20.80 230.00DISTRIBUTION-UNATTEN 7
BYRON 4.16 34.50DISTRIBUTION-UNATTEN 8
CASSA 20.80 57.00DISTRIBUTION-UNATTEN 9
CENTER STREET 12.47 115.00DISTRIBUTION-UNATTEN 10
CHAPMAN 12.47 46.00DISTRIBUTION-UNATTEN 11
CHUKAR 4.16 12.47DISTRIBUTION-UNATTEN 12
COKEVILLE 24.90 46.00DISTRIBUTION-UNATTEN 13
COLUMBIA-GENEVA 12.47 230.00DISTRIBUTION-UNATTEN 14
COMMUNITY PARK 12.47 115.00DISTRIBUTION-UNATTEN 15
CONTINENTAL PIPELINE 4.16 13.20DISTRIBUTION-UNATTEN 16
CROOKS GAP 12.47 34.50DISTRIBUTION-UNATTEN 17
DEAVER 4.16 34.50DISTRIBUTION-UNATTEN 18
DEER CREEK 12.47 69.00DISTRIBUTION-UNATTEN 19
DJ COAL MINE 34.50 69.00DISTRIBUTION-UNATTEN 20
DRY FORK 4.16 69.00DISTRIBUTION-UNATTEN 21
ELK BASIN 7.20 34.50DISTRIBUTION-UNATTEN 22
ELK HORN 12.47 115.00DISTRIBUTION-UNATTEN 23
EMIGRANT 12.47 115.00DISTRIBUTION-UNATTEN 24
EVANS 12.47 115.00DISTRIBUTION-UNATTEN 25
EVANSTON 12.47 138.00DISTRIBUTION-UNATTEN 26
FIREHOLE 34.50 230.00 13.20DISTRIBUTION-UNATTEN 27
FORT CASPER 12.47 69.00DISTRIBUTION-UNATTEN 28
FORT SANDERS 13.20 115.00DISTRIBUTION-UNATTEN 29
FRANNIE 34.50 230.00 2.40DISTRIBUTION-UNATTEN 30
FRONTIER 4.16 69.00DISTRIBUTION-UNATTEN 31
GARLAND 34.50 230.00 13.20DISTRIBUTION-UNATTEN 32
GLENDO 4.16 57.00DISTRIBUTION-UNATTEN 33
GRASS CREEK 34.50 230.00DISTRIBUTION-UNATTEN 34
GREAT DIVIDE 34.50 115.00DISTRIBUTION-UNATTEN 35
GREEN MOUNTAIN 4.16 34.50DISTRIBUTION-UNATTEN 36
GREYBULL 4.16 34.50DISTRIBUTION-UNATTEN 37
HANNA 13.20 34.50DISTRIBUTION-UNATTEN 38
HILLTOP 34.50 115.00 13.20DISTRIBUTION-UNATTEN 39
HOLLY SUGAR 4.16 34.50DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.20
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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
7 1 2
14 1 3
225 3 1 4
73 4 5
25 1 6
20 1 1 7
2 3 8
2 6 9
12 1 10
4 1 11
1 3 12
6 1 13
45 2 14
50 2 15
2 3 16
5 1 17
3 18
9 1 19
12 1 20
9 1 21
5 1 22
25 1 23
12 1 24
9 1 25
40 2 26
50 2 27
28 1 28
20 1 29
50 2 30
6 1 31
45 2 32
1 3 33
25 1 34
20 1 35
5 1 36
3 1 37
6 1 38
45 2 1 39
5 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 / /2020/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).
JACKALOPE 13.20 115.00DISTRIBUTION-UNATTEN 1
KEMMERER 24.90 69.00DISTRIBUTION-UNATTEN 2
KIRBY CREEK 4.16 34.50DISTRIBUTION-UNATTEN 3
KIRBY CREEK PUMPING 2.40 34.50DISTRIBUTION-UNATTEN 4
LABARGE 24.90 69.00DISTRIBUTION-UNATTEN 5
LANDER 12.47 34.50DISTRIBUTION-UNATTEN 6
LARAMIE 13.20 115.00DISTRIBUTION-UNATTEN 7
LATHAM 46.00 230.00DISTRIBUTION-UNATTEN 8
LINCH 13.80 69.00DISTRIBUTION-UNATTEN 9
LITTLE MOUNTAIN 34.50 230.00DISTRIBUTION-UNATTEN 10
LOVELL 4.16 34.50DISTRIBUTION-UNATTEN 11
MANSFACE 34.50 230.00 2.40DISTRIBUTION-UNATTEN 12
MILL IRON 13.80 34.50DISTRIBUTION-UNATTEN 13
MILLS 4.16 12.47DISTRIBUTION-UNATTEN 14
MINERS 34.50 230.00 7.20DISTRIBUTION-UNATTEN 15
MOUNTAIN GAS 12.47 34.50 4.16DISTRIBUTION-UNATTEN 16
MURPHY DOME 12.47 34.50DISTRIBUTION-UNATTEN 17
NAUGHTON CONSTRUCTION 12.47 69.00DISTRIBUTION-UNATTEN 18
NUGGETT 7.20 69.00DISTRIBUTION-UNATTEN 19
OPAL 24.90 69.00DISTRIBUTION-UNATTEN 20
ORIN 7.20 34.50DISTRIBUTION-UNATTEN 21
OWL CREEK PUMP #1 4.16 34.50DISTRIBUTION-UNATTEN 22
PARADISE 24.90 69.00DISTRIBUTION-UNATTEN 23
PARCO 13.20 34.50DISTRIBUTION-UNATTEN 24
PHILLIPS GAS PLANT PIPELINE 2.40 12.47DISTRIBUTION-UNATTEN 25
PINEDALE 24.90 69.00DISTRIBUTION-UNATTEN 26
PITCHFORK 24.90 69.00DISTRIBUTION-UNATTEN 27
PLATTE 115.00 230.00 13.20DISTRIBUTION-UNATTEN 28
PLATTE PIPE BYRON 4.16 34.50DISTRIBUTION-UNATTEN 29
PLATTE PIPE OREGON BASIN 4.16 34.50DISTRIBUTION-UNATTEN 30
PLATTE RIVER DJ 12.47 69.00DISTRIBUTION-UNATTEN 31
POINT OF ROCKS 34.50 230.00 13.20DISTRIBUTION-UNATTEN 32
POISON SPIDER 2.40 69.00DISTRIBUTION-UNATTEN 33
RAINBOW 13.20 34.50DISTRIBUTION-UNATTEN 34
RAVEN 34.50 230.00 12.47DISTRIBUTION-UNATTEN 35
RED BUTTE 13.20 115.00DISTRIBUTION-UNATTEN 36
REFINERY 12.47 115.00DISTRIBUTION-UNATTEN 37
RIVERTON 34.50 230.00 13.20DISTRIBUTION-UNATTEN 38
ROCK SPRINGS 230 34.50 230.00 13.20DISTRIBUTION-UNATTEN 39
SAGE HILL 13.20 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 / /2020/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
14 1 2
2 3 3
2 3 4
8 6 5
25 2 6
50 2 7
575 3 8
12 1 9
20 1 10
4 1 11
20 1 12
12 1 13
2 3 14
20 1 15
3 1 16
13 1 17
2 3 18
1 19
8 1 20
1 1 1 21
2 3 22
30 1 23
3 1 24
1 3 25
20 1 26
16 9 1 27
140 3 28
2 3 29
2 3 30
2 3 31
25 1 32
3 1 33
12 1 34
200 2 35
30 1 36
45 2 37
77 4 38
50 2 1 39
9 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.21
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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).
SHOSHONI 2.40 34.50DISTRIBUTION-UNATTEN 1
SINCLAIR PIPELINE 4.16 34.50DISTRIBUTION-UNATTEN 2
SLATE CREEK 13.80 69.00DISTRIBUTION-UNATTEN 3
SOUTH CODY 24.90 69.00DISTRIBUTION-UNATTEN 4
SOUTH ELK BASIN 4.16 34.50DISTRIBUTION-UNATTEN 5
SOUTH TRONA 34.50 230.00 13.20DISTRIBUTION-UNATTEN 6
SPRING CREEK 13.20 115.00DISTRIBUTION-UNATTEN 7
STANDPIPE 12.47 230.00DISTRIBUTION-UNATTEN 8
SVILAR 4.16 34.50DISTRIBUTION-UNATTEN 9
TEN MILE 34.50 69.00DISTRIBUTION-UNATTEN 10
TEN MILE STEP DOWN 12.47 34.50DISTRIBUTION-UNATTEN 11
THERMOPOLIS TOWN 4.16 34.50DISTRIBUTION-UNATTEN 12
THERMOPOLIS (WAPA) 34.50 115.00DISTRIBUTION-UNATTEN 13
THUNDER CREEK 12.47 69.00DISTRIBUTION-UNATTEN 14
VETERANS 13.20 34.50DISTRIBUTION-UNATTEN 15
WAMSUTTER AMOCO 4.16 34.50DISTRIBUTION-UNATTEN 16
WARM SPRINGS SPL 4.16 115.00DISTRIBUTION-UNATTEN 17
WERTZ-SINCLAIR 4.16 57.00DISTRIBUTION-UNATTEN 18
WEST ADAMS 4.16 34.50DISTRIBUTION-UNATTEN 19
WESTVACO 34.50 230.00DISTRIBUTION-UNATTEN 20
WHISKEY GULCH 12.47 57.00DISTRIBUTION-UNATTEN 21
WORLAND TOWN 4.16 34.50DISTRIBUTION-UNATTEN 22
WYCO BEAR CREEK 2.40 20.80DISTRIBUTION-UNATTEN 23
WYCO STROUD 4.16 13.20DISTRIBUTION-UNATTEN 24
WYOPO 34.50 230.00DISTRIBUTION-UNATTEN 25
YELLOWCAKE 34.50 230.00 13.20DISTRIBUTION-UNATTEN 26
Total (Number of substations - 113) 1938.96 11064.61 207.43 27
28
JIM BRIDGER 230.00 345.00 34.50T/D-ATTENDED 29
BAIROIL 69.00 115.00 13.20T/D-UNATTENDED 30
CASPER 115.00 230.00 13.80T/D-UNATTENDED 31
MIDWEST 69.00 230.00 13.20T/D-UNATTENDED 32
OREGON BASIN 69.00 230.00 13.20T/D-UNATTENDED 33
Total (Number of substations - 5) 552.00 1150.00 87.90 34
35
DAVE JOHNSTON 115.00 230.00 13.20TRANSMISSION-ATTENDE 36
NAUGHTON 138.00 230.00 13.80TRANSMISSION-ATTENDE 37
AEOLUS 230.00 500.00 34.50TRANSMISSION-UNATTEN 38
ANTICLINE 345.00 500.00TRANSMISSION-UNATTEN 39
CHAPPEL CREEK 69.00 230.00 12.47TRANSMISSION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.22
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
2 3 1
5 1 2
1 1 3
14 3 1 4
2 6 5
150 2 6
28 1 7
75 2 8
2 3 9
12 1 10
5 1 11
5 1 12
25 1 13
14 1 14
25 2 15
2 3 16
9 1 17
2 6 18
3 1 19
25 1 20
9 1 21
5 1 22
1 3 23
2 3 24
20 1 1 25
100 2 26
3234 211 8 27
28
775 4 29
53 3 30
575 4 31
157 3 32
100 2 33
1660 16 34
35
303 3 1 36
661 4 37
1600 3 1 38
1600 3 1 39
75 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.22
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2020/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).
CHIMNEY BUTTE 69.00 230.00 12.47TRANSMISSION-UNATTEN 1
FOOTE CREEK 34.50 230.00 12.47TRANSMISSION-UNATTEN 2
GLENDO AUTO 57.00 69.00TRANSMISSION-UNATTEN 3
MUSTANG 115.00 230.00 13.20TRANSMISSION-UNATTEN 4
RAILROAD 138.00 230.00 24.90TRANSMISSION-UNATTEN 5
SAGE 46.00 69.00 2.40TRANSMISSION-UNATTEN 6
THERMOPOLIS 115.00 230.00 12.47TRANSMISSION-UNATTEN 7
Total (Number of substations - 12) 1471.50 2978.00 151.88 8
9
CALIFORNIA 10
Distribution - 41 11
T/D - 3 12
Transmission - 5 13
IDAHO 14
Distribution - 71 15
T/D - 4 16
Transmission - 12 17
MONTANA 18
Transmission - 3 19
OREGON 20
Distribution - 187 21
T/D - 18 22
Transmission - 21 23
UTAH 24
Distribution - 292 25
T/D - 20 26
Transmission - 36 27
WASHINGTON 28
Distribution - 33 29
T/D - 3 30
Transmission - 5 31
WYOMING 32
Distribution - 113 33
T/D - 5 34
Transmission - 12 35
ALL STATES 36
Distribution - 737 37
T/D - 53 38
Transmission - 94 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 / /2020/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
67 1 1
196 2 2
8 1 1 3
100 1 4
400 1 5
22 1 6
84 1 1 7
5116 22 5 8
9
10
337 11
205 12
725 13
14
1565 15
1248 16
3709 17
18
200 19
20
4806 21
2334 22
7524 23
24
7042 25
8324 26
10254 27
28
1493 29
692 30
970 31
32
3234 33
1660 34
5116 35
36
18477 37
14463 38
28498 39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.23
Schedule Page: 426.3 Line No.: 11 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.: 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.: 19 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.: 23 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.: 23 Column: g
Includes one 3-phase transformer

Schedule Page: 426.3 Line No.: 24 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.: 28 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.: 32 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: 426.3 Line No.: 33 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: 426.8 Line No.: 35 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.: 1 Column: a
The Roundup 230kV Substation property is owned by PacifiCorp and Bonneville Power
Administration as defined in the facility sharing agreement where operations and
maintenance costs vary by type of asset and performance responsibility.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 426.9 Line No.: 12 Column: a
The Dixonville 500kV Substation is jointly owned by PacifiCorp and Bonneville Power
Administration ("BPA"), each with an undivided interest of 50.0%. Operations 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.: 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 as
defined in the operations and maintenance agreement.

Schedule Page: 426.9 Line No.: 20 Column: a
The Meridian 500kV Substation is jointly owned by PacifiCorp and Bonneville Power
Administration ("BPA"), each with an undivided interest of 50.0%. Operations 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.: 24 Column: a
The Santiam Tie 230kV Substation property is owned by PacifiCorp and Bonneville Power
Administration as defined in the facility sharing agreement where operations and
maintenance costs vary by type of asset and responsibility for performance.

Schedule Page: 426.18 Line No.: 14 Column: g
Represents three phase shifters at the substation, which does not change the voltage and
reports a 3-phase bank as three transformers.

Schedule Page: 426.18 Line No.: 18 Column: g
Includes one 3-phase transformer
Schedule Page: 426.19 Line No.: 26 Column: a
The Dry Gulch 115kV Substation property is jointly owned by PacifiCorp and Avista
Corporation as defined in the interconnection agreement where operations and maintenance
costs vary by type of asset and performance responsibility.

Schedule Page: 426.19 Line No.: 28 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
Joint Ownership and Operating Agreement.

Schedule Page: 426.22 Line No.: 29 Column: a
The Jim Bridger 345kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.
Schedule Page: 426.22 Line No.: 36 Column: a
The Dave Johnston 230kV Substation is jointly owned by PacifiCorp and Black Hills Power
with an undivided interest of 85.0% and 15.0%, respectively. Operations 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.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/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
/ /2020/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 148,225,853Bridger Coal Company 151,501
3 Coal purchases 16,249,568Trapper Mining Inc. 151,501
4 Administrative services under the IASA 4,054,460BHE 107,426.4,426.5,923
5 Administrative services under the IASA 4,191,936MEC
6 Operational support services 1,057,762MEC 234
7 Administrative services under the IASA 1,503Kern River Gas Transmission Company 923
8 Gas transportation services 3,109,681Kern River Gas Transmission Company 547
9 Operational support services 7,773Kern River Gas Transmission Company 107
10 Operational support services 147,029,375BHE Wind, LLC 107
11 Rail services and right-of-way fees 28,857,667BNSF Railway Company
12 Operational support services 3,290,593Marmon Utility, Inc. 571,593
13 Employee relocation services 960,143HomeServices of America, Inc.
14 Travel services 470,671Delta Air Lines, Inc.
15 Financial transactions related to energy hedging 2,500,232J. Aron & Company LLC 419,501,547
16 Financial transactions related to energy hedging 589,900Wells Fargo & Company 501,547
17 Banking services 851,613Wells Fargo & Company
18 Underwriting services 868,000U.S. Bancorp Investments, Inc. 181
19 Banking services 373,352U.S. Bank National Association
20 Non-power Goods or Services Provided for Affiliate
21 Information technology and administrative
22 support services 1,319,719Bridger Coal Company 501,557,931
23 Administrative services under the IASA 1,379,922BHE
24 Administrative services under the IASA 408,753MEC
25 Operational support services 1,383,681MEC 416,426.5
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
1 Non-power Goods or Services Provided by Affiliated
2 Rating agency fees 529,652Moody's Investors Service, Inc. 181,428,930.2
FERC FORM NO. 1 (New) Page 429
FERC FORM NO. 1-F (New)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
PacifiCorp X
/ /2020/Q4
Line
No. Description of the Non-Power Good or Service
Name of
(c)(b)(a)(d)
Associated/AffiliatedCompany
AccountCharged orCredited
Amount
Credited
1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed toan associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should notattempt to include or aggregate amounts in a nonspecific category such as "general".3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Charged or
3 Administrative services under the IASA 355NV Energy, Inc. 923
4 Operational support services 584,745NV Energy, Inc. 234
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20 Non-power Goods or Services Provided for Affiliate
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (New) Page 429.1
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. Eight combinations of this allocator are used for
allocating services that benefit different companies within the BHE organization.
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: b
This footnote applies to all occurrences of "BHE" on page 429. Complete name is Berkshire
Hathaway Energy Company, which is PacifiCorp's indirect parent company.

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 for MidAmerican Energy Company: 107, 426.4, 426.5, 553 and 923.

Schedule Page: 429 Line No.: 11 Column: c
Accounts charged for BNSF Railway Company: 107, 151, 501, 507, 567, 589 and 593.

Schedule Page: 429 Line No.: 11 Column: d
Non-power goods or services provided by BNSF Railway Company are as follows:
$ 28,742,050 Rail services
115,617 Right-of-way (1)
$ 28,857,667
(1) Includes right-of-way fees related to jointly owned utility facilities that are paid
either directly or indirectly to BNSF Railway Company.

Schedule Page: 429 Line No.: 13 Column: c
Accounts charged to HomeServices of America, Inc.: 506, 535, 539, 548, 557, 580, 581, 590,
592, 593, 903 and 921.
Schedule Page: 429 Line No.: 14 Column: b
On May 7, 2020, Delta Air Lines, Inc. ceased being an affiliated company when PacifiCorp's
ultimate direct parent company, Berkshire Hathaway Inc. filed public notice with the
United States Securities and Exchange Commission that all shares of Delta Air Lines, Inc.
common stock had been sold.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 429 Line No.: 14 Column: c
Accounts charged for Delta Air Lines, Inc.: 107, 416, 426.1, 426.5, 502, 506, 511, 535,
539, 548, 549, 552, 553, 557, 560, 561.2, 561.5, 568, 580, 581, 585, 588, 590, 592, 593,
595, 598, 901, 903, 908, 909, 920, 921 and 928.

Schedule Page: 429 Line No.: 15 Column: b
On February 14, 2020, J. Aron & Company ceased being an affiliated company when
PacifiCorp's ultimate direct parent company, Berkshire Hathaway Inc., filed public notice
with the United States Securities and Exchange Commission that the number of shares of J.
Aron & Company common stock fell below a controlling interest in the company.
J. Aron & Company LLC is a subsidiary of The Goldman Sachs Group, Inc. which was an
affiliated company.

Schedule Page: 429 Line No.: 16 Column: b
This footnote applies to all occurrences of "Wells Fargo & Company" on page 429. On
September 4, 2020, Wells Fargo & Company ceased being an affiliated company when
PacifiCorp's ultimate direct parent company Berkshire Hathaway Inc., filed public notice
with the United States Securities and Exchange Commission that the number of shares of
Wells Fargo & Company common stock fell below a controlling interest in the company.

Schedule Page: 429 Line No.: 17 Column: c
Accounts charged for Wells Fargo & Company: 228.3, 419, 426.5, 427, 431, 903 and 921.

Schedule Page: 429 Line No.: 18 Column: b
U.S. Bancorp Investments, Inc. is a subsidiary of U.S. Bancorp which is an affiliated
company.

Schedule Page: 429 Line No.: 18 Column: d
Represents a percentage of underwriting discount costs, excluding any expenses incurred by
PacifiCorp in connection with a debt offering.

Schedule Page: 429 Line No.: 19 Column: b
U.S. Bank National Association is a subsidiary of U.S. Bancorp which is an affiliated
company.
Schedule Page: 429 Line No.: 19 Column: c
Account charged for U.S. Bank National Association: 419, 427, 431, 537, 557, 903, 920 and
930.2.

Schedule Page: 429 Line No.: 23 Column: c
Accounts charged for Berkshire Hathaway Energy Company: 426.5, 557, 903, 920, 921, 923 and
931.
Schedule Page: 429 Line No.: 24 Column: c
Accounts charged for MidAmerican Energy Company: 107, 426.5, 580, 920, 921, 923 and 931.
Schedule Page: 429.1 Line No.: 4 Column: d
Represents an estimate at December 31, 2020.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
INDEX
Schedule Page No.
Accrued and prepaid taxes ........................................................................ 262-263
Accumulated Deferred Income Taxes .................................................................... 234
272-277
Accumulated provisions for depreciation of
common utility plant ............................................................................. 356
utility plant .................................................................................... 219
utility plant (summary) ...................................................................... 200-201
Advances
from associated companies .................................................................... 256-257
Allowances ....................................................................................... 228-229
Amortization
miscellaneous .................................................................................... 340
of nuclear fuel .............................................................................. 202-203
Appropriations of Retained Earnings .............................................................. 118-119
Associated Companies
advances from ................................................................................ 256-257
corporations controlled by respondent ............................................................ 103
control over respondent .......................................................................... 102
interest on debt to .......................................................................... 256-257
Attestation ............................................................................................ i
Balance sheet
comparative .................................................................................. 110-113
notes to ..................................................................................... 122-123
Bonds ............................................................................................ 256-257
Capital Stock ........................................................................................ 251
expense .......................................................................................... 254
premiums ......................................................................................... 252
reacquired ....................................................................................... 251
subscribed ....................................................................................... 252
Cash flows, statement of ......................................................................... 120-121
Changes
important during year ........................................................................ 108-109
Construction
work in progress - common utility plant .......................................................... 356
work in progress - electric ...................................................................... 216
work in progress - other utility departments ................................................. 200-201
Control
corporations controlled by respondent ............................................................ 103
over respondent .................................................................................. 102
Corporation
controlled by .................................................................................... 103
incorporated ..................................................................................... 101
CPA, background information on ....................................................................... 101
CPA Certification, this report form ................................................................. i-ii
FERC FORM NO. 1 (ED. 12-93)Index 1
INDEX (continued)
Schedule Page No.
Deferred
credits, other ................................................................................... 269
debits, miscellaneous ............................................................................ 233
income taxes accumulated - accelerated
amortization property ........................................................................ 272-273
income taxes accumulated - other property .................................................... 274-275
income taxes accumulated - other ............................................................. 276-277
income taxes accumulated - pollution control facilities .......................................... 234
Definitions, this report form ........................................................................ iii
Depreciation and amortization
of common utility plant .......................................................................... 356
of electric plant ................................................................................ 219
336-337
Directors ............................................................................................ 105
Discount - premium on long-term debt ............................................................. 256-257
Distribution of salaries and wages ............................................................... 354-355
Dividend appropriations .......................................................................... 118-119
Earnings, Retained ............................................................................... 118-119
Electric energy account .............................................................................. 401
Expenses
electric operation and maintenance ........................................................... 320-323
electric operation and maintenance, summary ...................................................... 323
unamortized debt ................................................................................. 256
Extraordinary property losses ........................................................................ 230
Filing requirements, this report form
General information .................................................................................. 101
Instructions for filing the FERC Form 1 ............................................................. i-iv
Generating plant statistics
hydroelectric (large) ........................................................................ 406-407
pumped storage (large) ....................................................................... 408-409
small plants ................................................................................. 410-411
steam-electric (large) ....................................................................... 402-403
Hydro-electric generating plant statistics ....................................................... 406-407
Identification ....................................................................................... 101
Important changes during year .................................................................... 108-109
Income
statement of, by departments ................................................................. 114-117
statement of, for the year (see also revenues) ............................................... 114-117
deductions, miscellaneous amortization ........................................................... 340
deductions, other income deduction ............................................................... 340
deductions, other interest charges ............................................................... 340
Incorporation information ............................................................................ 101
Index 2FERC FORM NO. 1 (ED. 12-95)
INDEX (continued)
Schedule Page No.

Interest
charges, paid on long-term debt, advances, etc ............................................... 256-257
Investments
nonutility property .............................................................................. 221
subsidiary companies ......................................................................... 224-225
Investment tax credits, accumulated deferred ..................................................... 266-267
Law, excerpts applicable to this report form .......................................................... iv
List of schedules, this report form .................................................................. 2-4
Long-term debt ................................................................................... 256-257
Losses-Extraordinary property ........................................................................ 230
Materials and supplies ............................................................................... 227
Miscellaneous general expenses ....................................................................... 335
Notes
to balance sheet ............................................................................. 122-123
to statement of changes in financial position ................................................ 122-123
to statement of income ....................................................................... 122-123
to statement of retained earnings ............................................................ 122-123
Nonutility property .................................................................................. 221
Nuclear fuel materials ........................................................................... 202-203
Nuclear generating plant, statistics ............................................................. 402-403
Officers and officers' salaries ...................................................................... 104
Operating
expenses-electric ............................................................................ 320-323
expenses-electric (summary) ...................................................................... 323
Other
paid-in capital .................................................................................. 253
donations received from stockholders ............................................................. 253
gains on resale or cancellation of reacquired
capital stock .................................................................................... 253
miscellaneous paid-in capital .................................................................... 253
reduction in par or stated value of capital stock ................................................ 253
regulatory assets ................................................................................ 232
regulatory liabilities ........................................................................... 278
Peaks, monthly, and output ........................................................................... 401
Plant, Common utility
accumulated provision for depreciation ........................................................... 356
acquisition adjustments .......................................................................... 356
allocated to utility departments ................................................................. 356
completed construction not classified ............................................................ 356
construction work in progress .................................................................... 356
expenses ......................................................................................... 356
held for future use .............................................................................. 356
in service ....................................................................................... 356
leased to others ................................................................................. 356
Plant data ...................................................................................336-337
401-429
Index 3FERC FORM NO. 1 (ED. 12-95)
INDEX (continued)
Schedule Page No.
Plant - electric
accumulated provision for depreciation ........................................................... 219
construction work in progress .................................................................... 216
held for future use .............................................................................. 214
in service ................................................................................... 204-207
leased to others ................................................................................. 213
Plant - utility and accumulated provisions for depreciation
amortization and depletion (summary) ............................................................. 201
Pollution control facilities, accumulated deferred
income taxes ..................................................................................... 234
Power Exchanges .................................................................................. 326-327
Premium and discount on long-term debt ............................................................... 256
Premium on capital stock ............................................................................. 251
Prepaid taxes .................................................................................... 262-263
Property - losses, extraordinary ..................................................................... 230
Pumped storage generating plant statistics ....................................................... 408-409
Purchased power (including power exchanges) ...................................................... 326-327
Reacquired capital stock ............................................................................. 250
Reacquired long-term debt ........................................................................ 256-257
Receivers' certificates .......................................................................... 256-257
Reconciliation of reported net income with taxable income
from Federal income taxes ...................................................................... 261
Regulatory commission expenses deferred .............................................................. 233
Regulatory commission expenses for year .......................................................... 350-351
Research, development and demonstration activities ............................................... 352-353
Retained Earnings
amortization reserve Federal ..................................................................... 119
appropriated ................................................................................. 118-119
statement of, for the year ................................................................... 118-119
unappropriated ............................................................................... 118-119
Revenues - electric operating .................................................................... 300-301
Salaries and wages
directors fees ................................................................................... 105
distribution of .............................................................................. 354-355
officers' ........................................................................................ 104
Sales of electricity by rate schedules ............................................................... 304
Sales - for resale ............................................................................... 310-311
Salvage - nuclear fuel ........................................................................... 202-203
Schedules, this report form .......................................................................... 2-4
Securities
exchange registration ........................................................................ 250-251
Statement of Cash Flows .......................................................................... 120-121
Statement of income for the year ................................................................. 114-117
Statement of retained earnings for the year ...................................................... 118-119
Steam-electric generating plant statistics ....................................................... 402-403
Substations .......................................................................................... 426
Supplies - materials and ............................................................................. 227
Index 4FERC FORM NO. 1 (ED. 12-90)
INDEX (continued)
Schedule Page No.
Taxes
accrued and prepaid ......................................................................... 262-263
charged during year ......................................................................... 262-263
on income, deferred and accumulated ............................................................. 234
272-277
reconciliation of net income with taxable income for ............................................ 261
Transformers, line - electric ....................................................................... 429
Transmission
lines added during year ..................................................................... 424-425
lines statistics ............................................................................ 422-423
of electricity for others ................................................................... 328-330
of electricity by others ........................................................................ 332
Unamortized
debt discount ............................................................................... 256-257
debt expense ................................................................................ 256-257
premium on debt ............................................................................. 256-257
Unrecovered Plant and Regulatory Study Costs ........................................................ 230
Index 5FERC FORM NO. 1 (ED. 12-90)
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM NO. 1
FOR
MULTI-STATE ELECTRIC COMPANIES
INDEX
Page Title
Number
1 Statement of Operating Income for the Year
2 Electric Operating Revenues
3 - 6 Electric Operation and Maintenance Expenses
7 Depreciation and Amortization of Electric Plant
8 Taxes, Other Than Income Taxes
9 Non-Utility Property
10 Summary of Utility Plant and Accumulated Provisions
11 - 12 Electric Plant in Service
13 Materials and Supplies
Data provided in this report is consistent with the unadjusted data reflected in the company’s Results of Operations
in the Idaho general rate case, which will be filed with the Idaho Public Utilities Commission on May 27, 2021. For
further information regarding Idaho’s 2020 financial results, refer to the Idaho general rate case.
Page i
Line ACCOUNT (Ref)
No.Page
No.Current Year Previous Year
(a)(b)(c)(d)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400) 2 310,249,279 298,763,227
3 Operating Expenses
4 Operation Expenses (401) 3-6 149,219,047 148,465,404
5 Maintenance Expenses (402) 3-6 22,003,675 20,256,417
6 Depreciation Expenses (403) (1)7 40,448,993 40,903,100
7 Amort. & Depl. of Utility Plant (404-405) 7 2,250,896 2,688,697
8 Amort. of Utility Plant Acq. Adj (406) 430,583 282,644
9
Amort. of Property Losses, Unrecovered
Plant and Regulatory Study Costs (407)884 -
10 Amort. of Conversion Expenses (407) - -
11 Taxes other Than Income Taxes (408.1) (2)8 9,794,184 9,389,124
12 Income Taxes - Federal (409.1) 6,259,389 11,126,860
13 - Other (409.1) 2,576,412 2,893,193
14 Provision for Deferred Income Taxes (410.1) 19,880,650 14,858,331
15 Provision for Deferred Income Taxes - Cr. (411.1) (34,808,620) (18,512,483)
16 Investment Tax Credit Adj. - Net (411.4) (250,976) (312,920)
17 (Gain)/Loss from Disp. of Utility Plant (411.6, 411.7, 421) (128,641) (211,561)
18 Gains from Disp. Of Allowances (411.8) (4) (11)
19
TOTAL Utility Operating Expenses
(Enter Total of Lines 4 thru 18)217,676,472 231,826,795
20
Net Utility Operating Income (Enter Total of
line 2 less 19)92,572,807 66,936,432
(1) Depreciation expense associated with transportation equipment is generally charged to operations and maintenance
expense and construction work in progress.
(2) Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
IDAHO SUPPLEMENT
STATE OF IDAHO STATEMENT OF OPERATING INCOME FOR THE YEAR
ELECTRIC UTILITY
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report Is:
(1) _X An Original
(2) __ A resubmission
Date of Report
(Mo, Da, Yr)
May 25, 2021
Year of Report
Dec. 31, 2020
Page 1
Amount for Year
(a)
Amount for
Previous Year
(c)
Amount for Year
(d)
Amount for
Previous Year
(e)
Number for
Year
(f)
Number for
Previous Year
(g)
1 Sales of Electricity
2 (440) Residential Sales 81,215,009 78,861,152 740,986 735,158 68,196 66,558
3 (442) Commercial and Industrial Sales
4 Small (or Commercial) (See Instr. 4) 43,418,994 43,891,041 494,075 512,559 9,423 9,175
5 Large (or Industrial) (See Instr. 4) 166,013,980 155,745,653 2,296,434 2,235,057 5,686 5,653
6 (444) Public Street and Highway Lighting 523,056 511,533 2,711 2,702 115 115
7 (445) Other Sales to Public Authorities - - - - - -
8 (446) Sales to Railroads and Railways - - - - - -
9 (448) Interdepartmental Sales - - - - - -
10 TOTAL Sales to Ultimate Consumers 291,171,039 279,009,379 3,534,206 3,485,476 83,420 81,501
11 (447) Sales for Resale 10,071,267 10,499,006 (1) (1) (1) (1)
12 TOTAL Sales of Electricity 301,242,306 289,508,385 3,534,206 3,485,476 83,420 81,501
13 (Less) (449.1) Provision for Rate Refunds (185,389) - - - - -
14 TOTAL Revenue Net of Prov. For Refunds 301,056,917 289,508,385 3,534,206 3,485,476 83,420 81,501
15 Other Operating Revenues
16 (450) Forfeited Discounts 451,084 334,885
17 (451) Miscellaneous Service Revenues 97,521 91,047
18 (453) Sale of Water and Water Power 421 3,172
19 (454) Rent from Electric Property 650,463 655,225
20 (455) Interdepartmental Rents - -
21 (456) Other Electric Revenues 7,992,873 8,170,513
22
23 TOTAL Other Operating Revenues 9,192,362 9,254,842
24 TOTAL Electric Operating Revenues 310,249,279 298,763,227
Pa
g
e

2
(1) For a complete list of the number of customers and Megawatt hours sold on a total
company basis see pages 310-311 - Sales for Resale of the 2020 FERC Form No. 1.
ID
A
H
O

S
U
P
P
L
E
M
E
N
T
OPERATING REVENUES AVG. NO. OF CUSTOMERS PER MONTH
Line
No.Title of Account
(a)
MEGAWATT HOURS SOLD
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report Is:
(1) _X An Original
(2) __ A resubmission
Date of Report
(Mo, Da, Yr)
May 25, 2021
Year of Report
Dec. 31, 2020
1. Report below operating revenues for each
prescribed account, and manufactured gas revenues in
total.
2. 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.
3. 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.
4. 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).
5. See page 108-109 of FERC Form No. 1, Important
Changes During Period, for important new territory added
and important rate increases or decreases.
6. For lines 2,4,5,6, and 7 see page 304 of FERC Form
No. 1 for amounts relating to unbilled revenue by
accounts.
7. Include unmetered sales. Provide details of such
sales in a footnote.
ELECTRIC OPERATING REVENUES (Account 400)
Line
No.Account
Amount for
Current Year
Amount for
Previous Year
(a)(b)(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering 922,925 1,053,665
5 (501) Fuel 43,997,856 47,745,478
6 (502) Steam Expenses 4,362,502 4,743,637
7 (503) Steam from Other Sources 424,764 315,452
8 (Less) (504) Steam Transferred - Cr. - -
9 (505) Electric Expenses 87,977 90,589
10 (506) Miscellaneous Steam Power Expenses 3,434,020 1,598,531
11 (507) Rents 26,977 29,110
12 TOTAL Operation (Enter Total of lines 4 thru 11) 53,257,021 55,576,462
13 Maintenance
14 (510) Maintenance Supervision and Engineering 469,581 431,127
15 (511) Maintenance of Structures 1,795,260 1,632,341
16 (512) Maintenance of Boiler Plant 4,046,307 5,263,249
17 (513) Maintenance of Electric Plant 1,526,532 2,335,427
18 (514) Maintenance of Miscellaneous Steam Plant 545,021 612,214
19 TOTAL Maintenance (Enter Total of lines 14 thru 18) 8,382,701 10,274,358
20 TOTAL Power Production Expenses - Steam Power (Enter Total of lines 12 & 19) 61,639,722 65,850,820
21 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 23 thru 31) - -
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 34 thru 38) - -
40 TOTAL Power Production Expenses - Nuclear Power (Enter Total of lines 32 & 39) - -
41 C. Hydraulic Power Generation
42 Operation
43 (535) Operation Supervision and Engineering 556,676 559,356
44 (536) Water for Power 8,901 2,139
45 (537) Hydraulic Expenses 274,978 240,778
46 (538) Electric Expenses - -
47 (539) Miscellaneous Hydraulic Power Generation Expenses 1,116,416 1,184,501
48 (540) Rents 101,953 100,275
49 TOTAL Operation (Enter Total of lines 43 thru 48) 2,058,924 2,087,049
IDAHO SUPPLEMENT
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report Is:
(1) _X_ An Original
(2) __ A resubmission
Date of Report
(Mo, Da, Yr)
May 25, 2021
Year of Report
Dec. 31, 2020
Page 3
Line
No.Account
Amount for
Current Year
Amount for
Previous Year
(a)(b)(c)
104 3. DISTRIBUTION EXPENSES (Continued)
105 (582) Station Expenses 355,123 472,115
106 (583) Overhead Line Expenses 352,766 313,774
107 (584) Underground Line Expenses - -
108 (585) Street Lighting and Signal System Expenses 14,023 11,201
109 (586) Meter Expenses 171,664 183,938
110 (587) Customer Installations Expenses 875,855 886,970
111 (588) Miscellaneous Distribution Expenses 28,853 (977)
112 (589) Rents 44,408 34,956
113 TOTAL Operation (Enter Total of lines 102 thru 112) 2,993,192 2,947,784
114 Maintenance
115 (590) Maintenance Supervision and Engineering 339,178 333,798
116 (591) Maintenance of Structures 126,061 148,372
117 (592) Maintenance of Station Equipment 774,816 507,870
118 (593) Maintenance of Overhead Lines 3,925,734 2,587,944
119 (594) Maintenance of Underground Lines 865,726 902,167
120 (595) Maintenance of Line Transformers 50,894 50,126
121 (596) Maintenance of Street Lighting and Signal Systems 76,955 91,042
122 (597) Maintenance of Meters 41,082 36,291
123 (598) Maintenance of Miscellaneous Distribution Plant 370,628 287,462
124 TOTAL Maintenance (Enter Total of lines 115 thru 123) 6,571,074 4,945,072
125 TOTAL Distribution Expenses (Enter Total of lines 113 and 124) 9,564,266 7,892,856
126 4. CUSTOMER ACCOUNTS EXPENSES
127 Operation
128 (901) Supervision 96,089 95,981
129 (902) Meter Reading Expenses 2,061,465 2,171,132
130 (903) Customer Records and Collection Expenses 1,919,620 1,989,916
131 (904) Uncollectible Accounts 403,578 657,699
132 (905) Miscellaneous Customer Accounts Expenses 1,152 756
133 TOTAL Customer Accounts Expenses (Enter Total of lines 128 thru 132) 4,481,904 4,915,484
134 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
135 Operation
136 (907) Supervision 28 283
137 (908) Customer Assistance Expenses 118,131 132,712
138 (909) Informational and Instructional Expenses 233,823 266,394
139 (910) Miscellaneous Customer Service and Informational Expenses 74 190
140 TOTAL Cust. Service and Informational Exp. (Enter Total of lines 136 thru 139) 352,056 399,579
141 6. SALES EXPENSES
142 Operation
143 (911) Supervision - -
144 (912) Demonstrating and Selling Expenses - -
145 (913) Advertising Expenses - -
146 (916) Miscellaneous Sales Expenses - -
147 TOTAL Sales Expenses (Enter Total of lines 143 thru 146)- -
148 7. ADMINISTRATIVE AND GENERAL EXPENSES
149 Operation
150 (920) Administrative and General Salaries 4,334,892 4,377,494
151 (921) Office Supplies and Expense 926,025 560,397
152 (Less) (922) Administrative Expenses Transferred - Cr. (2,121,833) (1,976,601)
153 (923) Outside Services Employee 1,112,475 1,164,399
154 (924) Property Insurance 365,482 384,332
155 (925) Injuries and Damages 8,259,600 357,318
156 (926) Employee Pensions and Benefits (1)6,357,885 5,817,860
157
(1)
IDAHO SUPPLEMENT
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Pensions and benefits expense is associated with labor and generally charged to operations and maintenance expense and
construction work in progress.
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report Is:
(1) _X_ An Original
(2) __ A resubmission
Date of Report
(Mo, Da, Yr)
May 25, 2021
Year of Report
Dec. 31, 2020
Page 5
Line
No.Account
Amount for
Current Year
Amount for
Previous Year
(a)(b)(c)
50 C. Hydraulic Power Generation (Continued)
51 Maintenance
52 (541) Maintenance Supervision and Engineering 23 23
53 (542) Maintenance of Structures 39,849 38,228
54 (543) Maintenance of Reservoirs, Dams, and Waterways 81,084 104,645
55 (544) Maintenance of Electric Plant 96,139 118,998
56 (545) Maintenance of Miscellaneous Hydraulic Plant 2,125,945 258,795
57 TOTAL Maintenance (Enter Total of lines 52 thru 56) 2,343,040 520,689
58 TOTAL Power Production Expenses - Hydraulic Power (Enter Total of lines 49 & 57) 4,401,964 2,607,738
59 D. Other Power Generation
60 Operation
61 (546) Operation Supervision and Engineering 20,072 21,032
62 (547) Fuel 16,485,247 18,275,033
63 (548) Generation Expenses 1,121,191 1,019,903
64 (549) Miscellaneous Other Power Generation Expenses 489,513 455,878
65 (550) Rents 270,231 168,480
66 TOTAL Operation (Enter Total of lines 61 thru 65) 18,386,254 19,940,326
67 Maintenance
68 (551) Maintenance Supervision and Engineering - -
69 (552) Maintenance of Structures 249,609 140,354
70 (553) Maintenance of Generation and Electric Plant 917,252 723,469
71 (554) Maintenance of Miscellaneous Other Power Generation Plant 166,612 177,191
72 TOTAL Maintenance (Enter Total of lines 68 thru 71) 1,333,473 1,041,014
73 TOTAL Power Production Expenses - Other Power (Enter Total of lines 66 & 72) 19,719,727 20,981,340
74 E. Other Power Supply Expenses
75 (555) Purchased Power 37,005,204 40,093,922
76 (556) System Control and Load Dispatching 38,775 45,552
77 (557) Other Expenses (1)6,498,197 6,797,525
78 TOTAL Other Power Supply Expenses (Enter Total of lines 75 thru 77) 43,542,176 46,936,999
79 TOTAL Power Production Expenses - (Enter Total of lines 20, 40, 58, 73 and 78) 129,303,589 136,376,897
80 2. TRANSMISSION EXPENSES
81 Operation
82 (560) Operation Supervision and Engineering 478,309 435,102
83 (561) Load Dispatching 975,221 1,206,737
84 (562) Station Expenses 195,271 184,669
85 (563) Overhead Line Expenses 59,424 64,407
86 (564) Underground Line Expenses - -
87 (565) Transmission of Electricity by Others 8,172,295 8,650,055
88 (566) Miscellaneous Transmission Expenses 174,050 177,709
89 (567) Rents 126,877 132,649
90 TOTAL Operation (Enter Total of lines 82 thru 89) 10,181,447 10,851,328
91 Maintenance
92 (568) Maintenance Supervision and Engineering 53,770 77,103
93 (569) Maintenance of Structures 322,149 342,147
94 (570) Maintenance of Station Equipment 641,186 697,326
95 (571) Maintenance of Overhead Lines 938,017 957,687
96 (572) Maintenance of Underground Lines 13,159 3,401
97 (573) Maintenance of Miscellaneous Transmission Plant 11,028 9,072
98 TOTAL Maintenance (Enter Total of lines 92 thru 97) 1,979,309 2,086,736
99 TOTAL Transmission Expenses (Enter Total of lines 90 and 98) 12,160,756 12,938,064
100 3. DISTRIBUTION EXPENSES
101 Operation
102 (580) Operation Supervision and Engineering 512,165 438,136
103 (581) Load Dispatching 638,335 607,671
(1)
IDAHO SUPPLEMENT
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
The Idaho amounts in Account 557 Other expenses are $5,662,197 for the current year and $5,961,983 for the previous year.
However, the amount for this year has been increased by $836,00 because of the impact of the 2020 Protocol Adjustment, while in the
prior year it was increased by $835,542 because of the impact of the 2020 Protocol Adjustment.
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report Is:
(1) _X_ An Original
(2) __ A resubmission
Date of Report
(Mo, Da, Yr)
May 25, 2021
Year of Report
Dec. 31, 2020
Page 4
Line
No.
Amount for
Current Year
Amount for
Previous Year
(b)(c)
157
158 - -
159 1,334,975 1,339,610
160 (6,862,853) (7,468,193)
161 838 3,145
162 125,181 125,122
163 133,406 125,510
164 13,966,073 4,810,393
165
166 1,394,078 1,388,548
167 15,360,151 6,198,941
168 171,222,722 168,721,821
Line Functional Classifications Operation Maintenance Total
No. (a) (b) (c) (d)
169 Power Production Expenses
170 Electric Generation:
171 Steam Power 53,257,021 8,382,701 61,639,722
172 Nuclear Power - - -
173 Hydraulic -Conventional 2,058,924 2,343,040 4,401,964
174 Other Power Generation 18,386,254 1,333,473 19,719,727
175 Other Power Supply Expenses 43,542,176 - 43,542,176
176 Total Power Production Expenses 117,244,375 12,059,214 129,303,589
177 Transmission Expenses 10,181,447 1,979,309 12,160,756
178 Distribution Expenses 2,993,192 6,571,074 9,564,266
179 Customer Accounts Expenses 4,481,904 - 4,481,904
180 Customer Service and Informational Expenses 352,056 - 352,056
181 Sales Expenses - - -
182 Adm. and General Expenses 13,966,073 1,394,078 15,360,151
183 Total Electric Operation and Maintenance Expenses 149,219,047 22,003,675 171,222,722
IDAHO SUPPLEMENT
(927) Franchise Requirements
(928) Regulatory Commission Expenses
(929) Duplicate Charges - Cr.
(930.1) General Advertising Expenses
(930.2) Miscellaneous General Expenses
(931) Rents
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) - IDAHO
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Account
(a)
TOTAL Operation (Enter Total of lines 150 thru 163)
7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
SUMMARY OF ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
Maintenance
(935) Maintenance of General Plant
TOTAL Administrative and General Expenses (Enter Total of lines 164 & 166)
TOTAL Electric Operation and Maintenance Expenses (Enter Total of lines 79, 99,
125, 133, 140, 147, and 167)
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report Is:
(1) _X_ An Original
(2) __ A resubmission
Date of Report
(Mo, Da, Yr)
May 25, 2021
Year of Report
Dec. 31, 2020
Page 6
Line
No.Functional Classification
Depreciation
Expense
(Account 403) (1)
Amortization of
Limited-Term Electric
Plant (Acct. 404)
Amortization of
Other Electric
Plant (Acct. 405)
Total
(a)(b)(c)(d)(e)
1 Intangible Plant - 2,217,560 - 2,217,560
2 Steam Production Plant 14,688,069 - - 14,688,069
3 Nuclear Production Plant - - - -
4 Hydraulic Production Plant - Conventional 1,735,249 17,835 - 1,753,084
5 Hydraulic Production Plant - Pumped Storage - - - -
6 Other Production Plant 7,241,637 - - 7,241,637
7 Transmission Plant 6,645,286 - - 6,645,286
8 Distribution Plant 7,681,754 - - 7,681,754
9 General Plant 2,456,998 15,501 - 2,472,499
10 Common Plant - Electric - - - -
11 TOTAL 40,448,993 2,250,896 - 42,699,889
(1) Depreciation expense associated with transportation equipment is generally charged to operations and maintenance
expense and construction work in progress.
IDAHO SUPPLEMENT
A. Summary of Depreciation and Amortization Charges
STATE OF IDAHO - ALLOCATED
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Accounts 403, 404, 405)
(Except amortization of acquisition adjustments)
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report Is:
(1) _x An Original
(2) __ A resubmission
Date of Report
(Mo, Da, Yr)
May 25, 2021
Year of Report
Dec. 31, 2020
Page 7
KIND OF TAX AMOUNT
1 Property 8,931,046
2 Other 863,138
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20 Total ( Must agree with page 1, line 11.)9,794,184
(1) Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
TAXES, OTHER THAN INCOME TAXES
ACCOUNT 408.1 (1)
Page 8
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report Is:
(1) _X_ An Original
(2) __ A resubmission
Date of Report
(Mo, Da, Yr)
May 25, 2021
Year of Report
Dec. 31, 2020
Location Description Description
Beginning Balance
(c)
Acquistion
(d)
Retirement
(e)
Transfer
(f)
Balance at End of Year
(g)
1 IDAHO FALLS POLE TREATING PLANT Fee Land 54,317 54,317
2 MALAD PLANT SITE AND WATER RIGHTS Land Rights 33 33
3 GEORGETOWN PLANT LAND Fee Land 110 110
4 LAVA DEVELOPMENT Land Rights 1,274 1,274
5 MENAN SUBSTATION SITE Fee Land 55 55
6 UCON SITE - CATERCORNER TO UCON SUBSTATION Fee Land 27 27
7 OLD DUBOIS SUBSTATION SITE Fee Land 75 75
8 EAST RIVER SUBSTATION SITE Fee Land 13,742 13,742
9 NORTH MONTEVIEW SUBSTATION SITE Fee Land 328 328
10 MONTEVIEW SUBSTATION SITE Fee Land 618 618
11 MUD LAKE SERVICE CENTER Fee Land 17,915 17,915
12 LAVA SUBSTATION AND SERVICE CENTER Fee Land 382 (382) -
13 Total Non-Utility Property 88,876 - (382) - 88,494
Pa
g
e

9
NON-UTILITILY PROPERTY (ACCOUNT 121)
ID
A
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P
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Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report Is:
(1) _X An Original
(2) __ A resubmission
Date of Report
(Mo, Da, Yr)
May 25, 2021
Year of Report
Dec. 31, 2020
Line
No.Account
Amount for
Current Year
Amount for
Previous Year
(a)(b)(c)
1 UTILITY PLANT
2 In Service
3 Plant In Service (Classified) 1,656,883,332 1,609,735,369
4 Property Under Capital Lease (1)- -
5 Plant Purchased or Sold - -
6 Completed Construction not Classified 41,035,931 13,990,267
7 Experimental Plant Unclassified - -
8 Total (Enter Total of Lines 3 through 7) 1,697,919,263 1,623,725,636
9 Leased To Others - -
10 Held for Future Use 606,721 743,669
11 Construction Work In Process (2)- -
12 Acquisition Adjustments 8,280,065 8,553,673
13 Total Utility Plant (Enter Total of Lines 8 through 12) 1,706,806,049 1,633,022,978
14 Accumulated Provision for Depreciation, Amortization & Depletion 558,762,492 583,411,736
15 Net Utility Plant (Enter Total of Line 13 less Line 14) 1,148,043,557 1,049,611,242
16
DETAIL OF ACCUMULATED PROVISION FOR DEPRECIATION,
AMORTIZATION AND DEPLETION
17 In Service
18 Depreciation 512,940,617 538,669,948
19 Amortization/Depletion of Producing Natural Gas Land And Land Rights - -
20 Amortization of Underground Storage Land and Land Rights - -
21 Amortization of Other Utility Plant 38,063,374 37,009,557
22 Total In Service (Enter Total of Lines 18 through 21) 551,003,991 575,679,505
23 Leased To Others
24 Depreciation - -
25 Amortization And Depletion - -
26 Total Leased to Others (Enter Total of Lines 24 and 25) - -
27 Held for Future Use
28 Depreciation - -
29 Amortization - -
30 Total Held for Future Use (Enter Total of Lines 28 and 29) - -
31 Abandonment of Leases (Natural Gas) - -
32 Accumulated Provision for Asset Acquisition Adjustment 7,758,501 7,732,231
33
Total Accumulated Provisions (Should Agree With Line 14 above)
(Enter Total of Lines 22, 26, 30, 31 and 32)558,762,492 583,411,736
34
IDAHO SUPPLEMENT
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
(2) Construction Work In Process ("CWIP") is not included in rate base and it is not assigned allocation factors until it
goes into service. On a total company basis, CWIP was $1,539,838,861at December 31, 2020.
(1) Capitalized lease assets are not included in rate base; they are included in operating expense as rent expense.
Name of RespondentPacifiCorp
dba Rocky Mountain Power
This Report Is:(1) _X_ An Original
(2) __ A resubmission
Date of Report(Mo, Da, Yr)
May 25, 2021
Year of Report
Dec. 31, 2020
Page 10
Line
No.Account Beginning Balance
Balance at End of
Year
(a)(b)(g)
1 1. INTANGIBLE PLANT
2 (301) Organization - -
3 (302) Franchises and Consents 12,558,231 12,199,103
4 (303) Miscellaneous Intangible Plant 44,786,124 46,985,663
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)57,344,355 59,184,766
6 2. PRODUCTION PLANT
7 A Steam Production Plant
8 (310) Land and Land Rights 5,496,677 5,320,854
9 (311) Structures and Improvements 62,095,207 60,467,300
10 (312) Boiler Plant Equipment 273,912,728 266,365,529
11 (313) Engines and Engine Driven Generators - -
12 (314) Turbogenerator Units 59,332,914 57,698,249
13 (315) Accessory Electric Equipment 28,928,131 28,151,523
14 (316) Misc. Power Plant Equipment 1,995,931 1,981,708
15 TOTAL Steam Production Plant (Enter Total of lines 8 thru 14)431,761,588 419,985,163
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 TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 22)- -
24 C. Hydraulic Production Plant
25 (330) Land and Land Rights 2,146,926 2,080,421
26 (331) Structures and Improvements 16,485,450 16,394,808
27 (332) Reservoirs, Dams, and Waterways 30,497,570 30,374,301
28 (333) Water Wheels, Turbines, and Generators 8,387,526 8,356,780
29 (334) Accessory Electric Equipment 5,038,180 4,924,923
30 (335) Misc. Power Plant Equipment 151,171 146,738
31 (336) Roads, Railroads, and Bridges 1,474,512 1,495,048
32 TOTAL Hydraulic Production Plant (Enter Total of lines 25 thru 31)64,181,335 63,773,019
33 D. Other Production Plant
34 (340) Land and Land Rights 3,007,808 2,920,054
35 (341) Structures and Improvements 13,579,128 15,311,316
36 (342) Fuel Holders, Products, and Accessories 956,906 936,771
37 (343) Prime Movers 165,249,468 194,421,095
38 (344) Generators 29,446,063 31,608,175
39 (345) Accessory Electric Equipment 19,171,041 23,000,047
40 (346) Misc. Power Plant Equipment 941,306 1,288,111
41 TOTAL Other Production Plant (Enter Total of lines 34 thru 40)232,351,720 269,485,569
42 TOTAL Production Plant (Enter Total of lines 15, 23, 32, and 41)728,294,643 753,243,751
IDAHO SUPPLEMENT
(In addition to Account 101, Electric Plant In Service (Classified), this schedule includes Account 102, Electric Plant
Purchased or Sold, Account 103, Experimental Electric Plant Unclassified and
Account 106, Completed Construction Not Classified-Electric.)
ELECTRIC PLANT IN SERVICE - STATE OF IDAHO (ALLOCATED)
1. Report below the original cost of electric plant in
service according to prescribed accounts.
2. Do not include as adjustments, corrections of
additions and retirements for the current or the
preceding year.
3. Credit adjustments of plant accounts should be
enclosed in parentheses to indicate the negative effect
of such amounts.
Page 11
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report Is:
(1) _X_ An Original
(2) __ A resubmission
Date of Report
(Mo, Da, Yr)
May 25, 2021
Year of Report
Dec. 31, 2020
Line
No.Account Beginning Balance
Balance End of
Year
(a) (b) (g)
43 3. TRANSMISSION PLANT
44 (350) Land and Land Rights 16,587,091 17,461,725
45 (352) Structures and Improvements 16,708,847 17,522,634
46 (353) Station Equipment 131,138,148 131,628,554
47 (354) Towers and Fixtures 77,206,535 75,365,034
48 (355) Poles and Fixtures 59,732,112 59,416,332
49 (356) Overhead Conductors and Devices 75,734,497 76,566,856
50 (357) Underground Conduit 227,509 220,713
51 (358) Underground Conductors and Devices 486,986 519,597
52 (359) Roads and Trails 705,623 695,000
53 TOTAL Transmission Plant (Enter Total of lines 44 thru 52)378,527,348 379,396,445
54 4. DISTRIBUTION PLANT
55 (360) Land and Land Rights 1,835,903 1,835,903
56 (361) Structures and Improvements 3,366,731 3,368,537
57 (362) Station Equipment 37,524,250 38,256,405
58 (363) Storage Battery Equipment - -
59 (364) Poles, Towers, and Fixtures 94,598,436 98,739,838
60 (365) Overhead Conductors and Devices 40,464,083 41,785,421
61 (366) Underground Conduit 10,668,846 11,672,129
62 (367) Underground Conductors and Devices 29,478,412 31,258,339
63 (368) Line Transformers 85,091,706 86,895,810
64 (369) Services 44,726,689 46,988,045
65 (370) Meters 16,827,950 17,554,730
66 (371) Installations on Customer Premises 170,194 170,534
67 (372) Leased Property on Customer Premises - -
68 (373) Street Lighting and Signal Systems 770,243 813,920
69 TOTAL Distribution Plant (Enter Total of lines 55 thru 68) 365,523,443 379,339,611
70 5. GENERAL PLANT
71 (389) Land and Land Rights 671,121 668,380
72 (390) Structures and Improvements 18,114,649 18,392,116
73 (391) Office Furniture and Equipment 3,912,030 4,443,964
74 (392) Transportation Equipment 8,277,652 10,187,980
75 (393) Stores Equipment 873,089 960,272
76 (394) Tools, Shop and Garage Equipment 3,706,858 3,692,335
77 (395) Laboratory Equipment 2,054,313 2,073,210
78 (396) Power Operated Equipment 14,021,353 17,024,306
79 (397) Communication Equipment 27,920,207 27,791,957
80 (398) Miscellaneous Equipment 373,337 365,282
81 SUBTOTAL (Enter Total of lines 71 thru 80) 79,924,609 85,599,802
82 (399) Other Tangible Property 120,971 118,957
83 TOTAL General Plant (Enter Total of lines 81 thru 82) 80,045,580 85,718,759
84 TOTAL (Accounts 101) 1,609,735,369 1,656,883,332
85 (102) Electric Plant Purchased - -
86 Less (102) Electric Plant Sold - -
87 (103) Experimental Electric Plant Unclassified - -
88 (106) Plant Unclassified 13,990,267 41,035,931
89 TOTAL Electric Plant in Service 1,623,725,636 1,697,919,263
IDAHO SUPPLEMENT
ELECTRIC PLANT IN SERVICE (Continued) STATE OF IDAHO (ALLOCATED)
Page 12
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report Is:
(1) _X_ An Original
(2) __ A resubmission
Date of Report
(Mo, Da, Yr)
May 25, 2021
Year of Report
Dec. 31, 2020
Line ACCOUNT
Balance
Beginning of
Year
Balance
End of Year
Department or
Departments
Which Use Material
No. (a) (b) (c) (d)
1 Fuel Stock (Account 151) 14,199,711 Electric
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated) 9,467,446 Electric
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated) 4,111,497 Electric
8 Transmission Plant (Estimated) 61,683 Electric
9 Distribution Plant (Estimated) 690,706 Electric
10 Assigned to - Other (70,141) Electric
11 TOTAL Account 154 (Enter Total of lines 5 thru 10) 14,261,191
12 Merchandise (Account 155)
13 Other Materials and Supplies (Account 156)
14 Nuclear Materials Held for Sale (Account 157) (Not applicable to Gas
Utilities)
15 Stores Expense Undistributed (Account 163)
16
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet) 28,460,902
IDAHO SUPPLEMENT Page 13
STATE OF IDAHO --ALLOCATED
MATERIALS AND SUPPLIES
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report Is:
(1) _X_ An Original
(2) __ A resubmission
Date of Report
(Mo, Da, Yr)
May 25, 2021
Year of Report
Dec. 31, 2020
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 (on a supplemental page) showing general
classes of material and supplies and the various
accounts (operating expense, clearing accounts, plant,
etc.) affected - debited or credited. Show separately
debits or credits to stores expense clearing, if
applicable.