2023Annual Report FERC Form 1..pdf

1407 W. North Temple, Suite 330

Salt Lake City, UT 84116
April 22, 2024
VIA ELECTRONIC DELIVERY
Commission Secretary
Idaho Public Utilities Commission
11331 W Chinden Blvd.
Building 8 Suite 201A
Boise, ID 83714
Re: FERC Form 1
Attention: Commission Secretary
Rocky Mountain Power, a division of PacifiCorp, submits for electronic filing PacifiCorp’s annual
FERC Form 1 report for the year ended December 31, 2023.
PacifiCorp respectfully requests that all data requests regarding this matter be addressed to:
By email (preferred): [e-mail]
By regular mail: Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
Informal inquiries may be directed to Mark Alder, Idaho Regulatory Manager at [phone].
Very truly yours,
Joelle Steward
Senior Vice President of Regulation and Customer Solutions
Enclosures
RECEIVED
Monday, April 22, 2024 12:48:14 PM
IDAHO PUBLIC
UTILITIES COMMISSION
PAC-E
THIS FILING IS
Item 1: ☑ An Initial (Original) Submission OR ☐ Resubmission No.
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
Exact Legal Name of Respondent (Company)
PacifiCorp
Year/Period of Report
End of: 2023/ Q4
FERC FORM NO. 1 (REV. 02-04)
INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q
GENERAL INFORMATION
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.
Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of
Accounts Prescribed for Public Utilities, Licensees, and Others 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:
one million megawatt hours of total annual sales,
100 megawatt hours of annual sales for resale,
500 megawatt hours of annual power exchanges delivered, or
500 megawatt hours of annual wheeling for others (deliveries plus losses).
What and Where to Submit
Submit FERC Form Nos. 1 and 3-Q electronically through the eCollection portal at
https://eCollection.ferc.gov, and according to the specifications in the Form 1 and 3-Q taxonomies.
The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1
and 3-Q filings.
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
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.
The CPA Certification Statement should:
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
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.)
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
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 [COMPANY NAME] for
the year ended on which we have reported separately under date of [DATE], we have also
reviewed schedules [NAME OF 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.
Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification
Statement using eFiling. Further instructions are found on the Commission’s website at
https://www.ferc.gov/ferc-online/ferc-online/frequently-asked-questions-faqs-efilingferc-online.
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 https://www.ferc.gov/general-information-
0/electric-industry-forms.
When to Submit
FERC Forms 1 and 3-Q must be filed by the following schedule:
FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year
(18 CFR § 141.1), and
FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter
(18 C.F.R. § 141.400).
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
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.
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.
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).
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.
For any resubmissions, please explain the reason for the resubmission in a footnote to the data field.
Do not make references to reports of previous periods/years or to other reports in lieu of required
entries, except as specifically authorized.
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.
Schedule specific instructions are found in the applicable taxonomy and on the applicable blank
rendered form.
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
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
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.
Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or
instrumentality in whose behalf the report is made.
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:
’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;
'Person' means an individual or a corporation;
'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;
'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; ......
"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
'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.
Every Licensee and every public utility shall file with the Commission such annual and other periodic or
special* reports as the Commission may by 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 shall 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
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4.
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b.
c.
d.
a.
b.
e.
f.
g.
IV.
a.
b.
V.
III.
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any penalty if any collection of information does not display a valid control number (44 U.S.C. § 3512
(a)).
GENERAL INSTRUCTIONS
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.
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.
determining such costs and other facts. Such reports shall be made under oath unless the Commission
otherwise specifies*.10
"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 NO. 1 (ED. 03-07)
I.
II.
FERC FORM NO. 1
REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent
PacifiCorp
02 Year/ Period of Report
End of: 2023/ Q4
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)
825 N.E. Multnomah Street, Suite 1900, Portland, OR 97232
05 Name of Contact Person
Jennifer Kahl
06 Title of Contact Person
External Reporting Director
07 Address of Contact Person (Street, City, State, Zip Code)
825 N.E. Multnomah Street, Suite 1900, Portland, OR 97232
08 Telephone of Contact Person, Including Area Code
[phone]
09 This Report is An Original / A Resubmission
(1) ☑ An Original
(2) ☐ A Resubmission
10 Date of Report (Mo, Da, Yr)
04/11/2024
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.
01 Name
Nikki L. Kobliha
02 Title
Vice President, Chief Financial Officer and Treasurer
03 Signature
/s/ Nikki L. Kobliha
04 Date Signed (Mo, Da, Yr)
04/11/2024
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.
FERC FORM No. 1 (REV. 02-04)
Page 1
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
LIST OF SCHEDULES (Electric Utility)
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".
Line
No.
Title of Schedule
(a)
Reference Page No.
(b)
Remarks
(c)
1
2
1 101
2 102
3 103
4 104
5 105
6 106
7 108
8 110
9 114
10 118
12 120
12 122
13 122a
14 200
15 202 N/A
16 204
17 213 N/A
18 214
19 216
20 219
21 224
22 227
23 228
24 230a N/A
25 230b N/A
26 231
27 232
28 233
29 234
30 250
31 253
32 254b
33 256
34 261
35 262
36 266
37 269
38 272
39 274
40 276
41 278
42 300
Identification
List of Schedules
General Information
Control Over Respondent
Corporations Controlled by Respondent
Officers
Directors
Information on Formula Rates
Important Changes During the Year
Comparative Balance Sheet
Statement of Income for the Year
Statement of Retained Earnings for the Year
Statement of Cash Flows
Notes to Financial Statements
Statement of Accum Other Comp Income, Comp Income, and Hedging
Activities
Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep
Nuclear Fuel Materials
Electric Plant in Service
Electric Plant Leased to Others
Electric Plant Held for Future Use
Construction Work in Progress-Electric
Accumulated Provision for Depreciation of Electric Utility Plant
Investment of Subsidiary Companies
Materials and Supplies
Allowances
Extraordinary Property Losses
Unrecovered Plant and Regulatory Study Costs
Transmission Service and Generation Interconnection Study Costs
Other Regulatory Assets
Miscellaneous Deferred Debits
Accumulated Deferred Income Taxes
Capital Stock
Other Paid-in Capital
Capital Stock Expense
Long-Term Debt
Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax
Taxes Accrued, Prepaid and Charged During the Year
Accumulated Deferred Investment Tax Credits
Other Deferred Credits
Accumulated Deferred Income Taxes-Accelerated Amortization Property
Accumulated Deferred Income Taxes-Other Property
Accumulated Deferred Income Taxes-Other
Other Regulatory Liabilities
Electric Operating Revenues
43 302 N/A
44 304
45 310
46 320
47 326
48 328
49 331 N/A
50 332
51 335
52 336
53 350
54 352 N/A
55 354
56 356 N/A
57 397
58 398
59 400
60 400a N/A
61 401a
62 401b
63 402
64 406
65 408 N/A
66 410
66.1 414
66.2 419
67 422
68 424
69 426
70 429
71 450
Stockholders' Reports Check appropriate box:
☑ Two copies will be submitted
☐ No annual report to stockholders is prepared
FERC FORM No. 1 (ED. 12-96)
Page 2
Regional Transmission Service Revenues (Account 457.1)
Sales of Electricity by Rate Schedules
Sales for Resale
Electric Operation and Maintenance Expenses
Purchased Power
Transmission of Electricity for Others
Transmission of Electricity by ISO/RTOs
Transmission of Electricity by Others
Miscellaneous General Expenses-Electric
Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
Regulatory Commission Expenses
Research, Development and Demonstration Activities
Distribution of Salaries and Wages
Common Utility Plant and Expenses
Amounts included in ISO/RTO Settlement Statements
Purchase and Sale of Ancillary Services
Monthly Transmission System Peak Load
Monthly ISO/RTO Transmission System Peak Load
Electric Energy Account
Monthly Peaks and Output
Steam Electric Generating Plant Statistics
Hydroelectric Generating Plant Statistics
Pumped Storage Generating Plant Statistics
Generating Plant Statistics Pages
Energy Storage Operations (Large Plants)
Energy Storage Operations (Small Plants)
Transmission Line Statistics Pages
Transmission Lines Added During Year
Substations
Transactions with Associated (Affiliated) Companies
Footnote Data
Stockholders' Reports (check appropriate box)
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
GENERAL INFORMATION
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.
Nikki L. Kobliha
Vice President, Chief Financial Officer and Treasurer
825 N.E. Multnomah Street, Suite 1900, Portland, OR 97232
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.
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.
State of Incorporation:
Date of Incorporation:
Incorporated Under Special Law:
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.
Not applicable.
(a) Name of Receiver or Trustee Holding Property of the Respondent:
(b) Date Receiver took Possession of Respondent Property:
(c) Authority by which the Receivership or Trusteeship was created:
(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.
PacifiCorp is a United States regulated electric utility company headquartered in Oregon that serves approximately 2.1 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.
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
(2) ☑ No
FERC FORM No. 1 (ED. 12-87)
Page 101
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the respondent 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 beneficiaries for whom trust was maintained, and purpose of the trust.
Berkshire Hathaway Inc.
Berkshire Hathaway Energy Company ("BHE") (100%)
PPW Holdings LLC (100% controlled by BHE)
PacifiCorp (100% of common stock held by PPW Holdings LLC)
Berkshire Hathaway Inc. owns 92.0% of BHE's voting common stock. The balance of BHE's common stock is privately held by a limited group of investors.
FERC FORM No. 1 (ED. 12-96)
Page 102
1
1
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
CORPORATIONS CONTROLLED BY RESPONDENT
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.
Line
No.(a)(b)(c)(d)
1 Energy West Mining Company Mining 100%(a)
See footnote
2 Pacific Minerals, Inc.Management services 100%(b)
See footnote
3 Bridger Coal Company Mining 66.67%(c)
See footnote
4 Trapper Mining Inc.Mining 29.14%(d)
See footnote
5 PacifiCorp Foundation Non-profit foundation (e)
See footnote
FERC FORM No. 1 (ED. 12-96)
Page 103
Name of Company Controlled Kind of Business Percent Voting
Stock Owned Footnote Ref.
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: FootnoteReferences
Energy West Mining Company ceased mining operations in 2015.
(b) Concept: FootnoteReferences
Pacific Minerals, Inc. is a wholly owned subsidiary of PacifiCorp that holds a 66.67% ownership interest in Bridger Coal Company.
(c) Concept: FootnoteReferences
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.
(d) Concept: FootnoteReferences
PacifiCorp is a minority owner in Trapper Mining Inc., a cooperative. As of December 31, 2023, the members were Salt River Project Agricultural Improvement and Power District (43.72%), PacifiCorp (29.14%) and Platte
River Power Authority (27.14%).
(e) Concept: FootnoteReferences
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, 2023, the Foundation's two directors are also directors of PacifiCorp.
FERC FORM No. 1 (ED. 12-96)
Page 103
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
OFFICERS
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.
Line
No.(a)(b)(c)(d)(e)
1 (a)
Executive Officers as of December 31, 2023:
2 Chair of the Board of Directors and Chief Executive
Officer, PacifiCorp
(b)
Cindy A. Crane 633,338 2023-09-01
3 Former Chair of the Board of Directors and Chief
Executive Officer, PacifiCorp
(c)
Scott W. Thon 2023-09-01
4 President and Chief Executive Officer, Pacific Power (d)
Stefan A. Bird 525,500
5 President and Chief Executive Officer, Rocky
Mountain Power
(e)
Gary W. Hoogeveen 525,500
6 Vice President, Chief Financial Officer and Treasurer,
PacifiCorp Nikki L. Kobliha 301,446
FERC FORM No. 1 (ED. 12-96)
Page 104
Title Name of Officer Salary for Year Date Started in Period Date Ended in Period
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: OfficerTitle
PacifiCorp sets forth compensation information for its "named executive officers" for the year ended December 31, 2023 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).
(b) Concept: OfficerName
On September 1, 2023, Mr. Scott W. Thon resigned as PacifiCorp's Chair of the Board of Directors and Chief Executive Officer and Ms. Cindy A. Crane was elected as PacifiCorp's Chair of the Board of Directors and Chief
Executive Officer. Mr. Thon did not receive any direct compensation from PacifiCorp in 2023. Rather, PacifiCorp reimbursed its indirect parent company, Berkshire Hathaway Energy Company ("BHE"), for the cost of Mr.
Thon'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. As an employee of PacifiCorp,
Ms. Crane receives direct compensation from PacifiCorp. For further information on executive compensation, refer to BHE’s Annual Report on Form 10-K for the year ended December 31, 2023.
(c) Concept: OfficerName
On September 1, 2023, Mr. Scott W. Thon resigned as PacifiCorp's Chair of the Board of Directors and Chief Executive Officer and Ms. Cindy A. Crane was elected as PacifiCorp's Chair of the Board of Directors and Chief
Executive Officer. Mr. Thon did not receive any direct compensation from PacifiCorp in 2023. Rather, PacifiCorp reimbursed its indirect parent company, Berkshire Hathaway Energy Company ("BHE"), for the cost of Mr.
Thon'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. As an employee of PacifiCorp,
Ms. Crane receives direct compensation from PacifiCorp. For further information on executive compensation, refer to BHE’s Annual Report on Form 10-K for the year ended December 31, 2023.
(d) Concept: OfficerName
On January 2, 2024, Mr. Stefan A. Bird resigned as Pacific Power's President and Chief Executive Officer.
(e) Concept: OfficerName
On April 2, 2024, Mr. Gary W. Hoogeveen resigned as Rocky Mountain Power's President and Chief Executive Officer.
FERC FORM No. 1 (ED. 12-96)
Page 104
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
DIRECTORS
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), name and abbreviated titles of the directors who are officers of the
respondent.
2. Provide the principle place of business in column (b), designate members of the Executive Committee in column (c), and the Chairman of the Executive Committee in column (d).
Line
No.(a)(b)(c)(d)
1 Cindy A. Crane (Chair of the Board of Directors and
Chief Executive Officer, PacifiCorp)
825 N.E. Multnomah Street, Suite 2000, Portland,
OR 97232 false false
2 Scott W. Thon (Former Chair of the Board of
Directors and Chief Executive Officer, PacifiCorp)
666 Grand Avenue, 27th Floor, Des Moines, IA
50309 false false
3 Stefan A. Bird (President and Chief Executive
Officer, Pacific Power)
825 N.E. Multnomah Street, Suite 2000, Portland,
OR 97232 false false
4 Gary W. Hoogeveen (President and Chief
Executive Officer, Rocky Mountain Power)
1407 West North Temple, Suite 310, Salt Lake City,
UT 84116 false false
5 Nikki L. Kobliha (Vice President, Chief Financial
Officer and Treasurer, PacifiCorp)
825 N.E. Multnomah Street, Suite 1900, Portland,
OR 97232 false false
6 Calvin D. Haack 666 Grand Avenue, 27th Floor, Des Moines, IA
50309 false false
7 Natalie L. Hocken 825 N.E. Multnomah Street, Suite 2000, Portland,
OR 97232 false false
FERC FORM No. 1 (ED. 12-95)
Page 105
Name (and Title) of Director Principal Business Address Member of the Executive Committee Chairman of the Executive Committee
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
INFORMATION ON FORMULA RATES
Does the respondent have formula rates?
☑ Yes
☐ No
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.
Line
No.(a)(b)
1 FERC Electric Tariff Volume No. 11, Attachment H-1 ER23-1892
FERC FORM No. 1 (NEW. 12-08)
Page 106
FERC Rate Schedule or Tariff Number FERC Proceeding
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or
more frequent) filings containing the inputs to the formula
rate(s)?
☑ Yes
☐ No
If yes, provide a listing of such filings as contained on the Commission's eLibrary website.
Line
No.(a)(b)(c)(d)(e)
1 20230324-5095 03/24/2023 ER23-1455-000 (a)
See footnote PacifiCorp's Volume No. 11 Open Access
Transmission Tariff
2 20230511-5196 05/11/2023 EL22-38-000, ER23-1865-001 (b)
See footnote PacifiCorp's Volume No. 11 Open Access
Transmission Tariff
3 20230515-5329 05/15/2023 ER23-1892-000 (c)
See footnote PacifiCorp's Volume No. 11 Open Access
Transmission Tariff
4 20231218-5081 12/18/2023 ER24-692-000 (d)
See footnote PacifiCorp's Volume No. 11 Open Access
Transmission Tariff
FERC FORM NO. 1 (NEW. 12-08)
Page 106a
2.
Accession No.Document Date / Filed Date Docket No.Description Formula Rate FERC Rate Schedule Number
or Tariff Number
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionOfFiling
PacifiCorp submits tariff filing per 35.13(a)(2)(iii: OATT Revised Attachment H-1 (Rev Depreciation Rates 2023) to be effective 6/1/2023 under ER23-1455
(b) Concept: DescriptionOfFiling
PacifiCorp submits Compliance Filing under ER23-1865
(c) Concept: DescriptionOfFiling
Informational Filing of 2023 Formula Rate Annual Update of PacifiCorp under ER23-1892
(d) Concept: DescriptionOfFiling
PacifiCorp submits tariff filing per 35.13(a)(2)(iii: PacifiCorp OATT Revised Attachment H-1 - Attachments 3 and 5 to be effective 2/17/2024 under ER24-692
FERC FORM NO. 1 (NEW. 12-08)
Page 106a
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
INFORMATION ON FORMULA RATES - Formula Rate Variances
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 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.
Line No.(a)(b)(c)(d)
1 204-207 Electric Plant in Service (b)46
2 204-207 Electric Plant in Service (g)46
3 204-207 Electric Plant in Service (b)58
4 204-207 Electric Plant in Service (g)58
5 204-207 Electric Plant in Service (b)75
6 204-207 Electric Plant in Service (g)75
7 204-207 Electric Plant in Service (b)99
8 204-207 Electric Plant in Service (g)99
9 204-207 Electric Plant in Service (b)104
10 204-207 Electric Plant in Service (g)104
11 219 Accumulated Provision for Depreciation of Electric Utility Plant (c)20
12 219 Accumulated Provision for Depreciation of Electric Utility Plant (c)22
13 219 Accumulated Provision for Depreciation of Electric Utility Plant (c)24
14 219 Accumulated Provision for Depreciation of Electric Utility Plant (c)25
15 219 Accumulated Provision for Depreciation of Electric Utility Plant (c)26
16 219 Accumulated Provision for Depreciation of Electric Utility Plant (c)28
17 219 Accumulated Provision for Depreciation of Electric Utility Plant (c)29
18 232 Other Regulatory Assets (f)18
19 232 Other Regulatory Assets (f)25
20 232 Other Regulatory Assets (f)35
21 320-323 Electric Operation and Maintenance Expenses (b)181
22 320-323 Electric Operation and Maintenance Expenses (b)185
23 320-323 Electric Operation and Maintenance Expenses (b)193
24 320-323 Electric Operation and Maintenance Expenses (b)196
25 320-323 Electric Operation and Maintenance Expenses (b)197
FERC FORM No. 1 (NEW. 12-08)
Page 106b
Page No(s).Schedule Column Line No.
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR
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 Pages 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.
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
None
Idaho
Arimo 03/01/2023 03/01/2048 —%
Paris 01/01/2023 01/01/2038 3.0%
Oregon
Adams 06/25/2023 06/25/2043 6.5%
Arlington 09/01/2023 09/01/2048 5.0%
Brownsville 02/19/2023 02/19/2033 5.0%
Grass Valley 12/19/2023 12/19/2043 3.5%
Medford 10/15/2023 10/15/2028 9.0%
Moro 06/30/2023 06/30/2043 3.5%
Weston 12/15/2023 12/15/2028 7.0%
Utah
Castle Valley 02/01/2023 02/01/2043 —%
Cedar City 04/15/2023 04/15/2033 —%
Clearfield 06/27/2023 06/27/2033 —%
Hooper 04/15/2023 04/15/2033 —%
Lakepoint 04/01/2023 04/01/2043 —%
Lehi 04/01/2023 04/01/2033 —%
Lewiston 07/01/2023 07/01/2038 —%
Mapleton 08/01/2023 08/01/2028 6.0%
Park City 04/01/2023 04/01/2028 2.5%
Provo 10/01/2023 10/01/2033 6.0%
Richmond 09/01/2023 09/01/2028 6.0%
Smithfield 09/01/2023 09/01/2028 6.0%
Syracuse 04/15/2023 04/15/2043 —%
Washington
Walla Walla County 07/19/2023 07/19/2048 6.0%
Wyoming
Evansville 06/01/2023 06/01/2048 2.5%
Glenrock 01/28/2023 01/28/2048 2.0%
Mills 12/23/2023 12/23/2033 7.0%
(1) In California, franchise agreement fees are an expense to PacifiCorp and are embedded in rates.
(2) In Idaho, PacifiCorp collects franchise agreement fees from customers and remits them directly to the applicable municipalities.
(3) In Oregon, the first 3.5% of the franchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 3.5% is collected from customers and remitted directly to the applicable municipalities.
(4) In Utah, 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.
ITEM 2.
None.
ITEM 3.
In December 2022, PacifiCorp transferred the Lower Klamath Hydroelectric Project dams to the Klamath River Renewal Corporation (KRRC) and the States of Oregon and California who accepted license transfer and co-licensee status as outlined in the Federal Energy Regulatory
Commission’s (FERC) order issued November 17, 2022 in Docket No. P-14803-001 and P-2082-063, modifying and approving surrender of the license and removal of the project facilities, which will be performed by the KRRC. In February and April 2023, PacifiCorp filed for approval
with the FERC the accounting entries required by the Uniform System of Accounts to use account 102, Electric plant purchased or sold, for the transfer. In May 2023, the FERC approved PacifiCorp's accounting entries in Docket No. AC23-26-000. Accordingly, PacifiCorp cleared account
102, Electric plant purchased or sold, and recorded the transfer to account 182.3, Other regulatory assets as approved by the FERC. Refer to Note 14 of Notes to Financial Statements in this Form No. 1 for additional discussion regarding the Lower Klamath Hydroelectric Project.
ITEM 4.
None.
ITEM 5.
In August 2023, PacifiCorp placed into service a 4-mile single-circuit 230kV transmission line in Oregon between the Klamath Falls substation and Snow Goose substation. Refer to Pages 424-425, Transmission lines added or altered, in this Form No. 1 for additional information regarding
transmission lines added or removed during the year ended December 31, 2023.
For the year ended December 31, 2023, PacifiCorp did not significantly increase or decrease its distribution territory.
(1)
(2)
(3)
(4)
(5)
(6)
ITEM 6.
Short-term Debt and Credit Facilities
As of December 31, 2023, PacifiCorp had $1.6 billion of short-term debt outstanding at a weighted average rate of 6.16%, which was subsequently repaid in January 2024.
Commission authorizations currently for up to $2.0 billion outstanding at any one time in commercial paper and other unsecured short-term debt are as follows:
•FERC – Docket No. ES23-3-000, dated December 23, 2022, letter order effective January 1, 2023 through December 31, 2024.
•Idaho Public Utilities Commission (IPUC) – Case No. PAC-E-22-17, Order No. 35630, dated December 15, 2022, effective through November 30, 2027.
•Oregon Public Utility Commission (OPUC) – Docket No. UF 4335, Order No. 22-472, dated December 13, 2022, effective through December 31, 2029.
•Washington Utilities and Transportation Commission (WUTC) – Docket No. UE-980404, dated April 8, 1998.
In June 2023, PacifiCorp amended and restated its existing $1.2 billion unsecured credit facility expiring in June 2025. The amendment increased the lender commitment to $2.0 billion and extended the expiration date to June 2026.
As of December 31, 2023, PacifiCorp had $255 million of letter of credit capacity under its $2.0 billion revolving credit facility of which $31 million was outstanding and was utilized as a standby letter of credit, and $168 million of letter of credit capacity outside of its $2.0 billion
revolving credit facility, of which $55 million was outstanding and was utilized in support of certain transactions required by third parties.
While PacifiCorp's current revolving credit facility is unsecured, upon future renewal, PacifiCorp may be required to secure the facility, which could further limit the amount of First Mortgage Bonds PacifiCorp can issue.
Long-term Debt
In May 2023, PacifiCorp issued $1.2 billion of its 5.500% First Mortgage Bonds due May 2054. PacifiCorp intends within 24 months of the issuance date, to allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing investments or expenditures
made in one or more eligible projects in alignment with BHE's Green Financing Framework.
State commission authorizations for the above issuance were as follows:
•OPUC – Docket No. UF-4337, Order No. 23-105, dated March 21, 2023.
•IPUC – Case No. PAC-E-23-03, Order 35723, dated March 29, 2023, effective through September 30, 2028.
In January 2024, PacifiCorp issued $500 million of its 5.10% First Mortgage Bonds due February 2029, $700 million of its 5.30% First Mortgage Bonds due February 2031, $1.1 billion of its 5.45% First Mortgage Bonds due February 2034 and $1.5 billion of its 5.80% First Mortgage
Bonds due January 2055 for a total of $3.8 billion. PacifiCorp initially used a portion of the net proceeds to repay outstanding short-term debt and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.
State commission authorizations for the above issuances totaling $3.8 billion of long-term debt were as follows:
•OPUC – Docket No. UF-4337(1), Order No. 23-421, dated November 2, 2023.
•IPUC – Case No. PAC-E-23-03, Order 35723, dated March 29, 2023, effective through September 30, 2028.
In December 2023, PacifiCorp entered into a $900 million unsecured delayed draw term loan facility expiring in June 2025. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at PacifiCorp's option, plus a
pricing margin. Subject to regulatory authority to issue long-term debt, PacifiCorp may draw all or none of the unused commitment up to three times through June 2025. As of December 31, 2023, PacifiCorp had no term loans drawn from the facility.
PacifiCorp currently has an effective shelf registration statement filed with the SEC to issue an indeterminate amount of first mortgage bonds through September 2026. PacifiCorp must receive additional long-term debt issuance authority from the OPUC and IPUC and make a notice filing
with the WUTC prior to any future long-term debt issuance.
For further discussion, refer to Note 8 of Notes to Financial Statements in this Form No. 1.
ITEM 7.
None.
ITEM 8.
For the twelve-month period ended December 31, 2023, PacifiCorp's bargaining unit wage scale changes were as follows:
Unions Represented % Increase Effective Date(s)
Estimated Annual
Financial Impact
IBEW 57 Power Delivery (UT, ID & WY)6.79%01/26/2023 $6,416,001
IBEW 57 Power Supply (UT, ID & WY)4.62%01/26/2023 1,790,452
IBEW 57 Combustion Turbine (UT)5.02%01/26/2023 182,991
IBEW 77 (WA)1.83%01/26/2023 25,226
IBEW 125 (OR, WA)4.06%01/26/2023 1,333,052
IBEW 659 (OR, CA)2.74%04/26/2023 667,248
UWUA 197 (OR)4.52%05/26/2023 53,357
IBEW 57 Laramie (WY)6.52%06/26/2023 28,815
UWUA Local 127 (WY)1.18%09/26/2023 21,550
Total $10,518,692
(1) This percentage increase represents the increase in wages from the effective date of the increase to the end of the calendar year as compared to the wage scale of the prior calendar year.
(2) The estimated annual impact is based on the time period from the effective date of the increase to the end of the calendar year. Some amounts may be reimbursed by joint owners.
ITEM 9.
For information regarding certain legal proceedings affecting PacifiCorp, including matters related to wildfire loss contingencies, refer to Note 14 of Notes to Financial Statements in this Form No. 1.
ITEM 10.
Refer to page 429, Transactions with associated (affiliated) companies in this Form No. 1 for information regarding related-party transactions.
There have been no material officer, director or security holder transactions during the twelve-month period ended December 31, 2023, other than preferred and common stock dividends declared and paid.
In January 2023, PacifiCorp declared a common stock dividend of $300 million, paid in February 2023, to PPW Holdings LLC.
ITEM 12.
None.
ITEM 13.
On September 1, 2023, Cindy A. Crane replaced Scott W. Thon as PacifiCorp’s Chair of the Board of Directors and Chief Executive Officer.
ITEM 14.
Not applicable
FERC FORM No. 1 (ED. 12-96)
Page 108-109
(1)(2)
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
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)
1
2 200 34,043,912,436 33,039,040,567
3 200 4,719,845,635 2,476,435,222
4 38,763,758,071 35,515,475,789
5 200 13,094,069,120 12,334,383,396
6 25,669,688,951 23,181,092,393
7 202
8
9
10
11
12 202
13
14 25,669,688,951 23,181,092,393
15
16
17
18 21,155,095 21,206,842
19 3,283,929 3,254,224
20 69,928 69,928
21 224 156,585,163 136,476,068
23 228
24 111,023,868 100,689,729
25
26
27
28 174,123,261 131,896,187
29
30 2,200,107 14,530,841
31
32 461,873,493 401,615,371
33
34
35 13,593,270 21,115,014
36 85,529
37
38 113,626,658 566,381,766
39 1,391,069 1,383,552
40 579,437,294 533,992,933
41 445,112,582 75,334,312
42 30,393,528 18,532,513
43
44 (a)131,922,056 (b)83,670,876
45 227 103,923,863 133,979,566
46 227
47 227
48 227 428,441,000 340,361,073
UTILITY PLANT
Utility Plant (101-106, 114)
Construction Work in Progress (107)
TOTAL Utility Plant (Enter Total of lines 2 and 3)
(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)
Net Utility Plant (Enter Total of line 4 less 5)
Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)
Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
Nuclear Fuel Assemblies in Reactor (120.3)
Spent Nuclear Fuel (120.4)
Nuclear Fuel Under Capital Leases (120.6)
(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
Net Utility Plant (Enter Total of lines 6 and 13)
Utility Plant Adjustments (116)
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutility Property (121)
(Less) Accum. Prov. for Depr. and Amort. (122)
Investments in Associated Companies (123)
Investment in Subsidiary Companies (123.1)
Noncurrent Portion of Allowances
Other Investments (124)
Sinking Funds (125)
Depreciation Fund (126)
Amortization Fund - Federal (127)
Other Special Funds (128)
Special Funds (Non Major Only) (129)
Long-Term Portion of Derivative Assets (175)
Long-Term Portion of Derivative Assets - Hedges (176)
TOTAL Other Property and Investments (Lines 18-21 and 23-31)
CURRENT AND ACCRUED ASSETS
Cash and Working Funds (Non-major Only) (130)
Cash (131)
Special Deposits (132-134)
Working Fund (135)
Temporary Cash Investments (136)
Notes Receivable (141)
Customer Accounts Receivable (142)
Other Accounts Receivable (143)
(Less) Accum. Prov. for Uncollectible Acct.-Credit (144)
Notes Receivable from Associated Companies (145)
Accounts Receivable from Assoc. Companies (146)
Fuel Stock (151)
Fuel Stock Expenses Undistributed (152)
Residuals (Elec) and Extracted Products (153)
Plant Materials and Operating Supplies (154)
49 227
50 227
51 202/227
52 228 2,677,526 2,577,755
53 228
54 227
55
56
57 224,499,606 129,879,658
58
59 1,275,153
60 3,901,329 1,665,826
61 295,002,000 300,524,000
62
63 17,486,121 198,724,444
64 2,200,107 14,530,841
65
66
67 2,328,506,268 2,357,802,574
68
69 57,531,239 49,255,311
70 230a
71 230b
72 232 2,499,768,478 1,807,229,847
73 26,480,769 20,141,195
74
75
76 7,146
77 157,584
78 233 131,002,548 128,330,985
79
80 352
81 1,997,811 2,392,432
82 234 928,229,377 695,784,538
83
84 3,645,174,952 2,703,134,308
85 32,105,243,664 28,643,644,646
FERC FORM No. 1 (REV. 12-03)
Page 110-111
Merchandise (155)
Other Materials and Supplies (156)
Nuclear Materials Held for Sale (157)
Allowances (158.1 and 158.2)
(Less) Noncurrent Portion of Allowances
Stores Expense Undistributed (163)
Gas Stored Underground - Current (164.1)
Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
Prepayments (165)
Advances for Gas (166-167)
Interest and Dividends Receivable (171)
Rents Receivable (172)
Accrued Utility Revenues (173)
Miscellaneous Current and Accrued Assets (174)
Derivative Instrument Assets (175)
(Less) Long-Term Portion of Derivative Instrument Assets (175)
Derivative Instrument Assets - Hedges (176)
(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
Total Current and Accrued Assets (Lines 34 through 66)
DEFERRED DEBITS
Unamortized Debt Expenses (181)
Extraordinary Property Losses (182.1)
Unrecovered Plant and Regulatory Study Costs (182.2)
Other Regulatory Assets (182.3)
Prelim. Survey and Investigation Charges (Electric) (183)
Preliminary Natural Gas Survey and Investigation Charges 183.1)
Other Preliminary Survey and Investigation Charges (183.2)
Clearing Accounts (184)
Temporary Facilities (185)
Miscellaneous Deferred Debits (186)
Def. Losses from Disposition of Utility Plt. (187)
Research, Devel. and Demonstration Expend. (188)
Unamortized Loss on Reaquired Debt (189)
Accumulated Deferred Income Taxes (190)
Unrecovered Purchased Gas Costs (191)
Total Deferred Debits (lines 69 through 83)
TOTAL ASSETS (lines 14-16, 32, 67, and 84)
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: AccountsReceivableFromAssociatedCompanies
As of December 31, 2023, Account 146, Accounts receivable from associated companies, included $123,381,448 of income tax receivable from Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.
(b) Concept: AccountsReceivableFromAssociatedCompanies
As of December 31, 2022, Account 146, Accounts receivable from associated companies, included $79,950,662 of income tax receivable from Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.
FERC FORM No. 1 (REV. 12-03)
Page 110-111
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
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)
1
2 250 3,417,945,896 3,417,945,896
3 250 2,397,600 2,397,600
4
5
6
7 253 1,102,063,956 1,102,063,956
8 252
9 254
10 254b 41,101,061 41,101,061
11 118 5,401,125,738 6,188,985,268
12 118 100,240,452 80,131,357
13 250
14
15 122(a)(b)(10,369,236)(9,348,616)
16 9,972,303,345 10,741,074,400
17
18 256 10,493,150,000 9,742,150,000
19 256
20 256
21 256
22 227
23 25,686,565 26,507,475
24 10,467,463,435 9,715,642,752
25
26 20,578,928 18,311,335
27 894,600 7,696,932
28 1,572,643,695 168,270,561
29 59,657,269 59,591,258
30 27,276,601 32,419,032
31 971,425 1,720,000
32 19,997,035 1,875,535
33
34 355,525,424 331,315,147
35 2,057,544,977 621,199,800
36
37 1,605,961,000
38 1,390,952,592 981,087,553
39 (a)40,810,129 (b)3,375
40 139,299,855 148,494,505
41 28,663,856 50,669,328
42 262 40,928,851 44,786,760
43 153,832,529 129,544,631
44 40,475 40,475
45
46
47 22,991,961 22,624,875
PROPRIETARY CAPITAL
Common Stock Issued (201)
Preferred Stock Issued (204)
Capital Stock Subscribed (202, 205)
Stock Liability for Conversion (203, 206)
Premium on Capital Stock (207)
Other Paid-In Capital (208-211)
Installments Received on Capital Stock (212)
(Less) Discount on Capital Stock (213)
(Less) Capital Stock Expense (214)
Retained Earnings (215, 215.1, 216)
Unappropriated Undistributed Subsidiary Earnings (216.1)
(Less) Reacquired Capital Stock (217)
Noncorporate Proprietorship (Non-major only) (218)
Accumulated Other Comprehensive Income (219)
Total Proprietary Capital (lines 2 through 15)
LONG-TERM DEBT
Bonds (221)
(Less) Reacquired Bonds (222)
Advances from Associated Companies (223)
Other Long-Term Debt (224)
Unamortized Premium on Long-Term Debt (225)
(Less) Unamortized Discount on Long-Term Debt-Debit (226)
Total Long-Term Debt (lines 18 through 23)
OTHER NONCURRENT LIABILITIES
Obligations Under Capital Leases - Noncurrent (227)
Accumulated Provision for Property Insurance (228.1)
Accumulated Provision for Injuries and Damages (228.2)
Accumulated Provision for Pensions and Benefits (228.3)
Accumulated Miscellaneous Operating Provisions (228.4)
Accumulated Provision for Rate Refunds (229)
Long-Term Portion of Derivative Instrument Liabilities
Long-Term Portion of Derivative Instrument Liabilities - Hedges
Asset Retirement Obligations (230)
Total Other Noncurrent Liabilities (lines 26 through 34)
CURRENT AND ACCRUED LIABILITIES
Notes Payable (231)
Accounts Payable (232)
Notes Payable to Associated Companies (233)
Accounts Payable to Associated Companies (234)
Customer Deposits (235)
Taxes Accrued (236)
Interest Accrued (237)
Dividends Declared (238)
Matured Long-Term Debt (239)
Matured Interest (240)
Tax Collections Payable (241)
48 228,301,336 126,309,990
49 3,342,899 4,197,623
50 83,570,102 6,554,192
51 19,997,035 1,875,535
52
53
54 3,718,698,550 1,512,437,772
55
56 246,675,415 140,928,435
57 266 10,061,962 9,732,439
58
59 269 404,242,063 393,065,634
60 278 1,176,960,899 1,629,731,766
61
62 272 122,977,940 134,154,544
63 3,253,177,664 3,180,346,057
64 675,137,414 565,331,047
65 5,889,233,357 6,053,289,922
66 32,105,243,664 28,643,644,646
FERC FORM No. 1 (REV. 12-03)
Page 112-113
Miscellaneous Current and Accrued Liabilities (242)
Obligations Under Capital Leases-Current (243)
Derivative Instrument Liabilities (244)
(Less) Long-Term Portion of Derivative Instrument Liabilities
Derivative Instrument Liabilities - Hedges (245)
(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
Total Current and Accrued Liabilities (lines 37 through 53)
DEFERRED CREDITS
Customer Advances for Construction (252)
Accumulated Deferred Investment Tax Credits (255)
Deferred Gains from Disposition of Utility Plant (256)
Other Deferred Credits (253)
Other Regulatory Liabilities (254)
Unamortized Gain on Reacquired Debt (257)
Accum. Deferred Income Taxes-Accel. Amort.(281)
Accum. Deferred Income Taxes-Other Property (282)
Accum. Deferred Income Taxes-Other (283)
Total Deferred Credits (lines 56 through 64)
TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and
65)
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: NotesPayableToAssociatedCompanies
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, 2023, the interest rate on the outstanding loan balance was 5.650%.
(b) Concept: NotesPayableToAssociatedCompanies
Represents accrued interest 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, 2022, no advances were outstanding.
FERC FORM No. 1 (REV. 12-03)
Page 112-113
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
STATEMENT OF INCOME
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
Do not report fourth quarter data in columns (e) and (f)
Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility column in 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.
Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
Use page 122 for important notes regarding the statement of income for any account thereof.
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.
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 purchases, and a summary of the adjustments made to balance sheet, income, and expense accounts.
If any notes appearing in the report to stockholders are applicable to the Statement of Income, such notes may be included at page 122.
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.
Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Total Current Year
to Date Balance
for Quarter/Year
(c)
Total Prior Year to
Date Balance for
Quarter/Year
(d)
Current 3
Months Ended -
Quarterly Only -
No 4th Quarter
(e)
Prior 3 Months
Ended -
Quarterly Only -
No 4th Quarter
(f)
Electric
Utility
Current Year
to Date (in
dollars)
(g)
Electric
Utility
Previous
Year to Date
(in dollars)
(h)
Gas
Utiity
Current
Year to
Date
(in
dollars)
(i)
Gas
Utility
Previous
Year to
Date (in
dollars)
(j)
Other
Utility
Current
Year to
Date
(in
dollars)
(k)
Other
Utility
Previous
Year to
Date (in
dollars)
(l)
1
2 300 5,930,844,038 5,666,541,404 5,930,844,038 5,666,541,404
3
4 320 4,860,680,613 2,824,097,503 4,860,680,613 2,824,097,503
5 320 577,845,897 420,905,231 577,845,897 420,905,231
6 336 (a)1,023,482,570 1,016,353,629 1,023,482,570 1,016,353,629
7 336 (b)0 (e)0
8 336 62,649,787 64,937,656 62,649,787 64,937,656
9 336 376,987 1,132,844 376,987 1,132,844
10
11
12 13,251,404 11,367,893 13,251,404 11,367,893
13 9,547,753 9,547,753
14 262 (c)215,228,266 194,545,089 215,228,266 194,545,089
15 262 (351,752,881)(227,053,116)(351,752,881)(227,053,116)
16 262 (10,753,641)(2,662,119)(10,753,641)(2,662,119)
17 234, 272 1,291,887,433 985,200,400 1,291,887,433 985,200,400
18 234, 272 1,509,907,511 824,722,423 1,509,907,511 824,722,423
19 266 (764,880)(1,055,726)(764,880)(1,055,726)
20
21
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
UTILITY OPERATING
INCOME
Operating Revenues (400)
Operating Expenses
Operation Expenses (401)
Maintenance Expenses
(402)
Depreciation Expense (403)
Depreciation Expense for
Asset Retirement Costs
(403.1)
Amort. & Depl. of Utility
Plant (404-405)
Amort. of Utility Plant Acq.
Adj. (406)
Amort. Property Losses,
Unrecov Plant and
Regulatory Study Costs
(407)
Amort. of Conversion
Expenses (407.2)
Regulatory Debits (407.3)
(Less) Regulatory Credits
(407.4)
Taxes Other Than Income
Taxes (408.1)
Income Taxes - Federal
(409.1)
Income Taxes - Other
(409.1)
Provision for Deferred
Income Taxes (410.1)
(Less) Provision for
Deferred Income Taxes-Cr.
(411.1)
Investment Tax Credit Adj. -
Net (411.4)
(Less) Gains from Disp. of
Utility Plant (411.6)
Losses from Disp. of Utility
Plant (411.7)
22 91 100 91 100
23
24 (d)0
25 6,162,676,200 4,463,046,761 6,162,676,200 4,463,046,761
27 (231,832,162)1,203,494,643 (231,832,162)1,203,494,643
28
29
30
31 3,279,490 1,478,728
32 3,729,320 1,467,260
33
34 24,609 28,146
35 41,584 323,052
36 119 20,109,095 18,430,410
37 97,133,812 43,673,333
38 144,059,425 70,977,165
39 2,467,241 (3,107,598)
40 1,727,324 1,060,447
41 265,064,042 131,340,131
42
43 31
44 1,413,722 1,331,741
45 2,578,350 2,441,962
46 (9,212,248)1,221,220
47 24,951 (54,691)
48 2,655,807 1,353,122
49 4,995,431 3,532,867
50 2,456,013 9,826,252
51
52 262 317,207 331,830
53 262 17,772,582 6,925,565
54 262 4,025,002 1,568,448
55 234, 272 277,266,968 468,056,659
56 234, 272 276,592,758 467,729,785
57
(Less) Gains from
Disposition of Allowances
(411.8)
Losses from Disposition of
Allowances (411.9)
Accretion Expense (411.10)
TOTAL Utility Operating
Expenses (Enter Total of
lines 4 thru 24)
Net Util Oper Inc (Enter Tot
line 2 less 25)
Other Income and
Deductions
Other Income
Nonutilty Operating Income
Revenues From
Merchandising, Jobbing and
Contract Work (415)
(Less) Costs and Exp. of
Merchandising, Job. &
Contract Work (416)
Revenues From Nonutility
Operations (417)
(Less) Expenses of
Nonutility Operations
(417.1)
Nonoperating Rental
Income (418)
Equity in Earnings of
Subsidiary Companies
(418.1)
Interest and Dividend
Income (419)
Allowance for Other Funds
Used During Construction
(419.1)
Miscellaneous Nonoperating
Income (421)
Gain on Disposition of
Property (421.1)
TOTAL Other Income (Enter
Total of lines 31 thru 40)
Other Income Deductions
Loss on Disposition of
Property (421.2)
Miscellaneous Amortization
(425)
Donations (426.1)
Life Insurance (426.2)
Penalties (426.3)
Exp. for Certain Civic,
Political & Related Activities
(426.4)
Other Deductions (426.5)
TOTAL Other Income
Deductions (Total of lines 43
thru 49)
Taxes Applic. to Other
Income and Deductions
Taxes Other Than Income
Taxes (408.2)
Income Taxes-Federal
(409.2)
Income Taxes-Other (409.2)
Provision for Deferred Inc.
Taxes (410.2)
(Less) Provision for
Deferred Income Taxes-Cr.
(411.2)
Investment Tax Credit Adj.-
Net (411.5)
58 (75,321)2,501,395
59 22,864,322 6,651,322
60 239,743,707 114,862,557
61
62 486,803,423 404,320,904
63 4,869,406 4,457,195
64 394,621 443,653
65 227 2,718
66
67 1,146,989 136,625
68 52,519,654 20,255,501
69 70,233,788 31,361,791
70 475,500,078 398,249,369
71 (467,588,533)920,107,831
72
73
74
75
76 262
77
78 (467,588,533)920,107,831
FERC FORM No. 1 (REV. 02-04)
Page 114-117
(Less) Investment Tax
Credits (420)
TOTAL Taxes on Other
Income and Deductions
(Total of lines 52-58)
Net Other Income and
Deductions (Total of lines
41, 50, 59)
Interest Charges
Interest on Long-Term Debt
(427)
Amort. of Debt Disc. and
Expense (428)
Amortization of Loss on
Reaquired Debt (428.1)
(Less) Amort. of Premium
on Debt-Credit (429)
(Less) Amortization of Gain
on Reaquired Debt-Credit
(429.1)
Interest on Debt to Assoc.
Companies (430)
Other Interest Expense
(431)
(Less) Allowance for
Borrowed Funds Used
During Construction-Cr.
(432)
Net Interest Charges (Total
of lines 62 thru 69)
Income Before
Extraordinary Items (Total of
lines 27, 60 and 70)
Extraordinary Items
Extraordinary Income (434)
(Less) Extraordinary
Deductions (435)
Net Extraordinary Items
(Total of line 73 less line 74)
Income Taxes-Federal and
Other (409.3)
Extraordinary Items After
Taxes (line 75 less line 76)
Net Income (Total of line 71
and 77)
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: DepreciationExpense
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, 2023 and 2022, depreciation
expense associated with transportation equipment was $24,646,729 and $23,520,027, respectively.
(b) Concept: DepreciationExpenseForAssetRetirementCosts
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as a regulatory asset.
(c) Concept: TaxesOtherThanIncomeTaxesUtilityOperatingIncome
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress. During the years ended December 31, 2023 and 2022, payroll taxes were $47,008,878 and $42,754,894,
respectively.
(d) Concept: AccretionExpense
Generally, PacifiCorp records the accretion expense of asset retirement obligations as a regulatory asset.
(e) Concept: DepreciationExpenseForAssetRetirementCosts
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as a regulatory asset.
FERC FORM No. 1 (REV. 02-04)
Page 114-117
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly report.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, 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 for 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 for 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, attach them at page 122.
Line
No.
Item
(a)
Contra Primary Account
Affected
(b)
Current Quarter/Year Year to Date Balance
(c)
Previous Quarter/Year Year to Date
Balance
(d)
1 6,123,094,500 5,328,687,084
2
3
4
9
10
15
16 (487,697,628)901,677,421
17
17.1 215.1 (a)5,086,451
17.2 215.1 (3,595,171)(7,224,984)
22 1,491,280 (7,224,984)
23
23.1 238 (b)(161,902)(d)(161,902)
29 (161,902)(161,902)
30
30.1 238 (300,000,000)(100,000,000)
36 (300,000,000)(100,000,000)
37 216.1 116,881
38 5,336,726,250 6,123,094,500
39
45
46 (c)64,399,488 (e)65,890,768
47 64,399,488 65,890,768
48 5,401,125,738 6,188,985,268
49 80,131,357 61,817,828
50 20,109,095 18,430,410
51
52
52.1 (116,881)
53 100,240,452 80,131,357
FERC FORM No. 1 (REV. 02-04)
Page 118-119
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
Balance-Beginning of Period
Changes
Adjustments to Retained Earnings (Account 439)
Adjustments to Retained Earnings Credit
TOTAL Credits to Retained Earnings (Acct. 439)
Adjustments to Retained Earnings Debit
TOTAL Debits to Retained Earnings (Acct. 439)
Balance Transferred from Income (Account 433 less Account 418.1)
Appropriations of Retained Earnings (Acct. 436)
Unappropriation of excess earnings related to Lower Klamath Hydroelectric
Project
Appropriation of excess earnings at certain hydroelectric generating facilities
TOTAL Appropriations of Retained Earnings (Acct. 436)
Dividends Declared-Preferred Stock (Account 437)
Preferred Stock, various series and rates
TOTAL Dividends Declared-Preferred Stock (Acct. 437)
Dividends Declared-Common Stock (Account 438)
Common Stock
TOTAL Dividends Declared-Common Stock (Acct. 438)
Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
Balance - End of Period (Total 1,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account
215.1)
TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
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)
Balance-Beginning of Year (Debit or Credit)
Equity in Earnings for Year (Credit) (Account 418.1)
(Less) Dividends Received (Debit)
TOTAL other Changes in unappropriated undistributed subsidiary earnings for
the year
Transfers to/from Unappropriated Retained Earnings (Account 216)
Balance-End of Year (Total lines 49 thru 52)
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: AppropriationsOfRetainedEarnings
As approved by the FERC in Docket No. AC23-26-000.
(b) Concept: DividendsDeclaredPreferredStock
Outstanding shares of preferred stock as of December 31, 2023 and declared dividends on preferred stock during the twelve-month period ended December 31, 2023 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
(c) Concept: AppropriatedRetainedEarningsAmortizationReserveFederal
The balance in Account 215.1, Appropriated retained earnings - Amortization reserve, Federal, is due to requirements of certain hydroelectric relicensing projects.
(d) Concept: DividendsDeclaredPreferredStock
Outstanding shares of preferred stock as of December 31, 2022 and declared dividends on preferred stock during the twelve-month period ended December 31, 2022 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
(e) Concept: AppropriatedRetainedEarningsAmortizationReserveFederal
The balance in Account 215.1, Appropriated retained earnings - Amortization reserve, Federal, is due to requirements of certain hydroelectric relicensing projects.
FERC FORM No. 1 (REV. 02-04)
Page 118-119
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
STATEMENT OF CASH FLOWS
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.
Line
No.
Description (See Instructions No.1 for explanation of codes)
(a)
Current Year to Date Quarter/Year
(b)
Previous Year to Date Quarter/Year
(c)
1
2 (467,588,533)920,107,831
3
4 (a)1,049,255,663 1,041,278,061
5
5.1
5.2 64,063,509 66,269,397
5.3 376,987 1,132,844
5.4 12,498,487 11,243,603
8 (217,345,868)160,804,851
9 (689,559)(3,557,121)
10 (18,762,299)(143,775,110)
11 (58,024,224)(384,237)
12
13 1,393,799,901 292,340,442
14 (671,647,307)(425,809,415)
15 (18,560,906)(118,013,860)
16 144,059,425 70,977,165
17 20,109,095 18,313,529
18
18.1
18.2 (22,604,560)(27,463,823)
18.3 (100,200,000)95,100,000
18.4 (b)(90,579,395)
18.5 588,234
18.6 2,557,474 2,548,699
18.7 (2,398,526)(1,322,710)
18.8 17,354,296 2,306,885
18.9 (9,388,424)1,252,307
18.10 4,869,179 4,454,477
18.11 (2,421,774)3,385,848
18.12 16,284 (30,747)
22 701,000,119 1,792,577,528
24
25
26 (3,370,114,869)(2,236,811,129)
27
28
29
30 (144,059,425)(70,977,165)
31
34 (3,226,055,444)(2,165,833,964)
36
Net Cash Flow from Operating Activities
Net Income (Line 78(c) on page 117)
Noncash Charges (Credits) to Income:
Depreciation and Depletion
Amortization of (Specify) (footnote details)
Amortization:
Amortization of software and other intangibles
Amortization of electric plant acquisition adjustment
Amortization of regulatory assets
Deferred Income Taxes (Net)
Investment Tax Credit Adjustment (Net)
Net (Increase) Decrease in Receivables
Net (Increase) Decrease in Inventory
Net (Increase) Decrease in Allowances Inventory
Net Increase (Decrease) in Payables and Accrued Expenses
Net (Increase) Decrease in Other Regulatory Assets
Net Increase (Decrease) in Other Regulatory Liabilities
(Less) Allowance for Other Funds Used During Construction
(Less) Undistributed Earnings from Subsidiary Companies
Other (provide details in footnote):
Other Operating Activities:
Amounts Due To/From Affiliates, Net
Derivative Collateral (Net)
Prepayments
Other Assets
Depreciation and depletion included in cost of fuel
Net (gain) / loss on sale of property
Write-off of assets under construction
Change in corporate owned life insurance cash surrender value
Amortization of debt issuance expenses and bond discount/premium
Net (gain) / loss on long-term incentive plan and deferred compensation securities
Other
Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)
Cash Flows from Investment Activities:
Construction and Acquisition of Plant (including land):
Gross Additions to Utility Plant (less nuclear fuel)
Gross Additions to Nuclear Fuel
Gross Additions to Common Utility Plant
Gross Additions to Nonutility Plant
(Less) Allowance for Other Funds Used During Construction
Other (provide details in footnote):
Cash Outflows for Plant (Total of lines 26 thru 33)
Acquisition of Other Noncurrent Assets (d)
37 (c)2,425,257 (d)1,404,192
39
40
41
42
44
45
46
47
49
50
51
52
53
53.1
53.2 59,858 996,980
53.3 (1,769,814)2,353,006
53.4 5,297,714
57 (3,220,042,429)(2,161,079,786)
59
60
61 1,188,459,721 1,087,491,374
62
63
64
66 1,604,391,240
67
67.1 40,600,000
70 2,833,450,961 1,087,491,374
72
73 (449,000,000)(155,000,000)
74
75
76
76.1 (2,943,071)(574,649)
76.2 (1,126,364)(1,404,405)
76.3 (784,155)(539,251)
78
80 (161,902)(161,902)
81 (300,000,000)(100,000,000)
83 2,079,435,469 829,811,167
85
86 (439,606,841)461,308,909
88 620,581,280 159,272,371
90 180,974,439 620,581,280
FERC FORM No. 1 (ED. 12-96)
Page 120-121
Proceeds from Disposal of Noncurrent Assets (d)
Investments in and Advances to Assoc. and Subsidiary Companies
Contributions and Advances from Assoc. and Subsidiary Companies
Disposition of Investments in (and Advances to)
Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
Purchase of Investment Securities (a)
Proceeds from Sales of Investment Securities (a)
Loans Made or Purchased
Collections on Loans
Net (Increase) Decrease in Receivables
Net (Increase) Decrease in Inventory
Net (Increase) Decrease in Allowances Held for Speculation
Net Increase (Decrease) in Payables and Accrued Expenses
Other (provide details in footnote):
Other Investing Activities:
Other investments / special funds
Net proceeds from (purchases of) long-term incentive plan and deferred compensation
securities
Net proceeds from (purchases of) company owned life insurance policies
Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)
Cash Flows from Financing Activities:
Proceeds from Issuance of:
Long-Term Debt (b)
Preferred Stock
Common Stock
Other (provide details in footnote):
Net Increase in Short-Term Debt (c)
Other (provide details in footnote):
Net borrowings from subsidiary company, Pacific Minerals, Inc.
Cash Provided by Outside Sources (Total 61 thru 69)
Payments for Retirement of:
Long-term Debt (b)
Preferred Stock
Common Stock
Other (provide details in footnote):
Other deferred financing costs
Repayment of Finance Lease Obligations
Other
Net Decrease in Short-Term Debt (c)
Dividends on Preferred Stock
Dividends on Common Stock
Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)
Net Increase (Decrease) in Cash and Cash Equivalents
Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83)
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at End of Period
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: DepreciationAndDepletion
Includes depreciation expense associated with transportation equipment and finance lease assets of $25,773,093 and $24,924,432 during the years ended December 31, 2023 and 2022, respectively.
(b) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities
For the year ended December 31, 2022, the changes in Prepayments of $46 million were included in Net (Increase) Decrease in Receivables on the Statement of Cash Flows.
(c) Concept: ProceedsFromDisposalOfNoncurrentAssets
Represents proceeds from the disposal of fixed assets.
(d) Concept: ProceedsFromDisposalOfNoncurrentAssets
Represents proceeds from the disposal of fixed assets.
FERC FORM No. 1 (ED. 12-96)
Page 120-121
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
NOTES TO FINANCIAL STATEMENTS
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 Commission 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.
PACIFICORP
NOTES TO FINANCIAL STATEMENTS
(1) Organization and Operations
PacifiCorp is a United States ("U.S.") regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a
number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other
market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp 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.
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 the FERC and GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses
during the period. These estimates include, but are not limited to, the effects of regulation; certain assumptions made in accounting for pension and other postretirement benefits; AROs; income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative
contracts; and accounting for loss contingencies and applicable insurance recoveries, including those related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") and a wildfire that began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou
County, California in July 2022 (the "2022 McKinney Fire"), referred to together as "the Wildfires" as discussed 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.
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 when 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.
Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. 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 consist substantially of funds representing vendor retention, nuclear decommissioning and custodial funds. A reconciliation of cash and cash equivalents and restricted cash equivalents as of
December 31, 2023 and 2022 as presented on the Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Comparative Balance Sheets (in millions):
2023 2022
Cash (131)$14 $21
Other special funds (128)53 34
Temporary cash investments (136)114 566
Total cash and cash equivalents and restricted cash and cash equivalents 181 621
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, 2023 and 2022, 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 the allowance for credit losses for 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):
2023 2022
Beginning balance $19 $18
Charged to operating costs and expenses, net 34 18
Write-offs, net (23)(17)
Ending balance $30 $19
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.
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
liabilities or assets. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.
Inventories
Inventories consist mainly of materials, supplies and fuel stocks and 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.
Generall hen PacifiCorp retires or sells a component of reg lated tilit plant it charges the original cost net of an proceeds from the disposition to acc m lated pro ision for depreciation An gain or loss on disposals of all other assets is recorded thro gh earnings
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.
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 when 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 line 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 ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet
commenced. These 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 uses a single five-step model to identify and recognize 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.
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.
The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since the date of the last meter reading is estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of
unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Unbilled revenue is reversed in the following month and billed revenue is recorded based on the
subsequent meter readings.
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 U.S. 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 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 deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions.
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.
Segment Information
PacifiCorp currently has one segment, which includes its regulated electric utility operations.
New Accounting Pronouncements
In November 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures
of segment profit or loss used by the chief operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items as well as incremental qualitative disclosures on both an
annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. PacifiCorp is currently
evaluating the impact of adopting this guidance on its financial statements and disclosures included within Notes to Financial Statements.
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation,
disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15,
2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. PacifiCorp is currently evaluating the impact of adopting this guidance on its financial statements and disclosures included within Notes to Financial Statements.
Subsequent Events
PacifiCorp has evaluated the impact on its financial statements of events occurring after December 31, 2023 up to February 23, 2024, the date that PacifiCorp's GAAP financial statements were filed with the U.S. Securities and Exchange Commission and has updated such evaluation for
disclosure purposes through April 11, 2024. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.
(3) Net Utility Plant
The average depreciation and amortization rate applied to depreciable utility plant was 3.4% and 3.5% for the years ended December 31, 2023 and 2022, respectively, including the impacts of $29 million and $29 million in 2023 and 2022, respectively, related to Idaho's, Utah’s, Wyoming’s
and Washington’s shares of incremental decommissioning costs for certain coal-fueled units.
(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, 2023 (dollars in millions):
PacifiCorp Share Facility in Service
Accumulated Depreciation and
Amortization Construction Work-in-Progress
Jim Bridger Nos. 1 - 4 67%$1,602 $1,032 $26
Hunter No. 1 94 510 238 4
Hunter No. 2 60 316 151 2
Wyodak 80 491 286 —
Colstrip Nos. 3 and 4 10 262 208 —
Hermiston 50 191 114 3
Craig Nos. 1 and 2 19 372 206 —
Hayden No. 1 25 77 55 —
Hayden No. 2 13 45 33 —
Transmission and distribution facilities Various 900 338 192
Total $4,766 $2,661 $227
(5) Leases
The following table summarizes PacifiCorp's leases recorded on the Comparative Balance Sheet as of December 31 (in millions):
2023 2022
Right-of-use assets:
Operating leases $12 $11
Finance leases 12 12
Total right-of-use assets $24 $23
Lease liabilities:
Operating leases $12 $11
Finance leases 12 11
Total lease liabilities $24 $22
The following table summarizes PacifiCorp's lease costs for the years ended December 31 (in millions):
2023 2022
Variable $57 $61
Operating 4 3
Finance:
Amortization 1 1
Interest 1 1
Short-term 6 5
Total lease costs $69 $71
Weighted-average remaining lease term (years):
Operating leases 12.3 11.4
Finance leases 8.8 9.7
Weighted-average discount rate:
Operating leases 3.8 %3.9 %
Finance leases 10.6 %11.4 %
Cash payments associated with operating and finance lease liabilities approximated lease cost for the years ended December 31, 2023 and 2022.
PacifiCorp has the following remaining lease commitments as of December 31, 2023 (in millions):
Operating Finance Total
2024 $3 $2 $5
2025 2 2 4
2026 2 2 4
2027 1 2 3
2028 1 2 3
Thereafter 7 8 15
Total undiscounted lease payments 16 18 34
Less - amounts representing interest (4)(6)(10)
Lease liabilities $12 $12 $24
(6) Regulatory Matters
Regulatory Assets
PacifiCorp had regulatory assets not earning a return on investment of $1,850 million and $1,197 million as of December 31, 2023 and 2022, respectively.
(7) Short-term Debt and Credit Facilities
PacifiCorp has a $2.0 billion unsecured credit facility expiring in June 2026 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which supports PacifiCorp's commercial paper program and certain series of its tax-exempt bond obligations
and provides for the issuance of letters of credit, has a variable interest rate based on the Secured Overnight Financing 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.
The following table summarizes PacifiCorp's availability under its unsecured credit facility as of December 31 (in millions):
2023:
Credit facility $2,000
Less:
Short-term debt (1,604)
Tax-exempt bond support and letters of credit (249)
Net credit facility $147
2022:
Credit facility $1,200
Less:
Tax-exempt bond support and letters of credit (249)
Net credit facility $951
As of December 31, 2023, PacifiCorp was in compliance with all financial covenants that affect access to capital.
As of December 31, 2023, PacifiCorp had $1.6 billion of short-term debt outstanding at a weighted average rate of 6.16%, which was subsequently repaid in January 2024. As of December 31, 2022, PacifiCorp had no short-term debt outstanding.
The credit facility and the delayed draw term loan facility described in Note 8 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, 2023, PacifiCorp's debt to total
capitalization ratio was 0.55 to 1.0. Refer to Note 8 for discussion of PacifiCorp's January 2024 issuance of First Mortgage Bonds.
As of December 31, 2023, PacifiCorp had $255 million of letter of credit capacity under its $2.0 billion revolving credit facility of which $31 million was outstanding and was utilized as a standby letter of credit, and $168 million of letter of credit capacity outside of its $2.0 billion
revolving credit facility, of which $55 million was outstanding and was utilized in support of certain transactions required by third parties.
As of December 31, 2022, PacifiCorp had $219 million of letter of credit capacity under the $1.2 billion revolving credit facility that was in place at that time, of which $31 million was outstanding and was utilized as a standby letter of credit, and $7 million of letters of credit outstanding
under committed arrangements outside of the facility in support of certain transactions required by third parties.
(8) Long-term Debt
In May 2023, PacifiCorp issued $1.2 billion of its 5.50% First Mortgage Bonds due May 2054. PacifiCorp intends within 24 months of the issuance date, to allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing investments or expenditures
made in one or more eligible projects in alignment with BHE's Green Financing Framework.
In December 2023, PacifiCorp entered into a $900 million unsecured delayed draw term loan facility expiring in June 2025. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at PacifiCorp's option, plus a
pricing margin. Subject to regulatory authority to issue long-term debt, PacifiCorp may draw all or none of the unused commitment up to three times through June 2025. As of December 31, 2023, PacifiCorp had no term loans drawn from the facility As described in Note 7, the delayed
draw term loan facility requires certain ratios to be maintained.
In January 2024, PacifiCorp issued $500 million of its 5.10% First Mortgage Bonds due February 2029, $700 million of its 5.30% First Mortgage Bonds due February 2031, $1.1 billion of its 5.45% First Mortgage Bonds due February 2034 and $1.5 billion of its 5.80% First Mortgage
Bonds due January 2055 for a total of $3.8 billion. PacifiCorp initially used a portion of the net proceeds to repay outstanding short-term debt and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.
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.
Following PacifiCorp's January 2024 First Mortgage Bond issuances, PacifiCorp currently has no remaining regulatory authority from the Oregon Public Utility Commission ("OPUC") and the Idaho Public Utilities Commission ("IPUC") to issue additional long-term debt. PacifiCorp must
receive additional long-term debt issuance authority from the OPUC and IPUC and make a notice filing with the Washington Utilities and Transportation Commission prior to any future long-term debt issuance. PacifiCorp currently has an effective shelf registration statement filed with the
U.S. Securities and Exchange Commission to issue an indeterminate amount of first mortgage bonds through September 2026.
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's mortgage. Approximately $36 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage as of December 31,
2023.
As of December 31, 2023, the annual principal maturities of long-term debt for 2024 and thereafter are as follows (in millions):
Long-term
Debt
2024 $591
2025 302
2026 100
2027 —
2028 —
Thereafter 9,500
Total $10,493
Unamortized discount (26)
Total $10,467
(9) Income Taxes
The effective tax rate for the year ended December 31, 2023, is 54% and results from a $559 million income tax benefit associated with a $1,026 million pre-tax loss primarily related to a $1,677 million increase in wildfire loss accruals, net of expected insurance recoveries as described in
Note 14. The $559 million income tax benefit is primarily comprised of a $216 million benefit, or 21%, from the application of the federal statutory income tax rate to the pre-tax loss, a $180 million benefit, or 18%, from federal income tax credits, a $111 million benefit, or 11%, from
effects of ratemaking and a $43 million benefit, or 4%, from state income tax.
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
2023 2022
Current:
Federal $(334)$(220)
State (7)(1)
Total $(341)$(221)
Deferred:
Federal (167)90
State (50)71
Total $(217)$161
Investment tax credits (1)(4)
Total income tax expense (benefit)$(559)$(64)
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income (loss) before income tax expense (benefit) is as follows for the years ended December 31:
2023 2022
Federal statutory income tax rate 21 %21 %
State income taxes, net of federal income tax benefit 4 3
Effects of ratemaking 11 (12)
Federal income tax credits 18 (22)
Valuation allowance 1 2
Other (1)1
Effective income tax rate 54 %(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. PTCs for the years ended December 31, 2023 and 2022 totaled $180 million and$185 million, respectively.
The net deferred income tax liability consists of the following as of December 31 (in millions):
2023 2022
Deferred income tax assets:
Regulatory liabilities $312 $421
Employee benefits 51 59
State carryforwards 84 73
Loss contingencies 338 45
AROs 85 79
Other 82 54
Total deferred income tax assets $952 $731
Valuation allowances $(24)$(35)
Total deferred income tax assets, net $928 $696
Deferred income tax liabilities:
Property-related items (3,376)(3,315)
Regulatory assets (631)(461)
Other (44)(104)
Total deferred income tax liabilities (4,051)(3,880)
Net deferred income tax liability $(3,123)$(3,184)
The following table provides, without regard to valuation allowances, PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December 31, 2023 (in millions):
State
Net operating loss carryforwards $1,427
Deferred income taxes on net operating loss carryforwards $64
Expiration dates 2026 - indefinite
Tax credit carryforwards $20
Expiration dates 2024 - indefinite
The U.S. 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 income tax returns have expired for certain states through December 31, 2011, and for Idaho
through December 31, 2019, except for the impact of any federal audit adjustments. The closure of examinations, or the expiration of the statute of limitations, 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 of its employees, as well as a defined contribution 401(k) employee savings plan ("401(k) Plan"). In addition, PacifiCorp contributes to a joint trustee pension plan and a subsidiary
previously contributed to a multiemployer pension plan for benefits offered to certain bargaining units.
Defined Benefit Plans
PacifiCorp's pension plans include non-contributory defined benefit pension plans, the PacifiCorp Retirement Plan ("Retirement Plan"), and the Supplemental Executive Retirement Plan ("SERP"). The Retirement Plan is closed to all non-union employees hired after January 1, 2008. All
non-union Retirement Plan participants hired prior to January 1, 2008 that did not elect to receive equivalent fixed contributions to the 401(k) Plan effective January 1, 2009 earned benefits based on a cash balance formula through December 31, 2016. Effective January 1, 2017, non-union
employee participants with a cash balance benefit in the Retirement Plan are no longer eligible to receive pay credits in their cash balance formula. In general for union employees, benefits under the Retirement Plan were frozen at various dates from December 31, 2007 through December
31, 2011 as they are now being provided with enhanced 401(k) Plan benefits. However, certain limited union Retirement Plan participants continue to earn benefits under the Retirement Plan based on the employee's years of service and a final average pay formula. The SERP was closed to
new participants as of March 21, 2006 and froze future accruals for active participants as of December 31, 2014.
PacifiCorp's other postretirement benefit plan provides healthcare and life insurance benefits to eligible retirees.
Pension Settlement
Pension settlement accounting was triggered in 2022 as a result of the amount of lump sum distributions in the Retirement Plan exceeding the service and interest cost threshold. As a result of the settlement accounting, PacifiCorp recognized a settlement loss of $6 million, net of regulatory
deferrals during the year ended December 31, 2022.
Net Periodic Benefit Cost
For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the first year in which they
occur.
Net periodic benefit cost (credit) for the plans included the following components for the years ended December 31 (in millions):
Pension Other Postretirement
2023 2022 2023 2022
Service cost $— $— $1 $2
Interest cost 39 29 11 8
Expected return on plan assets (49)(42)(13)(11)
Settlement — 6 — —
Net amortization 12 16 (2)1
Net periodic benefit cost (credit)$2 $9 $(3)$—
Pension amounts represent settlement losses of $- million and $24 million net of deferrals of $- million and $18 million during the years ended December 31, 2023 and 2022.
Funded Status
Th f ll i bl i ili i f h f i l f l f h d d D b 31 (i illi )
(1)
(1) Effects of ratemaking is primarily attributable to activity associated with excess deferred income taxes.
(1)
(1)
The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
Pension Other Postretirement
2023 2022 2023 2022
Plan assets at fair value, beginning of year $758 $1,058 $264 $324
Employer contributions 4 4 — —
Participant contributions — — 4 5
Actual (loss) return on plan assets 73 (172)25 (42)
Settlement — (67)— —
Benefits paid (71)(65)(22)(23)
Plan assets at fair value, end of year $764 $758 $271 $264
(1)Pension amounts represent employer contributions to the SERP.
(2)Benefits paid in the form of lump sum distributions that gave rise to the settlement accounting described above.
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
Pension Other Postretirement
2023 2022 2023 2022
Benefit obligation, beginning of year $746 $1,048 $219 $288
Service cost — — 1 2
Interest cost 39 29 11 8
Participant contributions — — 4 5
Actuarial gain (loss)26 (199)2 (61)
Settlement — (67)— —
Benefits paid (71)(65)(22)(23)
Benefit obligation, end of year $740 $746 $215 $219
Accumulated benefit obligation, end of year $740 $746
(1)Benefits paid in the form of lump sum distributions that gave rise to the settlement accounting described above.
The funded status of the plans and the amounts recognized on the Comparative Balance Sheet as of December 31 are as follows (in millions):
Pension Other Postretirement
2023 2022 2023 2022
Plan assets at fair value, end of year $764 $758 $271 $264
Less - Benefit obligation, end of year 740 746 215 219
Funded status $24 $12 $56 $45
Amounts recognized on the Comparative Balance Sheet:
Other special funds (128)$65 $53 $56 $45
Miscellaneous current and accrued liabilities (242)(4)(4)— —
Accumulated provision for pension and benefits (228.3)(37)(37)— —
Amounts recognized $24 $12 $56 $45
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 $68 million and $61 million as of December 31, 2023 and 2022, 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, 2023 and 2022, respectively, on the Comparative Balance Sheet. The projected and accumulated benefit obligations for the SERP were $41 million and $42 million at December 31, 2023 and 2022, respectively.
As of December 31, 2023, the fair value of the plan assets for the Retirement Plan was in excess of both the projected benefit obligation and the accumulated benefit obligation.
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
2023 2022 2023 2022
Net loss (gain)$270 $273 $(42)$(36)
Regulatory deferrals 22 29 — 1
Total $292 $302 $(42)$(35)
(1)Pension amounts represent the unamortized portion of deferred settlement losses.
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2023 and 2022 is as follows (in millions):
Regulatory Asset
Accumulated Other Comprehensive
Loss Total
Pension
Balance, December 31, 2021 $286 $23 $309
Net loss (gain) arising during the year 24 (9)15
Net amortization (14)(2)(16)
Settlement (6)— (6)
Total 4 (11)(7)
Balance, December 31, 2022 290 12 302
Net loss arising during the year — 2 2
Net amortization (11)(1)(12)
Total (11)1 (10)
Balance, December 31, 2023 $279 $13 $292
Regulatory
Liability
Other Postretirement
Balance, December 31, 2021 $(26)
Net gain arising during the year (8)
Net amortization (1)
Total (9)
Balance, December 31, 2022 (35)
Net gain arising during the year (9)
Net amortization 2
Total (7)
Balance, December 31, 2023 $(42)
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
Pension Other Postretirement
2023 2022 2023 2022
Benefit obligations as of December 31:
Discount rate 5.20 %5.55 %5.20 %5.50 %
Interest crediting rates for cash balance plan - non-union
2021 N/A N/A N/A N/A
2022 N/A 0.88 %N/A N/A
2023 4.73 %4.73 %N/A N/A
2024 5.98 %4.73 %N/A N/A
(1)
(2)
(1)
(1)
2025 5.98 %2.60 %N/A N/A
2026 and beyond 3.10 %2.60 %N/A N/A
Interest crediting rates for cash balance plan - union
2021 N/A N/A N/A N/A
2022 N/A 1.94 %N/A N/A
2023 3.55 %3.55 %N/A N/A
2024 4.47 %3.55 %N/A N/A
2025 4.47 %2.40 %N/A N/A
2026 and beyond 2.70 %2.40 %N/A N/A
Net periodic benefit cost for the years ended December 31:
Discount rate 5.55 %2.90 %5.50 %2.90 %
Expected return on plan assets 6.00 4.70 4.78 3.44
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 $— million, respectively, during 2024. 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 of 2006"). PacifiCorp considers contributing additional amounts from time to time in order to achieve certain funding levels specified
under the PPA of 2006. 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 2024 through 2028 and for the five years thereafter are summarized below (in millions):
Projected Benefit Payments
Pension Other Postretirement
2024 $76 $22
2025 72 22
2026 70 21
2027 66 20
2028 63 19
2029-2033 273 81
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 consultants to advise on 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, 2023:
Pension Other Postretirement
%%
Debt securities 73 79
Equity securities 22 21
Other 5 —
(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.
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 Level 2 Level 3 Total
As of December 31, 2023:
Cash equivalents $— $28 $— $28
Debt securities:
U.S. government obligations 52 — — 52
Corporate obligations — 232 — 232
Municipal obligations — 16 — 16
Agency, asset and mortgage-backed obligations — 47 — 47
Equity securities:
U.S. companies 53 — — 53
Total assets in the fair value hierarchy $105 $323 $— 428
Investment funds measured at net asset value 310
Limited partnership interests measured at net asset value 26
Investments at fair value $764
As of December 31, 2022:
Cash equivalents $— $10 $— $10
Debt securities:
U.S. government obligations 41 — — 41
Corporate obligations — 211 — 211
Municipal obligations — 15 — 15
Agency, asset and mortgage-backed obligations — 34 — 34
Equity securities:
U.S. companies 69 — — 69
Total assets in the fair value hierarchy $110 $270 $— 380
Investment funds measured at net asset value 346
Limited partnership interests measured at net asset value 32
Investments at fair value $758
(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 41% and 59%, respectively for 2023 and 50% and 50%, respectively, for 2022, and are invested in U.S. and international securities of approximately 88% and 12%, respectively, for 2023 and 90%
and 10%, respectively, for 2022.
(3)Limited partnership interests include several funds that invest primarily in real estate.
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 Level 2 Level 3 Total
As of December 31, 2023:
Cash equivalents $4 $3 $— $7
Debt securities:
U.S. government obligations 9 — — 9
Corporate obligations — 45 — 45
Municipal obligations — 19 — 19
Agency, asset and mortgage-backed obligations — 50 — 50
Equity securities:
U.S. companies 8 — — 8
T t l t i th f i l hi h $21 $117 $138
(1)(1)
(2)
(2)
(1)(1)(1)
(2)
(3)
(2)
(3)
(1)(1)(1)
Total assets in the fair value hierarchy $21 $117 $— 138
Investment funds measured at net asset value 133
Investments at fair value $271
As of December 31, 2022:
Cash equivalents $5 $5 $— $10
Debt securities:
U.S. government obligations 6 — — 6
Corporate obligations — 49 — 49
Municipal obligations — 13 — 13
Agency, asset and mortgage-backed obligations — 47 — 47
Equity securities:
U.S. companies 7 — — 7
Total assets in the fair value hierarchy $18 $114 $— 132
Investment funds measured at net asset value 132
Investments at fair value $264
(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 2023 and 41% and 59%, respectively, for 2022, and are invested in U.S. and international securities of approximately 89% and 11%, respectively, for 2023 and 91%
and 9%, respectively, for 2022.
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. In January 2024, the withdrawal liability was recalculated by the plan's actuary to be $80 million as a result of arbitration efforts regarding the interest rate used to compute the 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 efforts with the plan trustees and the recent arbitration activities.
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. 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 of 2006 zone status or plan funded status percentage for plan years
beginning July 1,Contributions
Plan name
Employer
Identification
Number 2023 2022 Funding improvement plan Surcharge imposed under PPA of 2006 2023 2022
Year contributions to plan exceeded more than 5% of total
contributions
Local 57 Trust Fund 87-0640888 At least 80%At least 80%None None $5 $6 2023, 2022
PacifiCorp's minimum contributions to the Local 57 Trust Fund 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. The collective bargaining agreements governing
the Local 57 Trust Fund that were due to expire in 2023 were extended to 2028 in December 2022.
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, 2023, 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 $48 million and $44 million for the years ended December 31, 2023 and 2022, 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 $1,456 million and $1,332 million as of December 31,
2023 and 2022, respectively.
The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 31 (in millions):
2023 2022
Beginning balance $331 $304
Change in estimated costs (4)20
Additions 27 3
Retirements (9)(6)
Accretion 11 10
Ending balance $356 $331
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.
PacifiCorp has established a risk management process that is designed to identify, assess, manage and report on 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, futures, 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 has the ability to 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
Assets
Long-term
Assets
Current
Liabilities
Long-term
Liabilities Total
As of December 31, 2023
Not designated as hedging contracts :
Commodity assets $21 $2 $7 $2 $32
Commodity liabilities (3)— (83)(22)(108)
Total 18 2 (76)(20)(76)
Total derivatives 18 2 (76)(20)(76)
Cash collateral receivable (2)— 12 — 10
Total derivatives - net basis $16 $2 $(64)$(20)$(66)
As of December 31, 2022
Not designated as hedging contracts :
Commodity assets $279 $27 $9 $3 $318
Commodity liabilities (22)(7)(14)(5)(48)
Total 257 20 (5)(2)270
Total derivatives 257 20 (5)(2)270
Cash collateral payable (73)(5)— — (78)
(2)
(2)
(1)
(1)
(2)
p y ()()()
Total derivatives - net basis $184 $15 $(5)$(2)$192
(1)PacifiCorp's commodity derivatives are generally included in rates. As of December 31, 2023 a regulatory asset of $76 million was recorded related to the net derivative liability of $76 million. As of December 31, 2022 a regulatory liability of $270 million was recorded related to the net derivative asset of $270 million.
(2)As of December 31, 2022, PacifiCorp had an additional $12 million cash collateral payable that was not required to be netted against total derivatives.
The following table reconciles the beginning and ending balances of PacifiCorp's net regulatory (liabilities) assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory (liabilities) assets, as well as amounts reclassified to earnings for
the years ended December 31 (in millions):
2023 2022
Beginning balance $(270)$(53)
Changes in fair value recognized in regulatory (liabilities) assets 206 (513)
Net (losses) reclassified to operating revenue (8)(13)
Net gains reclassified to energy costs 148 309
Ending balance $76 $(270)
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 2023 2022
Electricity purchases, net Megawatt hours 2 2
Natural gas purchases Decatherms 153 127
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 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"). These agreements and other agreements that do not refer to specified
rating-dependent thresholds may 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, 2023, PacifiCorp's issuer 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 $108 million and $48 million as of December 31, 2023 and 2022, respectively, for which PacifiCorp had posted collateral of $12 million and $-
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, 2023 and 2022, PacifiCorp would have been required to post $84 million and $3 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.
(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 financial 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 Total
As of December 31, 2023
Assets:
Commodity derivatives $— $32 $— $(14)$18
Money market mutual funds 165 — — — 165
Investment funds 26 — — — 26
$191 $32 $— $(14)$209
Liabilities - Commodity derivatives $— $(108)$— $24 $(84)
As of December 31, 2022
Assets:
Commodity derivatives $— $318 $— $(119)$199
Money market mutual funds 597 — — — 597
Investment funds 22 — — — 22
$619 $318 $— $(119)$818
Liabilities - Commodity derivatives $— $(48)$— $41 $(7)
Represents netting under master netting arrangements and a net cash collateral receivable of $10 million and a net cash collateral payable of $78 million as of December 31, 2023 and 2022, respectively. As of December 31, 2022, PacifiCorp had an additional $12 million cash collateral payable that was not required to be netted against total
derivatives.
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. A discounted cash flow valuation method
was used to estimate fair value. 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):
2023 2022
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
Long-term debt $10,467 $9,722 $9,715 $9,045
(14) Commitments and Contingencies
Commitments
PacifiCorp has the following firm commitments that are not reflected on the Comparative Balance Sheet. Minimum payments as of December 31, 2023 are as follows (in millions):
2024 2025 2026 2027 2028 2029 and Thereafter Total
Contract type:
Purchased electricity contracts -
commercially operable $482 $198 $196 $195 $198 $1,964 $3,233
Purchased electricity contracts -
non-commercially operable — 34 58 58 58 946 1,154
Fuel contracts 673 425 160 169 156 323 1,906
Construction commitments 891 183 5 2 1 — 1,082
Transmission 105 100 92 80 75 394 846
Easements 13 13 13 13 14 797 863
Maintenance, service and
other contracts 143 117 128 63 54 240 745
Total commitments $2,307 $1,070 $652 $580 $556 $4,664 $9,829
Purchased Electricity Contracts - Commercially Operable
(1)
(1)
The table above reflects purchased electricity contracts with expiration dates ranging from 2024 through 2052. As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-term purchases and exchange agreements. PacifiCorp has many long-term
PPAs primarily with solar-powered or wind-powered generating facilities that are not included in the table above due to there being no minimum payments generally due to being dependent on wind and solar conditions. The PPAs generally range from 10 to 30 years in duration, with certain
of the PPAs extending through 2046. Future payments associated with these PPAs are expected to be material. Certain of these PPAs 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 2023 and 2022 energy sources.
Purchased Electricity Contracts - Non-Commercially Operable
PacifiCorp has many long-term PPAs with facilities that have not yet achieved commercial operation, primarily related to wind-powered and solar-powered generated facilities and including with facilities that are not included in the table above due to there being no minimum payments
generally due to being dependent on wind and solar conditions. The PPAs generally range from 10 to 30 years in duration with certain of the PPAs extending through 2054. Future payments associated with these arrangements are expected to be material. The table above reflects capacity
payments through 2046 for a 400 MW battery storage agreement associated with a purchased electricity contract for a 400 MW solar generating facility. To the extent these facilities do not achieve commercial operation, PacifiCorp has no obligation to the counterparties.
Fuel Contracts
PacifiCorp has "take or pay" coal and natural gas contracts that require minimum payments. In January and February 2024, PacifiCorp entered into new and amended coal supply agreements aggregating approximately $1.9 billion of additional commitments through 2030.
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 easements for land on which certain of its assets, primarily wind-powered generating facilities, are located.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal, wildfire prevention and mitigation and other environmental matters that have the potential to impact its current and
future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.
Lower Klamath Hydroelectric Project
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 hydroelectric dams comprising the Lower Klamath Project (FERC Project No. 14803) from PacifiCorp to the KRRC. The FERC approved the 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 to remove PacifiCorp from the license for the Lower Klamath Project and add the States and KRRC as co-licensees for the purposes of surrender. 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. In June 2021, the FERC approved the transfer of the Lower Klamath Project dams from PacifiCorp to the KRRC and the States as co-licensees. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions conditionally
approved the required property transfer applications. In August 2021, PacifiCorp notified the Public Service Commission of Utah of the property transfer, however no formal approval is required in Utah. In August 2022, the FERC staff issued a final environmental impact statement for the
project, concluding that dam removal is the preferred action. In November 2022, the FERC issued a license surrender order for the project, which was accepted by the KRRC and the States in December 2022, along with the transfer of the Lower Klamath Project dams. Although PacifiCorp
no longer owns the Lower Klamath Project, PacifiCorp will continue to operate the facilities under an operation and maintenance agreement with the KRRC until each facility is ready for removal. Removal of the Copco No. 2 facility was completed in November 2023, and removal of the
remaining three dams (J.C. Boyle, Copco No. 1, and Iron Gate) is anticipated to be completed in 2024.
Hydroelectric Commitments
Certain of PacifiCorp's hydroelectric licenses and settlement agreements contain requirements for PacifiCorp to make certain capital and operating expenditures related to its hydroelectric facilities, which are estimated to be approximately $314 million over the next 10 years.
Legal Matters
PacifiCorp is party to a variety of legal actions, including litigation, arising out of the normal course of business, some of which assert claims for damages in substantial amounts and are described below. For certain legal actions, parties at times may seek to impose fines, penalties and other
costs.
Pursuant to GAAP, a provision for a loss contingency is recorded when it is probable a liability is likely to occur and the amount of loss can be reasonably estimated. PacifiCorp evaluates the related range of reasonably estimated losses and records a loss based on its best estimate within
that range or the lower end of the range if there is no better estimate.
Wildfires
In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages from wildfires 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 be found liable for all damages.
2020 Wildfires
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, which resulted in real and personal property and natural resource 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 destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities.
Investigations into the cause and origin of each wildfire are complex and ongoing and have been or are being conducted by various entities, including the U.S. Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice,
PacifiCorp and various experts engaged by PacifiCorp.
As of the date of this filing, a significant number of complaints and demands alleging similar claims related to the 2020 Wildfires have been filed in Oregon and California, including a class action complaint in Oregon for which two jury verdicts were issued in June 2023 and January 2024
as described below. The plaintiffs seek damages for economic losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees. Several insurance carriers have filed subrogation complaints in
Oregon and California with allegations similar to those made in the aforementioned complaints. Additionally, the U.S. and Oregon Departments of Justice have informed PacifiCorp that they are contemplating filing actions against PacifiCorp in connection with certain of the Oregon 2020
Wildfires. PacifiCorp is actively cooperating with the U.S. and Oregon Departments of Justice on resolving these alleged claims, including through the pursuit of alternative dispute resolution.
Amounts sought in the complaints and demands filed in Oregon and in certain demands made in California total approximately $8 billion, excluding any doubling or trebling of damages included in the complaints. Generally, the complaints filed in California do not specify damages sought
and are excluded from this amount. For class actions, amounts specified by the plaintiffs in the complaints include amounts based on estimates of the potential class size, which ultimately may be significantly greater than estimated. Additionally, damages are not limited to the amounts
specified in the initially filed complaints as plaintiffs are frequently allowed to amend their complaints to add additional damages and amounts awarded in a court proceeding may be significantly greater than the damages specified. Oregon law provides for doubling of economic and
property damages in the event the defendant is found to have acted with gross negligence, recklessness, willfulness or malice. Oregon law provides for trebling of the damages associated with timber, shrubs and produce in the event the defendant is determined to have willfully and
intentionally trespassed. Based on available information to date, PacifiCorp believes it is probable that losses will be incurred associated with the 2020 Wildfires. Final determinations of liability will only be made following the completion of comprehensive investigations, litigation or
similar processes, the outcome of which, if adverse, could, in the aggregate, have a material adverse effect on PacifiCorp's financial condition.
The James Case
On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al, in Multnomah County Circuit Court, Oregon ("James"). The complaint was filed by Oregon residents and businesses who seek to represent a class of all
Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. In November 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted
by the Santiam Canyon, Echo Mountain Complex, South Obenchain and 242 wildfires. In May 2022, the Multnomah County Circuit Court granted issue class certification and consolidated the James case with several other cases. While PacifiCorp's pre-trial request for immediate appeal of
the class certification was denied, it subsequently filed to appeal the class issues as described below.
In April 2023, the jury trial for James with respect to 17 named plaintiffs began in Multnomah County Circuit Court. In June 2023, the jury issued its verdict finding PacifiCorp liable to the 17 named plaintiffs and to the class with respect to the four wildfires. The jury found PacifiCorp's
conduct grossly negligent, reckless and willful as to each plaintiff and the entire class. The jury awarded the 17 named plaintiffs $90 million of damages, including $4 million of economic damages, $68 million of noneconomic damages and $18 million of punitive damages based on a 0.25
multiplier of the economic and noneconomic damages.
In September 2023, the Multnomah County Circuit Court ordered trial dates for two consolidated jury trials including approximately 10 class members each and a third trial for certain commercial timber plaintiffs wherein plaintiffs in each of the three damages phase trials will present
evidence regarding their damages. The first of these trials addressing nine individual plaintiffs was held in January 2024 while the remaining trials are scheduled at various dates through April 2024.
In January 2024, the Multnomah County Circuit Court entered a limited judgment and money award for the June 2023 James verdict. The limited judgment awards the aforementioned damages, as well as doubling of the economic damages and offsetting of any insurance proceeds received
by plaintiffs. The limited judgment created a lien against PacifiCorp, attaching a debt for the money awards. PacifiCorp posted a supersedeas bond, which stays any effort to seek payment of the judgment pending final resolution of any appeals. Under ORS 82.010, interest at a rate of 9%
per annum will accrue on the judgment commencing at the date the judgment was entered until the entire money award is paid, amended or reversed by an appellate court. In January 2024, PacifiCorp filed a notice of appeal associated with the June 2023 verdict in James, including whether
the case can proceed as a class action and filed a motion to stay further damages phase trials. On February 14, 2024, the Oregon Court of Appeals denied PacifiCorp's request to stay the damages phase trials. On February 13, 2024, the 17 named plaintiffs filed a notice of cross-appeal as to
the January 2024 limited judgment and money award. The appeals process and further actions could take several years.
In January 2024, the jury for the first James damages phase trial awarded nine plaintiffs $62 million of damages, including $6 million of economic damages and $56 million of noneconomic damages. After the jury verdict, the Multnomah County Circuit Court doubled the economic
damages to $12 million and added $16 million of punitive damages using the 0.25 multiplier determined by the jury for the June 2023 James verdict. PacifiCorp will request that the Multnomah County Circuit Court judge offset the damage awards by deducting insurance proceeds received
by any of the nine plaintiffs. PacifiCorp intends to appeal the jury's damage awards associated with the January 2024 jury verdict once judgement is entered.
2022 McKinney Fire
According to the California Department of Forestry and Fire Protection, on July 29, 2022, the 2022 McKinney Fire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California located in PacifiCorp's service territory, burning over 60,000 acres.
Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged; 185 structures destroyed, including residences; 12 injuries; and four fatalities. The cause of the 2022 McKinney Fire is undetermined and remains under investigation by the U.S. Forest Service, the
California Public Utilities Commission, PacifiCorp and various experts engaged by PacifiCorp.
As of the date of this filing, multiple complaints have been filed in California on behalf of plaintiffs related to the 2022 McKinney Fire. The plaintiffs seek damages for economic losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life,
punitive damages, other damages and attorneys' fees, but the amount of damages sought is not specified.
Based on available information to date, PacifiCorp believes it is probable a loss will be incurred associated with the 2022 McKinney Fire. Final determinations of liability will only be made following the completion of comprehensive investigations, litigation or similar processes.
Estimated Losses for and Settlements Associated with the Wildfires
Based on the facts and circumstances available to PacifiCorp through February 23, 2024, the date through which PacifiCorp has evaluated the impacts of events occurring after December 31, 2023 as indicated under "Subsequent Events", including (i) ongoing cause and origin
investigations; (ii) ongoing settlement and mediation discussions; (iii) other litigation matters and upcoming legal proceedings; and (iv) the status of the James case, PacifiCorp increased its accrual by $1,930 million during the year ended December 31, 2023, bringing its cumulative
estimated probable losses associated with the Wildfires to $2,407 million through December 31, 2023. PacifiCorp's cumulative accrual includes estimates of probable losses for fire suppression costs, real and personal property damages, natural resource damages and noneconomic damages
such as personal injury damages and loss of life damages that it is reasonably able to estimate at this time and which is subject to change as additional relevant information becomes available. Any information associated with the Wildfires arising subsequent to February 23, 2024 will be
considered in a future period.
Through December 31, 2023, PacifiCorp paid $684 million in settlements associated with the 2020 Wildfires, including $299 million to 463 claimants and $250 million to 10 companies with commercial timber interests associated with the Archie Creek, French Creek, Susan Creek and
Smith Springs Road fires (collectively, the "Archie Creek Complex Fire") in Douglas County, Oregon. The Archie Creek Complex Fire settlements resolve substantially all claims filed by individual plaintiffs and
all claims filed by commercial timber plaintiffs associated with the Archie Creek Complex Fire, but do not address related damages claimed by the U.S. or Oregon Departments of Justice. In January 2024 through February 23, 2024, PacifiCorp entered into additional settlements associated
with the 2020 Wildfires totaling $51 million with 167 plaintiffs.
The following table presents changes in PacifiCorp's liability for estimated losses associated with the Wildfires for the years ended December 31 (in millions):
2023 2022
Beginning balance $424 $252
Accrued losses 1,930 225
Payments (631)(53)
Ending balance $1,723 $424
Amounts represent payments made to settle certain claims associated with the 2020 Wildfires, including $549 million in December 2023 resulting from the above-described settlement agreements reached in December 2023 associated with the Archie Creek Complex Fire.

As of December 31, 2023 and 2022, $4 million and $24 million, respectively, of PacifiCorp's liability for estimated losses associated with the Wildfires was included in Total Current and Accrued Liabilities on the Comparative Balance Sheet.
Until such time that settlement terms or other conclusions are reached to indicate that payments are expected to occur in the short-term, PacifiCorp's liability for estimated losses associated with the Wildfires is included in Total Other Noncurrent Liabilities on the Comparative Balance
Sheet.
The following table presents changes in PacifiCorp's receivable for expected insurance recoveries associated with the Wildfires for the years ended December 31 (in millions):
2023 2022
Beginning balance $246 $116
Accruals 253 161
Payments received — (31)
Ending balance $499 $246
As of December 31, 2023 and 2022, $350 million and $16 million, respectively, of PacifiCorp's receivable for expected insurance recoveries was included in Total Current and Accrued Assets, while the remaining $149 million and $230 million, respectively, was included in Total Other
Noncurrent Liabilities on the Comparative Balance Sheet. In January and February 2024, PacifiCorp received $338 million of insurance proceeds related to the 2020 Wildfires.
During the years ended December 31, 2023 and 2022, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $1,677 million and $64 million, respectively. No additional insurance recoveries beyond those accrued to date are expected to
be available.
It is reasonably possible PacifiCorp will incur material additional losses beyond the amounts accrued for the Wildfires that could have a material adverse effect on PacifiCorp's financial condition. PacifiCorp is currently unable to reasonably estimate a specific range of possible additional
losses that could be incurred due to the number of properties and parties involved, including claimants in the class to the James case, the variation in the types of properties and damages and the ultimate outcome of legal actions.
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, 2023, 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, 2023, PacifiCorp's actual common equity percentage, as calculated under this measure, was 50%.
These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings or BHE if PacifiCorp's senior unsecured debt rating is BBB- or lower by Standard & Poor's Rating Services or Fitch Ratings, or Baa3 or lower by Moody's Investor Service, as indicated by
two of the three rating services. As of December 31, 2023, PacifiCorp met these minimum required senior unsecured debt ratings.
PacifiCorp is also subject to a maximum debt-to-total capitalization percentage under various financing agreements as further discussed in Note 7.
(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):
2023 2022
Interest paid, net of amounts capitalized $432 $380
Income taxes received, net $297 $197
Supplemental disclosure of non-cash investing and financing activities:
Accounts payable related to utility plant additions $862 $558
(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.
FERC FORM No. 1 (ED. 12-96)
Page 122-123
(1)
(1)
(1)
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
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.
Line
No.
Item
(a)
Unrealized Gains
and Losses on
Available-For-Sale
Securities
(b)
Minimum Pension
Liability
Adjustment (net
amount)
(c)
Foreign Currency
Hedges
(d)
Other Adjustments
(e)
Other Cash
Flow Hedges
Interest Rate
Swaps
(f)
Other
Cash
Flow
Hedges
[Specify]
(g)
Totals for
each
category of
items
recorded in
Account
219
(h)
Net Income
(Carried
Forward
from Page
116, Line 78)
(i)
Total
Comprehensive
Income
(j)
1 Balance of Account 219 at
Beginning of Preceding Year (17,132,153)(17,132,153)
2
Preceding Quarter/Year to Date
Reclassifications from Account
219 to Net Income
963,429 963,429
3 Preceding Quarter/Year to Date
Changes in Fair Value 6,820,108 6,820,108
4 Total (lines 2 and 3)7,783,537 7,783,537 920,107,831 927,891,368
5 Balance of Account 219 at End
of Preceding Quarter/Year (9,348,616)(9,348,616)
6 Balance of Account 219 at
Beginning of Current Year (9,348,616)(9,348,616)
7
Current Quarter/Year to Date
Reclassifications from Account
219 to Net Income
470,469 470,469
8 Current Quarter/Year to Date
Changes in Fair Value (1,491,089)(1,491,089)
9 Total (lines 7 and 8)(1,020,620)(1,020,620)(467,588,533)(468,609,153)
10 Balance of Account 219 at End
of Current Quarter/Year (10,369,236)(10,369,236)
FERC FORM No. 1 (NEW 06-02)
Page 122 (a)(b)
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
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.
Line
No.
Classification
(a)
Total Company For the
Current Year/Quarter
Ended
(b)
Electric
(c)
Gas
(d)
Other (Specify)
(e)
Other (Specify)
(f)
Other
(Specify)
(g)
Common
(h)
1
2
3 33,301,600,620 33,301,600,620
4 24,034,133 24,034,133
5
6 547,634,625 547,634,625
7
8 33,873,269,378 33,873,269,378
9
10 14,174,575 14,174,575
11 4,719,845,635 4,719,845,635
12 156,468,483 156,468,483
13 38,763,758,071 38,763,758,071
14 13,094,069,120 13,094,069,120
15 25,669,688,951 25,669,688,951
16
17
18 12,167,631,341 12,167,631,341
19
20
21 781,734,972 781,734,972
22 12,949,366,313 12,949,366,313
23
24
25
26
27
28
29
30
31
32 144,702,807 144,702,807
33 13,094,069,120 13,094,069,120
FERC FORM No. 1 (ED. 12-89)
Page 200-201
UTILITY PLANT
In Service
Plant in Service (Classified)
Property Under Capital Leases
Plant Purchased or Sold
Completed Construction not Classified
Experimental Plant Unclassified
Total (3 thru 7)
Leased to Others
Held for Future Use
Construction Work in Progress
Acquisition Adjustments
Total Utility Plant (8 thru 12)
Accumulated Provisions for Depreciation,
Amortization, & Depletion
Net Utility Plant (13 less 14)
DETAIL OF ACCUMULATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION
AND DEPLETION
In Service:
Depreciation
Amortization and Depletion of Producing
Natural Gas Land and Land Rights
Amortization of Underground Storage Land
and Land Rights
Amortization of Other Utility Plant
Total in Service (18 thru 21)
Leased to Others
Depreciation
Amortization and Depletion
Total Leased to Others (24 & 25)
Held for Future Use
Depreciation
Amortization
Total Held for Future Use (28 & 29)
Abandonment of Leases (Natural Gas)
Amortization of Plant Acquisition Adjustment
Total Accum Prov (equals 14)
(22,26,30,31,32)
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
1. Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent.
2. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing
arrangements.
Line
No.
Description of item
(a)
Balance Beginning of Year
(b)
Changes during Year
Additions
(c)
Changes during Year
Amortization
(d)
Changes during Year Other
Reductions (Explain in a
footnote)
(e)
Balance End of Year
(f)
1 Nuclear Fuel in process of Refinement, Conv,
Enrichment & Fab (120.1)
2 Fabrication
3 Nuclear Materials
4 Allowance for Funds Used during Construction
5 (Other Overhead Construction Costs, provide
details in footnote)
6 SUBTOTAL (Total 2 thru 5)
7 Nuclear Fuel Materials and Assemblies
8 In Stock (120.2)
9 In Reactor (120.3)
10 SUBTOTAL (Total 8 & 9)
11 Spent Nuclear Fuel (120.4)
12 Nuclear Fuel Under Capital Leases (120.6)
13 (Less) Accum Prov for Amortization of Nuclear Fuel
Assem (120.5)
14 TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less
13)
15 Estimated Net Salvage Value of Nuclear Materials
in Line 9
16 Estimated Net Salvage Value of Nuclear Materials
in Line 11
17 Est Net Salvage Value of Nuclear Materials in
Chemical Processing
18 Nuclear Materials held for Sale (157)
19 Uranium
20 Plutonium
21 Other (Provide details in footnote)
22 TOTAL Nuclear Materials held for Sale (Total 19,
20, and 21)
FERC FORM No. 1 (ED. 12-89)
Page 202-203
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
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
the 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) 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.
Line
No.
Account
(a)
Balance Beginning of
Year
(b)
Additions
(c)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at
End of Year
(g)
1 1. INTANGIBLE PLANT
2 (301) Organization
3 (302) Franchise and Consents 173,498,124 3,964,953 671,924 176,791,153
4 (303) Miscellaneous Intangible Plant 955,483,086 26,129,675 18,619,023 (g)(5,807,842)(5,203)957,180,693
5 TOTAL Intangible Plant (Enter Total of lines 2,
3, and 4)1,128,981,210 30,094,628 19,290,947 (5,807,842)(5,203)1,133,971,846
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights 91,714,952 91,714,952
9 (311) Structures and Improvements 1,006,874,970 49,019,064 1,647,499 1,054,246,535
10 (312) Boiler Plant Equipment 4,432,371,231 66,234,878 105,392,940 4,393,213,169
11 (313) Engines and Engine-Driven Generators
12 (314) Turbogenerator Units 986,357,587 23,498,039 13,280,904 996,574,722
13 (315) Accessory Electric Equipment 427,643,229 1,076,640 (159,611)428,879,480
14 (316) Misc. Power Plant Equipment 33,442,838 3,397,843 1,413,450 35,427,231
15 (317) Asset Retirement Costs for Steam
Production 178,869,688 34,918,256 161,978 (9,708,375)203,917,591
16 TOTAL Steam Production Plant (Enter Total
of lines 8 thru 15)7,157,274,495 178,144,720 121,737,160 (9,708,375)7,203,973,680
17 B. Nuclear Production Plant
18 (320) Land and Land Rights
19 (321) Structures and Improvements
20 (322) Reactor Plant Equipment
21 (323) Turbogenerator Units
22 (324) Accessory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear
Production
25 TOTAL Nuclear Production Plant (Enter Total
of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights 38,471,099 38,471,099
28 (331) Structures and Improvements 282,039,563 6,492,017 833,425 287,698,155
29 (332) Reservoirs, Dams, and Waterways 515,037,675 4,635,547 1,341,198 518,332,024
30 (333) Water Wheels, Turbines, and
Generators 130,476,138 290,502 17,532 130,749,108
31 (334) Accessory Electric Equipment 72,908,213 645,187 34,235 73,519,165
32 (335) Misc. Power Plant Equipment 2,663,098 846,771 5,644 3,504,225
33 (336) Roads, Railroads, and Bridges 25,167,484 2,856,145 283,538 27,740,091
34 (337) Asset Retirement Costs for Hydraulic
Production
35 TOTAL Hydraulic Production Plant (Enter
Total of lines 27 thru 34)1,066,763,270 15,766,169 2,515,572 1,080,013,867
36 D. Other Production Plant
37 (340) Land and Land Rights 52,866,070 4,047,974 56,914,044
38 (341) Structures and Improvements 276,454,764 3,553,888 6,331 280,002,321
39 (342) Fuel Holders, Products, and
Accessories 16,412,329 27,024 16,439,353
40 (343) Prime Movers 4,032,385,708 117,322,768 27,999,681 4,121,708,795
41 (344) Generators 594,982,164 13,881,484 676,418 608,187,230
42 (345) Accessory Electric Equipment 463,165,933 4,413,122 165,432 467,413,623
43 (346) Misc. Power Plant Equipment 24,864,159 1,013,590 (11,911)25,889,660
44 (347) Asset Retirement Costs for Other
Production 47,923,299 3,765,653 (379,897)51,309,055
44.1 (348) Energy Storage Equipment -
Production
45 TOTAL Other Prod. Plant (Enter Total of lines
37 thru 44)5,509,054,426 148,025,503 28,835,951 (379,897)5,627,864,081
46 TOTAL Prod. Plant (Enter Total of lines 16,
25, 35, and 45)
(a)13,733,092,191 341,936,392 153,088,683 (10,088,272)(h)
13,911,851,628
47 3. Transmission Plant
48 (350) Land and Land Rights 348,935,285 2,384,696 1,098,301 350,221,680
48.1 (351) Energy Storage Equipment -
Transmission
49 (352) Structures and Improvements 383,301,808 5,258,745 96,022 10,425 388,474,956
50 (353) Station Equipment 2,766,928,999 68,513,129 9,813,652 59,144 2,825,687,620
51 (354) Towers and Fixtures 1,529,201,487 24,269,114 2,341,983 1,551,128,618
52 (355) Poles and Fixtures 1,298,654,510 49,537,594 7,745,816 177,543 1,340,623,831
53 (356) Overhead Conductors and Devices 1,694,195,111 42,605,063 6,427,721 (173,428)1,730,199,025
54 (357) Underground Conduit 3,868,617 42,061 25,928 3,884,750
55 (358) Underground Conductors and Devices 9,080,617 3,007 9,083,624
56 (359) Roads and Trails 12,141,468 12,141,468
57 (359.1) Asset Retirement Costs for
Transmission Plant 2,528,190 125,527 (259,905)2,393,812
58 TOTAL Transmission Plant (Enter Total of
lines 48 thru 57)
(b)8,048,836,092 192,738,936 27,549,423 (259,905)73,684 (i)
8,213,839,384
59 4. Distribution Plant
60 (360) Land and Land Rights 78,571,918 3,238,570 (12,590)13,946 81,837,024
61 (361) Structures and Improvements 146,224,254 6,984,531 59,656 153,149,129
62 (362) Station Equipment 1,257,061,910 72,656,031 5,241,205 (69,569)1,324,407,167
63 (363) Energy Storage Equipment –
Distribution
64 (364) Poles, Towers, and Fixtures 1,509,112,218 137,665,333 14,238,368 (4,115)1,632,535,068
65 (365) Overhead Conductors and Devices 944,782,984 112,615,403 11,149,343 1,046,249,044
66 (366) Underground Conduit 477,665,581 41,395,256 2,957,864 516,102,973
67 (367) Underground Conductors and Devices 1,088,850,385 88,370,605 5,403,656 1,171,817,334
68 (368) Line Transformers 1,601,353,708 89,801,244 13,203,974 1,677,950,978
69 (369) Services 1,009,228,967 54,195,223 1,325,116 1,062,099,074
70 (370) Meters 281,685,480 42,649,260 13,942,868 310,391,872
71 (371) Installations on Customer Premises 8,840,097 116,334 48,329 8,908,102
72 (372) Leased Property on Customer
Premises
73 (373) Street Lighting and Signal Systems 63,026,819 2,532,511 1,749,257 63,810,073
74 (374) Asset Retirement Costs for Distribution
Plant 1,331,349 1,331,349
75 TOTAL Distribution Plant (Enter Total of lines
60 thru 74)
(c)8,467,735,670 652,220,301 69,307,046 (59,738)(j)
9,050,589,187
76 5. REGIONAL TRANSMISSION AND
MARKET OPERATION PLANT
77 (380) Land and Land Rights
78 (381) Structures and Improvements
79 (382) Computer Hardware
80 (383) Computer Software
81 (384) Communication Equipment
82 (385) Miscellaneous Regional Transmission
and Market Operation Plant
83 (386) Asset Retirement Costs for Regional
Transmission and Market Oper
84 TOTAL Transmission and Market Operation
Plant (Total lines 77 thru 83)
85 6. General Plant
86 (389) Land and Land Rights 25,071,997 25,071,997
87 (390) Structures and Improvements 286,074,073 17,929,978 2,161,165 301,842,886
88 (391) Office Furniture and Equipment 105,109,861 13,834,360 24,586,194 5,203 94,363,230
89 (392) Transportation Equipment 152,732,782 32,664,403 4,945,292 (594,150)179,857,743
90 (393) Stores Equipment 17,555,251 3,315,780 366,518 20,504,513
91 (394) Tools, Shop and Garage Equipment 68,130,595 4,785,691 2,837,923 70,078,363
92 (395) Laboratory Equipment 43,283,258 6,229,437 1,478,167 48,034,528
93 (396) Power Operated Equipment 231,266,539 29,622,840 10,312,087 594,150 251,171,442
94 (397) Communication Equipment 526,053,780 27,645,342 16,784,387 536,914,735
95 (398) Miscellaneous Equipment 9,996,926 (145,935)567,819 9,283,172
96 SUBTOTAL (Enter Total of lines 86 thru 95)1,465,275,062 135,881,896 64,039,552 5,203 1,537,122,609
97 (399) Other Tangible Property (d)1,822,901 (k)1,822,901
98 (399.1) Asset Retirement Costs for General
Plant 39,748 (2,058)37,690
99 TOTAL General Plant (Enter Total of lines 96,
97, and 98)
(e)1,467,137,711 135,881,896 64,039,552 (2,058)5,203 (l)
1,538,983,200
100 TOTAL (Accounts 101 and 106)32,845,782,874 1,352,872,153 333,275,651 (16,158,077)13,946 33,849,235,245
101 (102) Electric Plant Purchased (See Instr. 8)
102 (Less) (102) Electric Plant Sold (See Instr. 8)
103 (103) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total
of lines 100 thru 103)
(f)32,845,782,874 1,352,872,153 333,275,651 (16,158,077)13,946 (m)
33,849,235,245
FERC FORM No. 1 (REV. 12-05)
Page 204-207
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: ProductionPlant
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)13,733,092,191
Less: (317) Asset Retirement Costs for Steam Production 15 (b)178,869,688
Less: (326) Asset Retirement Costs for Nuclear Production 24 (b)—
Less: (337) Asset Retirement Costs for Hydraulic Production 34 (b)—
Less: (347) Asset Retirement Costs for Other Production 44 (b)47,923,299
Revised TOTAL Production Plant $13,506,299,204
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.
(b) Concept: TransmissionPlant
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 Transmission Plant 58 (b)$8,048,836,092
Less: (359.1) Asset Retirement Costs for Transmission Plant 57 (b)2,528,190
Revised TOTAL Transmission Plant $8,046,307,902
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.
(c) Concept: DistributionPlant
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 Distribution Plant 75 (b)$8,467,735,670
Less: (374) Asset Retirement Costs for Distribution Plant 74 (b)1,331,349
Revised TOTAL Distribution Plant $8,466,404,321
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.
(d) Concept: OtherTangibleProperty
Account 399.21, Land owned in fee
(e) Concept: GeneralPlant
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 General Plant 99 (b)$1,467,137,711
Less: (399) Other Tangible Property 97 (b)1,822,901
Less: (399.1) Asset Retirement Costs for General Plant 98 (b)39,748
Revised TOTAL General Plant $1,465,275,062
To adjust PacifiCorp's formula rate, per FERC Docket No. FA16-4-000 for mining assets related to production plant.
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.
(f) Concept: ElectricPlantInService
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 Intangible Plant 5 (b)$1,128,981,210
Revised TOTAL Production Plant 13,506,299,204
Revised TOTAL Transmission Plant 8,046,307,902
Revised TOTAL Distribution Plant 8,466,404,321
Revised TOTAL General Plant 1,465,275,062
(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 $32,613,267,699
Refer to footnote on page 204, line no. 46, column (b)
Refer to footnote on page 204, line no. 58, column (b)
Refer to footnote on page 204, line no. 75, column (b)
Refer to footnote on page 204, line no. 99, column (b)
(g) Concept: MiscellaneousIntangiblePlantAdjustments
Refer to Item 3 of Important Changes During the Year of this Form No. 1 for discussion regarding the Lower Klamath Hydroelectric Project.
(h) Concept: ProductionPlant
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)$13,911,851,628
Less: (317) Asset Retirement Costs for Steam Production 15 (g)203,917,591
Less: (326) Asset Retirement Costs for Nuclear Production 24 (g)—
Less: (337) Asset Retirement Costs for Hydraulic Production 34 (g)—
Less: (347) Asset Retirement Costs for Other Production 44 (g)51,309,055
Revised TOTAL Production Plant $13,656,624,982
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.
(i) Concept: TransmissionPlant
(1)
(1)
(1)
(1)
(1)
(1)
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(1)
(1)
(1)
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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 Transmission Plant 58 (g)$8,213,839,384
Less: (359.1) Asset Retirement Costs for Transmission Plant 57 (g)2,393,812
Revised TOTAL Transmission Plant $8,211,445,572
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.
(j) Concept: DistributionPlant
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 Distribution Plant 75 (g)$9,050,589,187
Less: (374) Asset Retirement Costs for Distribution Plant 74 (g)1,331,349
Revised TOTAL Distribution Plant $9,049,257,838
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.
(k) Concept: OtherTangibleProperty
Account 399.21, Land owned in fee
(l) Concept: GeneralPlant
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 General Plant 99 (g)$1,538,983,200
Less: (399) Other Tangible Property 97 (g)1,822,901
Less: (399.1) Asset Retirement Costs for General Plant 98 (g)37,690
Revised TOTAL General Plant $1,537,122,609
To adjust PacifiCorp's formula rate, per FERC Docket No. FA16-4-000 for mining assets related to production plant.
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.
(m) Concept: ElectricPlantInService
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 Intangible Plant 5 (g)$1,133,971,846
Revised TOTAL Production Plant 13,656,624,982
Revised TOTAL Transmission Plant 8,211,445,572
Revised TOTAL Distribution Plant 9,049,257,838
Revised TOTAL General Plant 1,537,122,609
(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 $33,588,422,847
Refer to footnote on page 204, line no. 46, column (g)
Refer to footnote on page 204, line no. 58, column (g)
Refer to footnote on page 204, line no. 75, column (g)
Refer to footnote on page 204, line no. 99, column (g)
FERC FORM No. 1 (REV. 12-05)
Page 204-207
(1)
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Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Line
No.(a)
(b)
(c)(d)(e)(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
Name of Lessee
*
(Designation
of
Associated
Company)
Description of Property Leased Commission Authorization Expiration Date of Lease Balance at End of Year
47 TOTAL
FERC FORM No. 1 (ED. 12-95)
Page 213
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
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.
Line
No.(a)(b)(c)(d)
1 Land and Rights:
2 Barnes Butte Substation 08/24/2007 12/31/2032 746,268
3 Jumbers Point Substation 03/14/2008 12/31/2024 1,173,276
4 Mountain Green Substation 12/31/2009 12/31/2026 284,996
5 Hoggard Substation 02/21/2009 12/31/2026 254,397
6 Oquirrh-Terminal 345kV Transmission Line 02/21/2009 12/31/2024 396,020
7 Bend Service Center 07/06/2010 12/31/2024 2,981,121
8 Populus Substation 02/28/2011 12/31/2024 254,753
9 Old Mill Substation 11/30/2012 12/31/2030 1,838,281
10 Chimney Butte-Paradise 230kV Transmission Line 03/11/2013 12/31/2030 598,457
11 Fiddlers Canyon Substation 06/29/2016 12/31/2028 1,136,587
12 Banfield Substation 12/29/2017 12/31/2026 3,166,188
13 Ochoco Substation 12/21/2020 12/31/2031 594,174
14 (a)
Miscellaneous, each under $250,000:750,057
21 Other Property:
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 TOTAL 14,174,575
FERC FORM No. 1 (ED. 12-96)
Page 214
Description and Location of Property Date Originally Included in This
Account
Date Expected to be used in Utility
Service Balance at End of Year
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: ElectricPlantHeldForFutureUseDescription
Various dates properties were originally included in FERC Account 105. Various dates properties are expected to be placed in service.
FERC FORM No. 1 (ED. 12-96)
Page 214
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
CONSTRUCTION WORK IN PROGRESS - - 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.
Line No.(a)(b)
1 Intangible:
2 Oracle Systems Software 193,860,726
3 Field Ai-Field Asset Intelligence and Related Software Implementations 44,838,513
4 UII Software Upgrade 10,329,086
5 Palantir Foundry 8,300,000
6 Mobile GIS Software 7,831,215
7 Cutler Hydro Relicensing 6,262,620
8 PacifiCorp Public Safety Partner Portal Software 5,476,658
9 Advanced Weather Forecasting & Analytics Software 1,908,610
10 APIM-Asset Performance and Investment Management Software 1,630,095
11 Customer Mobile Apps Software 1,552,196
12 Endur Software Upgrade 1,528,915
13 Maximo Generation 1,414,142
14 PAC SolarWinds 1,383,902
15 Vertex for Oracle 1,134,750
16 Ambient Ai- Video Security 1,083,017
17 OpenMethods for Oracle 1,029,118
18 Production:
19 Rock Creek Wind II 438,464,084
20 Rock Creek Wind I 231,492,935
21 Rock River Wind 65,984,389
22 Fall Creek Hatchery 31,535,058
23 Lewis River System Relicensing Implementation 18,711,574
24 Jim Bridger U2 Conversion to Natural Gas 10,104,139
25 Jim Bridger U1 Conversion to Natural Gas 9,849,614
26 Yale Saddle Dam Seismic Remediation 8,960,206
27 Grace Hydro Unit 3 Overhaul 8,566,382
28 Toketee Dam Rehabilitation Evaluation 6,461,207
29 Viva Naughton FERC Production Compliance 5,213,086
30 Swift 1 Hydro Spillway Gate Bulkhead 4,734,134
31 Toketee 2 Turbine Refurbishment 4,322,632
32 Yale Main Dam In-Situ Instrumentation 4,194,896
33 ILR 4.5 Yale Downstream Fish Passage 3,655,875
34 Swift 1 Hydro Spillway Improvements 3,522,219
35 Swift 1 Hydro Spillway Gate Retrofit 3,281,070
36 Yale Dam Spillway Upgrades Evaluation 3,171,884
37 Cutler Hydro Surge Tank Anchor Upgrades 3,113,811
38 Prospect 3 Hydro - South Fork Flowline Repairs 2,759,280
39 North Fork Dam Upgrade 2,613,495
40 Huntington RO Softener to Thickener Piping 2,282,841
41 Weber Dam Improvements Evaluation 1,911,402
42 Hunter U3 Baghouse Bags 1,867,725
43 Bear River Hydro Flood and Structural Assessment Project 1,713,154
44 Hunter U3 ID Fans Variable Frequency Drives 1,680,325
45 Lemolo 1 Spillway Improvements 1,565,622
46 Oneida Switchgear 1,406,583
Description of Project Construction work in progress - Electric (Account 107)
47 Grace Unit #3 Pivot Valve 1,332,259
48 Ashton Hydro Trash Rake 1,294,427
49 Hunter Recovery Basin Lining 1,276,589
50 Hunter U3 3-7 Feedwater Heater Replacement 1,215,262
51 Cutler Dam Upgrades 1,097,161
52 Hunter U3 Air Preheater Basket Replacement 1,081,183
53 Lake Side Gas Continuous Emission Monitors Change Out & ESC Programming 1,055,862
54 Jim Bridger Southend Building Heating 1,048,078
55 Toketee Unit 2 Turbine Isolation Valve Replacement 1,023,569
56 Clearwater 1 Forebay Trash Rake 1,019,032
57 Transmission:
58 Aeolus - Mona 500kV Line 1,732,223,071
59 Windstar - Shirley Basin 230kV Line 209,863,126
60 Boardman - Hemingway 500kV Line 167,235,650
61 Anticline 345 kV Phase Shifting Transformers 105,453,786
62 Populus - Hemingway 500kV Line 99,683,865
63 Anticline - Populus 500kV Line 69,441,321
64 Oquirrh - Terminal 345kV Line 50,897,271
65 Project Specialized, 242 MW Load 35,590,971
66 Path C Transmission Improvements 28,767,072
67 Sams Valley New 500-230kV Substation 23,163,837
68 Q2913 Powerex Corp Transmission Service Request 23,006,398
69 Q0835 Rock Creek Wind LLC–Rock Creek Wind I 17,766,516
70 Gateway Central-Limber Area Reinforcements Segment C 16,812,024
71 Project Litespeed 16,082,094
72 Enhanced Substation Security - Rocky Mountain Power 14,062,630
73 Aligned Energy Data Ctrs Propco, 200 MW 12,629,751
74 Walla Walla 69 kV Loop Reconfigure and Reconductor 12,221,851
75 Columbia - Coal Creek Wildfire Mitigation and Restoration 8,853,904
76 Cottonwood-Snyderville 138kV Rebuild for Wildfire 8,829,904
77 Grantsville Convert to 138 kV 7,319,406
78 Tucker 69 kV Tie Line 5,340,229
79 Magna Cap and Tooele-Pine Canyon Rebuild 4,957,775
80 Aeolus Substation Transformer 4,943,960
81 Replace Sigurd #6 Trf 345-230kV 450MVA 4,880,534
82 El Monte-Eden 46kV Rebuild for Wildfire 4,812,600
83 Snyderville-Park Cty 46kV Rebuild for Wildfire 4,731,494
84 TCS-48 Dominguez Storage 1 4,573,590
85 Malin-Casebeer New 69 kV Line 4,548,462
86 Midpoint 500kV Series Cap Bank Replacement (IDP)4,283,933
87 Q0777 Hornshadow Solar 4,240,303
88 Houston Lake-Ponderosa Add Second 115kV Line 3,622,372
89 Lines 30 & 65 Convert to 115 kV, Construct New 230-69kV Substation 3,615,624
90 Q805 Glen Canyon Solar A, LLC 3,322,830
91 St. Johns (BPA) to Knott 115 kV Line Conversion 3,241,424
92 Burns 500 kV Series Capacitor Bank Replacement 2,685,164
93 Loop 90 S-Terminal into MidValley 345kV Line 2,522,455
94 Q0838 Faraday Solar 2,499,002
95 Hurricane Sub Spare 230-69 kV-25 MVA Transformer 2,367,139
96 Park City - Judge 46kV Line Rebuild for Wildfire 2,296,198
97 North Bench-Northeast 46kV Line Rebuild for Wildfire 2,133,066
98 Weirich to BPA Lebanon 115kV Tie Line 2,130,015
99 Gateway South Support Project - Shunt Capacitor Banks 2,015,963
100 Q2599 PAC ESM Swift-Troutdale 230kV Line Transmission Service Request 1,972,891
101 Shirley Basin-Anticline 500kV Line D2.2 1,930,178
102 Dixonville Sub Replace Transformer T-3112 1,872,053
103 Alturas Replace 115-69kV Transformer Bank 1,862,106
104 N Umpqua Pump Storage Project - Dixonville Transformer T3843 1,855,773
105 OTP Q0196 Nephi 2nd Point of Delivery UMPA 1,853,417
106 Construct Jackalope-Bixby 115kV Line 1,701,168
107 Lyons Loop into Santiam - New Tie Line 1,666,831
108 Lone Pine - Whetstone 230 kV Line 1,659,903
109 Pilot Butte Sub Replace 3 CTs 1,643,839
110 Dumas-Dimple Dell 138kV Underground Failure 1,518,428
111 Camp Williams 345-138kV Transformer and 138kV Yard Addition 1,499,546
112 WP West Acquisitions-ACC Burial on 100 S in downtown SLC 1,488,989
113 Amps Substation Replace Control Building 1,438,159
114 Hunter U1 Spare Generator Step-Up Transformer Replacement 1,411,207
115 Jim Bridger - Goshen 345kV Line Structures Replacement 1,393,623
116 St. George - Purgatory Flat Line Upgrade 1,316,138
117 Capitol-North Bench 138kV Line Rebuild for Wildfire 1,298,847
118 Ben Lomond-Naughton #1 230kV Line Replace Structures 1,271,301
119 PDX 50 MVA Mobile Transf T3510 Rebuild 1,263,693
120 Judge - Midway 46kV Rebuild for Wildfire 1,247,925
121 RMP New Spare 138-46kV (150MVA) Transformer 1,165,030
122 Pomona Heights Sub 230-115 kV Transformer Replacements TPL 1,114,556
123 Moab-Pinto 138 kV Line - Install Auto Rollover 1,095,691
124 Midpoint Sub T501 Transformer Damage (Idaho Power)1,077,676
125 CA–Wildfire Mitigation Current Differential Lines 38 44 South 1,053,535
126 Bluffdale 138 kV Conversion 1,037,349
127 Distribution:
128 Portland Willamette River Crossing Project 70,757,079
129 Fire High Consequence Area (FHCA) - Rebuild Brighton 12 17,034,137
130 OR Fire Mitigation Distribution Sub Relay Replacement Phase 1 12,380,698
131 Fire High Consequence Area (FHCA) - Rebuild Columbia 11 11,057,437
132 Aligned Energy Data Centers SLC, 20 MW 9,256,970
133 Skypark Sub 2nd 138-12kV Transformer 8,496,434
134 Utah Transit Authority, 10.24 MW Load 7,979,958
135 Nutglade Distribution Spacer Cable Install 7,335,360
136 Conser Road - Constuct New 115kV to 20.8 kV Substation 7,090,533
137 Olympia Development LLC, 35.92 MW Load 7,015,052
138 Fire High Consequence Area (FHCA) - Rebuild Quarry 15 6,911,443
139 Fire High Consequence Area (FHCA) - Rebuild Quarry 12 6,689,310
140 North Logan Area Greenfld 138-12.5kV Sub 6,497,445
141 RG Lakeview, 50.47 MW Load 6,259,324
142 Nibley - Constuct new 25Kv Circuit 6,181,574
143 Washington Distribution Spacer Cable Install 6,034,973
144 Apple Valley: New 69-12.47 kV Substation 6,004,461
145 Enlaw LLC, 15.93 MW Load 5,877,129
146 Oregon Distribution Spacer Cable Installation 5,381,760
147 BDO Sub: Install 2nd 138-12kV Transformer 5,196,756
148 Syracuse 138-13.2 kV Transformer 5,132,756
149 Mt Shasta Taps Distribution Spacer Cable Install - 5G76/5G79 4,629,831
150 Flint Substation - Construct New 115-12.5kV Substation 4,438,401
151 Timp Sub 2nd 138-12.5 kV 30 MVA Transformer 4,217,245
152 Utah Underground Cable Replacement 4,111,622
153 Copper Hills Install Second Transformer 4,089,606
154 Robertson Bridge Road Distribution Spacer Cable Install 3,920,484
155 Downtown SLC Development - Snarr Substation Conversion 3,876,223
156 West Valley Install Second Transformer 3,766,857
157 Fire High Consequence Area (FHCA) - Rebuild Butlerville 16 3,529,725
158 Utah-Distribution Mandated Wildfire Mitigation 3,400,925
159 Cross Hollow Add Distribution Capacity 3,392,197
160 West Weed/Edgewood Distribution Spacer Cable Install 3,343,460
161 Medford Road Widening/Lone Pine and Foothills Substations 3,334,058
162 EX Utah Development, 19.03 MW Load 3,308,697
163 Oregon Energy Storage Project 3,192,281
164 Seiad East & West Distribution Spacer Cable Install 3,192,196
165 118th South 6400 West 3,122,252
166 CA Fire Mitigation Distribution Sub Relay Replacement 3,114,832
167 CA Distribution Spacer Cable Install - 5G76 3,020,712
168 Oregon Expulsion Fuse Replacement - Grants Pass 2,975,647
169 Fire High Consequence Area (FHCA) - Rebuild Mountain Dell 11 2,974,632
170 Covered Conductor Sub to 0143300 - 5G40 2,534,511
171 Pony Express Mobile Connection, Load Transfer 2,499,939
172 Campbell Soup Supply Company, 1.5 MW 2,483,694
173 Arches Substation (Disappearing Angel)2,473,295
174 S Old Stage Road Distribution Spacer Cable Install 2,416,517
175 Northwest Quadrant Development - Lee Creek #2 2,413,785
176 Fire High Consequence Area (FHCA) - Rebuild New Harmony 11 2,389,104
177 Fire High Consequence Area (FHCA) - Rebuild Coleman 15 2,383,901
178 Hiouchi Hill - 5R165 2,372,918
179 Undergrould Line Rebuild Old Edgewood 4 - 5G83 2,361,039
180 Hood River Mosier Tie Distribution Spacer Cable Install - 5K70 2,331,479
181 Selma Thompson Creek Distribution Spacer Cable Install - 5R65 2,277,830
182 Taylor Sub: 46-12kV Transformer Replacement 2,216,601
183 Jumbers Point - New Substation 2,211,902
184 Fire Mitigation Distribution Sub Relay Replacement Phase 2 2,164,975
185 Salt Lake Dept of Airports - 14.7 MW Load 2,113,126
186 Russellville Distribution Automation Project - FLISR 2,089,166
187 Dodd Road Substation - Replace Transformer Bank 1 1,958,077
188 T&D Field Operations Training Modules 1,952,072
189 Mill City - New Substation 1,866,532
190 Fire High Consequence Area (FHCA) - Rebuild Olympus 13 1,827,194
191 Elk Horn Sub - Install 2nd 30MVA Transformer 1,760,933
192 Hwy 96 and Beaver Creek Line Rebuild - 5G40 1,760,316
193 Ruby Sub 69-12.5kV 14MVA Transformer Replacement 1,757,457
194 90th South Sub Install 30 MVA Transformer 1,716,555
195 Fire High Consequence Area (FHCA) - Rebuild Eden 11 1,658,511
196 Moab City Sub Upgrade Transformer 1,615,813
197 Pine Creek RNG LLC, 1,700 kW Load 1,601,399
198 TDW1401 / 3rd West Sub to LDS Data and Conference Center 1,593,684
199 Boise Cascade Sub Install Parallel Voltage Regulator 1,591,059
200 Seiad Creek Road CA Distribution Spacer Cable Install 1,585,408
201 Camp Williams Bank #1 Replacement for STASTA, LLC 1,564,752
202 Gordon Hollow - New Substation 1,537,457
203 Deer Creek Sub - New 69/13.2kV 25MVA Substation 1,521,655
204 Tata Chemicals Soda Ash Partners, 9MW Load 1,521,259
205 Enoch Sub Upgrade Transformer 1,513,669
206 Scott River Road Line Rebuild - 5G40 1,501,242
207 Redmond Sub - Replace 13 ABB DPU & 2TPU Relays 1,456,536
208 Yakima EV Charging Station 1,436,894
209 California Expulsion Fuse Replacement - Yreka 1,434,323
210 Rigby 161-12 kV Transformer Addition 1,413,837
211 Siskiyou Lake Distribution Spacer Cable Install 1,406,056
212 Garden City Sub Transformer Upgrade 1,392,480
213 Tap Lines Rebuild - 5G40 1,329,892
214 Weed City Taps 2023 CA Distribution Spacer Cable Install - 5G83 1,321,251
215 North Salt Lake Development - Cudahy #2 1,248,570
216 Mt Shasta City 4kV CA Distribution Spacer Cable Install - 7G81/7G82 1,224,296
217 Medford Distribution Automation Project - FLISR 1,200,892
218 Idaho-Distribution Mandated Wildfire Mitigation 1,188,138
219 Fire High Consequence Area (FHCA) - Rebuild Summit Park 11 1,182,427
220 WA Fire Mitigation Distribution Sub Relay Replacement 1,177,924
221 Fire High Consequence Area (FHCA) - Oregon Communicating Fault Circuit Indicators 1,166,732
222 Fire High Consequence Area (FHCA) - Rebuild Coalville 13 1,144,288
223 Amazon.com Services LLC, 6.24 MW Load 1,135,977
224 Riverbend Management Inc, 1.81 MW Load 1,128,059
225 Oregon Expulsion Fuse Replacement - Roseburg 1,119,030
226 SRC Land Holdings, 12.067 MW Load 1,117,001
227 Morrison Creek Sub Wildfire Mitigation Upgrades 1,075,222
228 Distribution Reconductor - 4M16 1,016,388
229 Clu12/Clu11 Reconductor 1,012,360
230 General:
231 Bend Juniper Ridge Service Center 19,283,347
232 North Temple Campus Redevelopment 15,239,423
233 Physical Access Control System FIPS 201 7,591,972
234 Calapooya to Mckenzie Fiber Install 2,409,407
235 Bend - T&D Training Facility 1,257,542
236 Cutler to Rabbit Mountain Microwave Replacement 1,216,159
237 New Salt Lake City Data Center 1,001,893
238 Miscellaneous Projects each under $1,000,000 307,330,982
43 Total 4,719,845,635
FERC FORM No. 1 (ED. 12-87)
Page 216
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
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 12, column (c), and that reported for electric plant in service, page 204, column (d), 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.
Line
No.
Item
(a)
Total (c + d + e)
(b)
Electric Plant in Service
(c)
Electric Plant Held for Future
Use
(d)
Electric Plant Leased To Others
(e)
Section A. Balances and Changes During Year
1 11,453,591,865 11,453,591,865
2 Depreciation Provisions for Year, Charged to
3 (a)1,023,482,570 1,023,482,570
4 (b)0 0
5
6
7
8
9.1 Other Accounts (Specify, details in footnote):
9.2 Account 143, Other accounts receivable: depreciation
expense billed to joint owners 266,843 266,843
9.3 Account 182.3, Other Regulatory Assets: asset retirement
obligations asset depreciation 25,256,353 25,256,353
9.4 Account 182.3, Other Regulatory Assets: depreciation
deferrals 2,257,801 2,257,801
9.5 Transportation depreciation allocated to operations and
maintenance expense based on usage activity 24,646,729 24,646,729
9.6 Account 503, Steam from other sources: Blundell
depreciation 2,503,933 2,503,933
10 1,078,414,229 1,078,414,229
11 Net Charges for Plant Retired:
12 (313,833,798)(313,833,798)
13 (69,069,501)(69,069,501)
14 5,881,596 5,881,596
15 (377,021,703)(377,021,703)
16
17.1 Other Debit or Cr. Items (Describe, details in footnote):
17.2 Close out of cost of removal activities associated with asset
retirement obligations 495,349 495,349
17.3 Other items include:12,313,579 12,313,579
17.4 Recovery from third parties for asset relocations and
damaged property
17.5 Insurance recoveries
17.6 Adjustments of reserve related to electric plant sold and/or
purchased
17.7 Reclassifications from electric plant
18 (161,978)(161,978)
19 12,167,631,341 (c)12,167,631,341
Section B. Balances at End of Year According to Functional Classification
20 4,755,324,162 (d)4,755,324,162
21
22 466,792,292 (e)466,792,292
23
24 763,732,700 (f)763,732,700
25 2,258,806,541 (g)2,258,806,541
Balance Beginning of Year
(403) Depreciation Expense
(403.1) Depreciation Expense for Asset Retirement Costs
(413) Exp. of Elec. Plt. Leas. to Others
Transportation Expenses-Clearing
Other Clearing Accounts
Other Accounts (Specify, details in footnote):
TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)
Book Cost of Plant Retired
Cost of Removal
Salvage (Credit)
TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru
14)
Other Debit or Cr. Items (Describe, details in footnote):
Book Cost or Asset Retirement Costs Retired
Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and
18)
Steam Production
Nuclear Production
Hydraulic Production-Conventional
Hydraulic Production-Pumped Storage
Other Production
Transmission
26 3,343,822,119 (h)3,343,822,119
27
28 579,153,527 (i)579,153,527
29 12,167,631,341 (j)12,167,631,341
FERC FORM No. 1 (REV. 12-05)
Page 219
Distribution
Regional Transmission and Market Operation
General
TOTAL (Enter Total of lines 20 thru 28)
FOOTNOTE DATA
(a) Concept: DepreciationExpenseExcludingAdjustments
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.
(b) Concept: DepreciationExpenseForAssetRetirementCosts
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as a regulatory asset.
(c) Concept: AccumulatedProvisionForDepreciationOfElectricUtilityPlant
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item Ref. Line No.Electric Plant in Service
(a)(Column)(c)
Revised Steam Production $4,617,706,639
Nuclear Production 21 (c)—
Revised Hydraulic Production - Conventional 466,792,292
Hydraulic Production - Pumped Storage 23 (c)—
Revised Other Production 760,981,107
Revised Transmission 2,258,536,003
Revised Distribution 3,342,434,416
Regional Transmission and Market Operation 27 (c)—
Revised General 579,316,418
Revised TOTAL $12,025,766,875
Refer to footnote on page 219, line no. 20, column (c)
Refer to footnote on page 219, line no. 22, column (c)
Refer to footnote on page 219, line no. 24, column (c)
Refer to footnote on page 219, line no. 25, column (c)
Refer to footnote on page 219, line no. 26, column (c)
Refer to footnote on page 219, line no. 28, column (c)
(d) Concept: AccumulatedDepreciationSteamProduction
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item Ref. Line No.Electric Plant in Service
(a)(Column)(c)
Steam Production 20 (c)$4,755,324,162
Less: Asset retirement obligations related cost components 137,617,523
Revised Steam Production $4,617,706,639
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 suppoorting its proposed rates.
(e) Concept: AccumulatedDepreciationHydraulicProductionConventional
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item Ref. Line No.Electric Plant in Service
(a)(Column)(c)
Hydraulic Production - Conventional 22 (c)$466,792,292
Less: Asset retirement obligations related cost components —
Revised Hydraulic Production - Conventional $466,792,292
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 suppoorting its proposed rates.
(f) Concept: AccumulatedDepreciationOtherProduction
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item Ref. Line No.Electric Plant in Service
(a)(Column)(c)
Other Production 24 (c)$763,732,700
Less: Asset retirement obligations related cost components 2,751,593
Revised Other Production $760,981,107
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 suppoorting its proposed rates.
(g) Concept: AccumulatedDepreciationTransmission
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item Ref. Line No.Electric Plant in Service
(a)(Column)(c)
Transmission 25 (c)$2,258,806,541
Less: Asset retirement obligations related cost components 270,538
Revised Transmission $2,258,536,003
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 suppoorting its proposed rates.
(h) Concept: AccumulatedDepreciationDistribution
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item Ref. Line No.Electric Plant in Service
(a)(Column)(c)
Distribution 26 (c)$3,343,822,119
Less: Asset retirement obligations related cost components 1,387,703
Revised Distribution $3,342,434,416
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 suppoorting its proposed rates.
(i) Concept: AccumulatedDepreciationGeneral
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item Ref. Line No.Electric Plant in Service
(a)(Column)(c)
General 28 (c)$579,153,527
Less: Asset retirement obligations related cost components (162,891)
Revised General $579,316,418
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 suppoorting its proposed rates.
(j) Concept: AccumulatedProvisionForDepreciationOfElectricUtilityPlant
(1)
(2)
(3)
(4)
(5)
(6)
(1)
(2)
(3)
(4)
(5)
(6)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item Ref. Line No.Electric Plant in Service
(a)(Column)(c)
Revised Steam Production $4,617,706,639
Nuclear Production 21 (c)—
Revised Hydraulic Production - Conventional 466,792,292
Hydraulic Production - Pumped Storage 23 (c)—
Revised Other Production 760,981,107
Revised Transmission 2,258,536,003
Revised Distribution 3,342,434,416
Regional Transmission and Market Operation 27 (c)—
Revised General 579,316,418
Revised TOTAL $12,025,766,875
Refer to footnote on page 219, line no. 20, column (c)
Refer to footnote on page 219, line no. 22, column (c)
Refer to footnote on page 219, line no. 24, column (c)
Refer to footnote on page 219, line no. 25, column (c)
Refer to footnote on page 219, line no. 26, column (c)
Refer to footnote on page 219, line no. 28, column (c)
FERC FORM No. 1 (REV. 12-05)
Page 219
(1)
(2)
(3)
(4)
(5)
(6)
(1)
(2)
(3)
(4)
(5)
(6)
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
1. Report below investments in Account 123.1, Investments in Subsidiary Companies.
2. Provide a subheading for each company and list thereunder 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.
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 from investments, including such revenues from 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
different 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.
Line
No.(a)(b)(c)(d)(e)(f)
(g)(h)
1 (a)
Pacific Minerals, Inc. - Common Stock 12/10/1973 1 1
2 Pacific Minerals, Inc. - Paid-In-Capital 12/10/1973 47,960,000 47,960,000
3 Pacific Minerals, Inc. - Unappropriated
Undistributed Subsidiary Earnings 12/10/1973 71,583,348 18,612,390 90,195,738
4 Energy West Mining Company -
Common Stock 07/19/1990 1,000 1,000
5 Trapper Mining Inc. - Equity Contribution 12/29/1997 6,038,000 6,038,000
6 Trapper Mining Inc. - Unappropriated
Undistributed Subsidiary Earnings 12/29/1997 10,893,719 1,496,705 12,390,424
42 Total Cost of Account 123.1 $53,999,001 Total 136,476,068 20,109,095 156,585,163
FERC FORM No. 1 (ED. 12-89)
Page 224-225
Description of Investment Date Acquired Date of Maturity Amount of Investment
at Beginning of Year
Equity in Subsidiary
Earnings of Year
Revenues
for Year
Amount of
Investment
at End of
Year
Gain or
Loss from
Investment
Disposed
of
FOOTNOTE DATA
(a) Concept: DescriptionOfInvestmentsInSubsidiaryCompanies
Pacific Minerals, Inc. is a wholly owned subsidiary of PacifiCorp that holds a 66.67% ownership interest in Bridger Coal Company.
FERC FORM No. 1 (ED. 12-89)
Page 224-225
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
MATERIALS AND SUPPLIES
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.
Line
No.
Account
(a)
Balance Beginning of Year
(b)
Balance End of Year
(c)
Department or Departments which Use Material
(d)
1 Fuel Stock (Account 151)133,979,566 103,923,863 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)251,987,732 336,602,638 Electric
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)65,271,248 65,247,369 Electric
8 Transmission Plant (Estimated)1,327,748 1,657,571 Electric
9 Distribution Plant (Estimated)21,774,345 24,933,422 Electric
10 Regional Transmission and Market Operation Plant (Estimated)
11 Assigned to - Other (provide details in footnote)
12 TOTAL Account 154 (Enter Total of lines 5 thru 11)340,361,073 428,441,000
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
20 TOTAL Materials and Supplies 474,340,639 532,364,863
FERC FORM No. 1 (REV. 12-05)
Page 227
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
Allowances (Accounts 158.1 and 158.2)
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.
6. Report on Line 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 acquired 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 and 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.
Current Year Year One Year Two Year Three Future Years Totals
Line
No.(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)(l)(m)
1 Balance-Beginning of Year 1,471,108 156,645 156,647 156,646 4,060,862 6,001,908
2
3 Acquired During Year:
4 Issued (Less Withheld Allow)156,644 156,644
5 Returned by EPA
6
7
8 Purchases/Transfers:
9
10
11
12
13
14
15 Total
16
17 Relinquished During Year:
18 Charges to Account 509 17,299 17,299
19 Other:
20 Allowances Used
20.1 Allowances Used
20.2 Prior period adjustment 1,789 1,789
21 Cost of Sales/Transfers:
22
23
24
25
26
27
28 Total
29 Balance-End of Year 1,452,020 156,645 156,647 156,646 4,217,506 6,139,464
30
31 Sales:
32 Net Sales Proceeds(Assoc. Co.)
33 Net Sales Proceeds (Other)
34 Gains
35 Losses
Allowances Withheld (Acct 158.2)
36 Balance-Beginning of Year 2,259 2,259 2,259 2,259 110,921 119,957
37 Add: Withheld by EPA 4,528 4,528
SO2 Allowances Inventory
(Account 158.1)No.Amt.No.Amt.No.Amt.No.Amt.No.Amt.No.Amt.
38 Deduct: Returned by EPA
39 Cost of Sales 2,259 2,269 4,528
40 Balance-End of Year 2,259 2,259 2,259 113,180 119,957
41
42 Sales
43 Net Sales Proceeds (Assoc. Co.)
44 Net Sales Proceeds (Other)
45 Gains
46 Losses
FERC FORM No. 1 (ED. 12-95)
Page 228(ab)-229(ab)a
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
Allowances (Accounts 158.1 and 158.2)
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.
6. Report on Line 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 acquired 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 and 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.
Current Year Year One Year Two Year Three Future
Years Totals
Line
No.(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)(l)(m)
1 Balance-Beginning of Year
2
3 Acquired During Year:
4 Issued (Less Withheld Allow)
5 Returned by EPA
6
7
8
9
10
11
12
13
14
15 Total
16
17 Relinquished During Year:
18 Charges to Account 509
19 Other:
20 Allowances Used
20.1 Allowances Used
21 Cost of Sales/Transfers:
22
23
24
25
26
27
28 Total
29 Balance-End of Year
30
31 Sales:
32 Net Sales Proceeds(Assoc. Co.)
33 Net Sales Proceeds (Other)
34 Gains
35 Losses
Allowances Withheld (Acct 158.2)
36 Balance-Beginning of Year
37 Add: Withheld by EPA
NOx Allowances Inventory (Account
158.1)No.Amt.No.Amt.No.Amt.No.Amt.No.Amt.No.Amt.
38 Deduct: Returned by EPA
39 Cost of Sales
40 Balance-End of Year
41
42 Sales
43 Net Sales Proceeds (Assoc. Co.)
44 Net Sales Proceeds (Other)
45 Gains
46 Losses
FERC FORM No. 1 (ED. 12-95)
Page 228(ab)-229(ab)b
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
WRITTEN OFF DURING YEAR
Line
No.
(a)
(b)(c)(d)(e)(f)
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
20 TOTAL
FERC FORM No. 1 (ED. 12-88)
Page 230a
Description of Extraordinary Loss [Include in the
description the date of Commission
Authorization to use Acc 182.1 and period of
amortization (mo, yr to mo, yr).]
Total Amount of Loss Losses Recognized During
Year Account Charged Amount Balance at End of Year
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
WRITTEN OFF DURING YEAR
Line
No.
(a)
(b)(c)(d)(e)(f)
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 TOTAL
FERC FORM No. 1 (ED. 12-88)
Page 230b
Description of Unrecovered Plant and Regulatory
Study Costs [Include in the description of costs,
the date of COmmission Authorization to use Acc
182.2 and period of amortization (mo, yr to mo,
yr)]
Total Amount of Charges Costs Recognized During
Year Account Charged Amount Balance at End of Year
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
Transmission Service and Generation Interconnection Study Costs
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.
Line
No.(a)(b)(c)(d)(e)
1 Transmission Studies
2 Q3134-A 508 561.6 508 456
3 Q3088-A 1,600 561.6
4 Q3170 497 561.6
5 Q3165-A 3,353 561.6
6 Q3049 104 561.6 104 456
7 Q3116 1,154 561.6 1,154 456
8 Q3204 4,792 561.6 4,792 456
9 Q3134-B 4,102 561.6 4,102 456
10 Q3217 449 561.6 449 456
11 Q3222 62 561.6 62 456
12 Q3223 198 561.6 198 456
13 Q3245 6,793 561.6 6,793 456
14 Q3246 5,572 561.6 5,572 456
15 Q3247 3,380 561.6 3,380 456
16 Q3218-A 3,136 561.6
17 Q3248-A 260 561.6
18 Q3221 215 561.6 215 456
19 Q3218-B 5,336 561.6
20 Q3249 3,276 561.6
21 Q3252 3,954 561.6
22 Q3265 114 561.6
23 Q3088-B 295 561.6
24 Q3089 555 561.6
25 Q3270-A 4,018 561.6 4,018 456
26 Q3271 2,127 561.6 2,127 456
27 Q3272 2,016 561.6 2,016 456
28 Q3248-B 7,317 561.6
29 Q3283 2,814 561.6
30 Q3284 3,275 561.6
31 Q3281-A 2,266 561.6
32 Q3143-A 5,398 561.6
33 Q3090 419 561.6
34 Q3290 3,142 561.6
35 Q3278 3,005 561.6
36 Q3279 2,891 561.6
37 Q3292 2,682 561.6
38 Q3293 690 561.6
39 Q3320-A 2,526 561.6
40 Q3319 2,526 561.6
41 Q3321 716 561.6
42 Q3301 2,844 561.6
43 Q3300 1,177 561.6
Description Costs Incurred During Period Account Charged Reimbursements Received During
the Period
Account Credited With
Reimbursement
44 Q3314 4,368 561.6
45 Q3331 5,804 561.6
46 Q3270-B 8,096 561.6 8,096 456
47 Q3325 4,197 561.6
48 Q3281-B 6,372 561.6
49 Q3334 6,123 561.6
50 Q3143-B 5,376 561.6
51 Q3332-A 5,506 561.6 5,506 456
52 Q3335 2,393 561.6
53 Q3344 532 561.6
54 Q3320-B 4,288 561.6
55 Q3357 591 561.6
56 Q3332-B 125 561.6 125 456
57 Q3368 125 561.6 125 456
58 Q3376 91 561.6 91 456
59 Q3375 170 561.6
60 Q3373 125 561.6
61 Q3374 125 561.6
62 Q3165-B 3,345 561.6
20 Total 159,306 49,433
21 Generation Studies
22 GIQ0847 84 561.7 84 456
23 GIQ1066 1,421 561.7 1,421 456
24 GIQ1067 1,421 561.7 1,421 456
25 GIQ1115 1,170 561.7 1,170 456
26 GIQ1122 584 561.7 584 456
27 GIQ1141 502 561.7 502 456
28 GIQ1142 502 561.7 502 456
29 GIQ1149 338 561.7 338 456
30 GIQ1150 129 561.7 129 456
31 GIQ1151 129 561.7 129 456
32 GIQ0907 42 561.7 42 456
33 GIQ0985 1,707 561.7 1,707 456
34 GIQ0558 261 561.7
35 ISGIQ0012 654 561.7 654 456
36 LGIQ0838 529 561.7 529 456
37 LGIQ0836 46 561.7 46 456
38 LGIQ0906 42 561.7 42 456
39 LGIQ1065 2,274 561.7 2,274 456
40 LGIQ1159 1,492 561.7 1,492 456
41 LGIQ0787 318 561.7 318 456
42 LGIQ0016 23,306 561.7 23,306 456
43 LGIQ1161 944 561.7 944 456
44 LGIQ1162 798 561.7 798 456
45 LGIQ1163 775 561.7 775 456
46 OCSGIQ0048 45 561.7 45 456
47 OCSGIQ0062 42 561.7 42 456
48 OCSGIQ0063 42 561.7 42 456
49 OCSGIQ0080 1,886 561.7 1,886 456
50 OCSGIQ0081 6,196 561.7 6,196 456
51 OCSGIQ0082 1,874 561.7 1,874 456
52 OGIQ1214 503 561.7 503 456
53 OCS0081 583 561.7 583 456
54 OCS0088 418 561.7 418 456
55 OCS0089 439 561.7 439 456
56 OCS0090 439 561.7 439 456
57 OCS0086 293 561.7 293 456
58 OCS0091 418 561.7 418 456
59 OCS0087 627 561.7 627 456
60 OCS0084 396 561.7 396 456
61 OCS0085 500 561.7 500 456
62 PIS029 8,165 561.7 8,165 456
63 PIS005 2,481 561.7
64 PIS009 4,417 561.7
65 PIS011 11,978 561.7
66 PIS012 4,249 561.7
67 PIS019 2,075 561.7
68 PIS0022 5,651 561.7 5,651 456
69 PIS0023 4,830 561.7 4,830 456
70 PIS0024 3,009 561.7 3,009 456
71 PIS0025 2,695 561.7 2,695 456
72 PIS0026 3,192 561.7 3,192 456
73 PIS0027 3,902 561.7 3,902
74 SGIQ1205 1,383 561.7 1,383 456
75 SGIQ1206 1,197 561.7 1,197 456
76 SIS002 2,217 561.7
77 SIS003 4,624 561.7
78 SIS004 2,455 561.7
79 SIS005 3,515 561.7
80 SIS006 3,267 561.7
81 SIS0007 2,220 561.7 2,220 456
82 SIS0008 2,305 561.7 2,305 456
83 SIS0009 1,352 561.7 1,352 456
84 SIS0010 1,570 561.7 1,570 456
85 SIS0011 1,674 561.7 1,674 456
86 SIS0012 1,789 561.7 1,789 456
87 SIS0013 1,670 561.7 1,670 456
88 SIS0014 6,224 561.7 6,224 456
89 SIS0015 7,451 561.7 7,451 456
90 SIS0016 5,369 561.7 5,369 456
91 SIS0017 5,339 561.7 5,339 456
92 SIS0018 4,352 561.7 4,352 456
93 SIS0019 290 561.7 290 456
94 SIS0020 863 561.7 863 456
95 SIS0021 1,137 561.7 1,137 456
96 S0022 274 561.7 274 456
97 S0023 236 561.7 236 456
98 S0024 236 561.7 236 456
99 C0012 167 561.7 167 456
100 C0011 251 561.7 251 456
101 C0013 84 561.7 84 456
102 C0014 251 561.7 251 456
103 C0015 334 561.7 334 456
104 C0016 334 561.7 334 456
105 C0020 836 561.7 836 456
106 C1-04 166 561.7 166 456
107 C1-10 1,857 561.7 1,857 456
108 C1-11 1,397 561.7 1,397 456
109 C1-13 377 561.7 377 456
110 C1-14 1,931 561.7 1,931 456
111 C1-16 1,230 561.7 1,230 456
112 C1-20 42 561.7 42 456
113 C1-23 3,163 561.7 3,163 456
114 C1-26 1,981 561.7 1,981 456
115 C1-27 482 561.7 482 456
116 C1-34 602 561.7 602 456
117 C1-35 1,514 561.7 1,514 456
118 C1-37 440 561.7 440 456
119 C1-39 1,282 561.7 1,282 456
120 C1-40 1,192 561.7 1,192 456
121 C1-43 -A 91 561.7 91 456
122 C1-43 -B 293 561.7 293 456
123 C1-44 251 561.7 251 456
124 C1-46 1,696 561.7 1,696 456
125 C1-50 2,259 561.7 2,259 456
126 C1-51 1,242 561.7 1,242 456
127 C1-54 2,036 561.7 2,036 456
128 C1-58 166 561.7 166 456
129 C2-10 -A 471 561.7 471 456
130 C2-10 -B 84 561.7 84 456
131 C2-11 84 561.7
132 C2-28 512 561.7 512 456
133 C2-31 642 561.7 642 456
134 C2-45 654 561.7 654 456
135 C2-54 771 561.7 771 456
136 C2-65 512 561.7 512 456
137 C2-79 554 561.7 554 456
138 C2-83 345 561.7 345 456
139 C2-86 376 561.7 376 456
140 C2-88 376 561.7 376 456
141 C2-91 502 561.7 502 456
142 C2-92 502 561.7 502 456
143 C2-101 581 561.7 581 456
144 C2-120 1,541 561.7 1,541 456
145 C2-138 429 561.7 429 456
146 C2-144 -A 209 561.7 209 456
147 C2-144 -B 2,571 561.7 2,571 456
148 C2-145 42 561.7 42 456
149 C2-156 376 561.7 376 456
150 C2-164 429 561.7 429 456
151 C2-169 429 561.7
152 C2-170 854 561.7 854 456
153 C2-171 771 561.7 771 456
154 C2-173 854 561.7 854 456
155 C2-179 84 561.7 84 456
156 C2-180 813 561.7 813 456
157 C2-181 813 561.7 813 456
158 C2-182 896 561.7 896 456
159 C2-187 813 561.7 813 456
160 C2-208 729 561.7 729 456
161 C2-209 1,487 561.7 1,487 456
162 C2-210 729 561.7 729 456
163 FT002 2,505 561.7 2,505 456
164 FT003 2,414 561.7 2,414 456
165 FT004 306 561.7 306 456
166 FT005 1,187 561.7 1,187 456
167 FT007 1,398 561.7 1,398 456
168 OATT Cluster Study 2021 -A (832)561.7 (832)456
169 OATT Cluster Study 2021 -B (5,625)561.7 (5,625)456
170 OATT Cluster Study CY2022 1,687 561.7 1,687 456
171 Cluster 2021 - Cluster Area 7 Restudy 4,730 561.7 4,730 456
172 2022 Cluster Study Report Production 192,334 561.7 192,334 456
173 2023 Cluster Study Applications C3APPS 147,801 561.7 147,801 456
174 Cluster 1 Restudy Area 6 3,539 561.7 3,539 456
175 Cluster 2 Cluster Area 1 Restudy C2REA1 7,366 561.7 7,366 456
176 Cluster 2 Cluster Area 2 Restudy C2REA2 4,448 561.7 4,448 456
177 Cluster 2 Cluster Area 4 Restudy C2REA4 6,446 561.7 6,446 456
178 Cluster 2 Cluster Area 6 Restudy C2REA6 11,702 561.7 11,702 456
179 Cluster 2 Cluster Area 7 Restudy C2REA7 20,206 561.7 20,206 456
180 Cluster 2 Cluster Area 9 Restudy C2REA9 30,420 561.7 30,420 456
181 Cluster2 Cluster Area 12 Restudy C2REA12 11,933 561.7 11,933 456
182 Cluster2 Cluster Area 13 Restudy C2REA13 8,885 561.7 8,885 456
183 Cluster2 Cluster Area 14 Restudy C2REA14 15,434 561.7 15,434 456
184 Cluster2 Cluster Area 15 Restudy C2REA15 19,273 561.7 19,273 456
185 Cluster2 Cluster Area 16 Restudy C2REA16 33,632 561.7 33,632 456
186 Cluster2 Cluster Area 18 Restudy C2REA18 24,772 561.7 24,772 456
187 Cluster2 Cluster Area 19 Restudy C2REA19 1,195 561.7 1,195 456
188 Cluster2 Cluster Area 20 Restudy C2REA20 116,667 561.7 116,667 456
189 Cluster2 Cluster Area 24 Restudy C2REA24 6,806 561.7 6,806 456
190 C2 Cluster Area 7 Restudy 2 C2REA7.2 251 561.7 251 456
191 C2 Cluster Area 8 Restudy C2REA8 4,424 561.7 4,424 456
192 C2 Cluster Area 9 Restudy 2 C2REA9.2 376 561.7 376 456
193 C2 Cluster Area 14 Restudy 2 C2REA14.2 84 561.7 84 456
194 C2 Cluster Area 16 Restudy 2 C2REA16.2 84 561.7 84 456
195 Cluster 3 Study Report Production C3RP -A 285,865 561.7
196 Cluster 3 Study Report Production C3RP -B 714,212 561.7 714,212 456
197 ESM Cluster 1 Study Costs 6,457 561.7
198 ESM Cluster Study 2 -A 75,778 561.7
199 ESM Cluster Study 2 -B 376,049 561.7
200 ESM Gen Clearing Order 439 561.7
201 Pre-Application Studies - East 4,240 561.7 4,240 456
202 Pre-Application Studies - West 10,408 561.7 10,408 456
203 Adjustment (501)561.7 (502)456
39 Total 2,372,399 1,585,758
40 Grand Total 2,531,705 1,635,191
FERC FORM No. 1 (NEW. 03-07)
Page 231
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
OTHER REGULATORY ASSETS (Account 182.3)
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.
CREDITS
Line
No.(a)(b)(c)
(d)(e)(f)
1 (a)
DSM Balancing Account - CA 72,243 908 72,243
2 (b)
DSM Balancing Account - ID 6,197,273 908, 431 5,645,928 551,345
3 (c)
DSM Balancing Account - UT 205,469,306 56,385,536 908 38,275,913 223,578,929
4 (d)
DSM Balancing Account - WY 18,159,809 9,063,927 908 6,107,558 21,116,178
5 (e)
DSM Balancing Account - OR 478,923 1,443,432 908 1,901,046 21,309
6 (f)
Deferred Excess Net Power Costs - CA 8,390,726 12,832,349 555 2,066,078 19,156,997
7 (g)
Deferred Excess Net Power Costs - ID 43,831,371 62,288,769 555 35,381,308 70,738,832
8 (h)
Deferred Excess Net Power Costs - OR 117,382,439 156,271,229 555 9,929,695 263,723,973
9 (i)
Deferred Excess Net Power Costs - UT 208,726,409 502,263,195 555 249,827,460 461,162,144
10 (j)
Deferred Excess Net Power Costs - WA 83,141,122 83,342,631 555 14,880,110 151,603,643
11 (k)
Deferred Excess Net Power Costs - WY 84,484,984 111,341,265 555 44,985,383 150,840,866
12 Deferred Excess RECs in Rates - WY 891,469 891,469
13 (l)
Deferred Excess RECs in Rates - UT 2,157,675 456 673,510 1,484,165
14 (m)
Decoupling Mechanism - WA 7,019,150 254, 440, 442 7,019,150
15 Solar Investment Tax Credit Basis Adjustment 377,951 5,734 282, 283 30,786 352,899
16 Metro Business Income Tax - OR 19,451 229 410.1 19,415 265
17 (n)
Pension 289,710,820 (au)11,035,158 278,675,662
18 (o)
Other Postretirement 736,873 439,321 926 (av)1,002,544 173,650
19 Deferred Steam Depreciation - UT 9,820,585 5,001,095 14,821,680
20 Colstrip Unit No. 4 Deferred Maintenance Costs - WA 258,904 258,904
21 (p)
Carbon Plant Inventory 840,508 407.3 415,756 424,752
22 Carbon Plant Inventory - CA (Amortization period: 3
years, starting 02/2020)28,824 407.3 28,824
23 Cholla Unit No. 4 Closure Costs - CA 4,471,792 215,552 440, 442, 444 965,748 3,721,596
24 Cholla Unit No. 4 Closure Costs - ID (35,512)407.3 21,231 (56,743)
25 (q)
Cholla Unit No. 4 Closure Costs - OR 482,896 669,159 920, 931, 408.1 (aw)398,665 753,390
26 Cholla Unit No. 4 Closure Costs - UT (Amortization
period: 4.4 years, starting 01/2021)5,682,655 407.3 2,663,830 3,018,825
27 Cholla Unit No. 4 Closure Costs - WY (Amortization
period: 11 years, starting 07/2021)39,700,940 358,830 407.3 4,176,328 35,883,442
28 Cholla Unit No. 4 Decommissioning Costs - CA 73,635 67,993 182.3, 426.5 123,740 17,888
29 Depreciation Study Deferral - ID (Amortization
period: 4 years, starting 01/2022)10,455,227 403 3,485,076 6,970,151
30 Depreciation Study Deferral - UT (Amortization
period: 17 years, starting 09/2014)1,088,367 403 128,042 960,325
31 Depreciation Study Deferral - WY (Amortization
period: 18 years, starting 01/2014)3,758,622 403 442,189 3,316,433
32 Generating Plant Liquidated Damages - UT
(Amortization period: 20 years, starting 01/2014)385,000 557 35,000 350,000
33 (r)
Generating Plant Liquidated Damages - WY 972,973 557 54,289 918,684
34 Wind Test Energy Deferral - WY (Amortization
period: 30 years, starting 12/2020)213,387 557 7,643 205,744
35 (s)
Environmental Costs 110,586,204 37,023,439 514, 545, 554, 598,
935 (ax)8,361,689 139,247,954
Description and Purpose of Other Regulatory
Assets
Balance at Beginning of
Current Quarter/Year Debits
Written off During
Quarter/Year
Account Charged
Written off During the
Period Amount
Balance at end of Current
Quarter/Year
36 (t)
Asset Retirement Obligations Regulatory Difference 205,960,894 37,037,978 230, 426.5 11,224,745 231,774,127
37 (u)
Unamortized Contract Values 18,314,273 242, 253 18,314,273
38 Unrealized Loss on Derivative Contracts 76,083,981 76,083,981
39 (v)
Greenhouse Gas Allowance Revenues - CA 24,073,719 456 20,059,374 4,014,345
40 (w)
Greenhouse Gas Allowance Compliance Costs - CA 5,468,275 15,409,803 419, 555 18,635,769 2,242,309
41 Emergency Service Resiliency Program - CA 6,104 343 6,447
42 (x)
Solar Feed-In Tariff Deferral - OR 4,233,222 4,460,567 555, 908 5,462,835 3,230,954
43 (y)
Oregon Community Solar Program 2,707,233 1,066,581 908 889,063 2,884,751
44 (z)
Solar Incentive Subscriber Program - UT 1,866,628 159,436 908 181,840 1,844,224
45 (aa)
Solar Incentive Program - UT 163,009 440, 442, 444, 431 16,872 146,137
46 (ab)
STEP Pilot Program - UT 1,758,413 447, 451, 598 1,118,508 639,905
47 (ac)
Renewable Portfolio Standards Compliance - OR 846,067 555 701,486 144,581
48 (ad)
Renewable Portfolio Standards Compliance - WA 459,668 555 459,668
49 Deferred Intervenor Funding Grants - CA 404,712 146,829 182.3 130,962 420,579
50 Deferred Intervenor Funding Grants - ID 40,000 40,000
51 Deferred Intervenor Funding Grants - OR
(Amortization period: 1 year, starting 07/2023)3,028,580 778,515 928 1,118,762 2,688,333
52 Deferred Intervenor Funding Grants - WA 300,000 300,000
53 Deferred Independent Evaluator Costs - OR 40,761 86,078 126,839
54 Deferred Independent Evaluator Costs - UT 99,740 131 99,740
55 Catastrophic Event - CA 38,692 21,217,314 228.1, 924 481,918 20,774,088
56 Low Income Program - WA 1,818,886 555,469 2,374,355
57 (ae)
Deferred Overburden Cost - ID 459,306 2,150,282 501 2,210,875 398,713
58 (af)
Deferred Overburden Cost - WY 1,130,023 5,265,566 501 5,419,106 976,483
59 BPA Balancing Account - WA 767,714 1,224,604 1,992,318
60 (ag)
BPA Balancing Account - OR 887,360 143 774,760 112,600
61 BPA Balancing Account - ID 1,007,862 333,711 1,341,573
62 Property Sales Balancing Account - OR
(Amortization period: 1 year, starting 07/2023)2,844,651 424,462 421.1, 440, 442,
444 1,419,663 1,849,450
63 (ah)
Property Damage - OR 32,194,780 8,954,932 924 13,000,573 28,149,139
64 (ai)
Property Damage - WA 503,158 1,028,449 924 1,144,819 386,788
65 Property Damage - CA 1,334,868 1,260,656 2,595,524
66 (aj)
Property Damage - UT 3,333,458 924 1,116,441 2,217,017
67 (ak)
Property Damage - WY 956,603 924 949,848 6,755
68 (al)
Miscellaneous Regulatory Assets and Liabilities - OR 458,802 24,030 142 2,137 480,695
69 (am)
Utah Mine Disposition 115,058,238 684,645 234, 506 36,576,859 79,166,024
70 Preferred Stock Redemption Loss - UT (Amortization
period: 10 years, starting 03/2014)99,725 407.3 82,531 17,194
71 Preferred Stock Redemption Loss - WA (Amortization
period: 10 years, starting 03/2014)15,537 407.3 13,318 2,219
72 Preferred Stock Redemption Loss - WY
(Amortization period: 10 years, starting 03/2014)34,366 407.3 28,442 5,924
73 Mobile Home Park Conversion - CA (Amortization
period: 10 years, starting 05/2020)206,797 15,136 407.3 32,508 189,425
74 Transportation Electrification Program - OR
(Amortization period: 3 years, starting 04/2023)606,797 2,390,125 908 697,474 2,299,448
75 Transportation Electrification Program - WA 791,532 216,663 1,008,195
76 Fire Hazard and Wildfire Mitigation Plan - CA 34,606,418 4,425,848 39,032,266
77
(an)
Wildfire Mitigation and Vegetation Management
Plans - OR 70,046,726 25,850,924 593 25,885,856 70,011,794
78 Wildfire Damaged Plant Net Book Value - OR 1,812,052 2,221 108 70,548 1,743,725
79 Wildfire Natural Disaster Plan - CA 83,417 5,051 88,468
80 (ao)
Wildland Fire Mitigation Balancing Account - UT 4,830,807 468,789 590 1,970,773 3,328,823
81 AMI Replaced Meters - OR (Amortization period: 5
years, starting 01/2021)11,353,971 406,894 407.3 3,964,506 7,796,359
82 COVID-19 Bill Assistance Program - OR
(Amortization period: 4 years, starting 04/2023)12,480,133 595,590 908 3,315,833 9,759,890
83 COVID-19 Bill Assistance Program - WA 3,101,326 3,101,326
84 Equity Advisory Group for Clean Energy
Implementation Plan - WA 916,270 346,311 1,262,581
85 (ap)
Low-Carbon Energy Standards - WY 581,607 440, 442, 444 581,607
86 (aq)
Low Income Bill Discount Admin Cost - OR 394,588 11,737,643 142 4,669,284 7,462,947
87 (ar)
Utility Community Advisory Group - OR 84,451 394,643 142 416,053 63,041
88 Distribution System Plan - OR 994,544 1,213,781 2,208,325
89 TB Flats - OR (Amortization period: 3 years, starting
04/2023)6,040,426 2,264,279 403, 431 4,576,556 3,728,149
90 (as)
Arrearage Payment Program - CA 227,343 254 227,343
91 Klamath Unrecovered Plant Net Book Value
(Amortization period: 5 years, starting 12/2022)5,948,649 407.3 1,218,154 4,730,495
92 Alternative Rate For Energy (CARE) - CA 616,721 616,721
93 (at)
Utility Bill Assistance - UT 1,789,765 142, 232, 440, 442,
444 1,284,526 505,239
94 2023 GRC Memo Account - CA 16,511,539 16,511,539
44 TOTAL 1,807,229,847 1,333,246,174 640,707,543 2,499,768,478
FERC FORM No. 1 (REV. 02-04)
Page 232
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(b) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(c) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately 10 years.
(d) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately 10 years.
(e) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(f) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately one year.
(g) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately one year.
(h) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately four years.
(i) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately one year.
(j) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately one year.
(k) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately one year.
(l) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately one year.
(m) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(n) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately 17 years. Substantially represents amounts not yet recognized as a component of net periodic benefit cost.
(o) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period of portion being amortized is approximately 13 years. Substantially represents amounts not yet recognized as a component of net periodic benefit cost.
(p) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining amortization period is approximately two years.
(q) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining amortization period is approximately two years.
(r) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately 20 years.
(s) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately 10 years.
(t) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(u) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately one year. Represents frozen values of contracts previously accounted for as derivatives and recorded at fair value.
(v) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(w) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(x) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately one year.
(y) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(z) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(aa) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately one year.
(ab) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately one year.
(ac) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately one year.
(ad) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately three years.
(ae) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(af) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(ag) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(ah) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(ai) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(aj) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(ak) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(al) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(am) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
$67 million is related to withdrawal from the 1974 UMWA Pension Trust and is indefinite-lived, while the remainder is associated with other closure costs and has an average remaining amortization period of one year.
(an) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average amortization period is approximately one year.
(ao) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(ap) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(aq) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(ar) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(as) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(at) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Amortization period varies depending on timing of underlying transactions.
(au) Concept: OtherRegulatoryAssetsWrittenOffRecovered
Pension costs are associated with labor and generally charged to operations and maintenance expense and construction work in progress. Pension curtailments, remeasurement data changes and settlement charges are charged
to Account 926, Employee pensions and benefits and Account 228.3, Accumulated provision for pensions and benefits.
(av) Concept: OtherRegulatoryAssetsWrittenOffRecovered
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, 2023, other postretirement regulatory asset amortization of
$1,002,544 was charged to Acount 926.
(aw) Concept: OtherRegulatoryAssetsWrittenOffRecovered
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, 2023, regulatory asset amortization associated with
Oregon's share of Cholla Unit No. 4 closure costs of $234,016 was charged to Acount 920 and $9,837 was charged to Account 931.
(ax) Concept: OtherRegulatoryAssetsWrittenOffRecovered
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, 2023, environmental cost regulatory asset amortization of
$149,082 was charged to Acount 935.
FERC FORM No. 1 (REV. 02-04)
Page 232
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
MISCELLANEOUS DEFFERED DEBITS (Account 186)
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.
CREDITS
Line
No.
Description of Miscellaneous Deferred Debits
(a)
Balance at Beginning of
Year
(b)
Debits
(c)
Credits Account
Charged
(d)
Credits Amount
(e)
Balance at End of Year
(f)
1 Bogus Creek (41)705,200 557 41,280 663,920
2 Point-to-Point Transmission Reservation Deposits 3,957,523 7,782,898 131 4,471,174 7,269,247
3 Hermiston Swap (40)2,332,165 557 171,693 2,160,472
4 Long-Term Lease Commissions Prepaids 1,116 589 1,116
5 Lake Side Maintenance Prepaid 21,378,653 6,882,275 28,260,928
6 Lake Side 2 Maintenance Prepaid 29,816,376 5,997,983 107 34,744,623 1,069,736
7 Chehalis Maintenance Prepaid 9,538,688 5,452,623 14,991,311
8 Currant Creek Maint. Prepaid 7,612,833 7,090,182 14,703,015
9 Seven Mile Hill Maintenance Prepaid 3,818,370 1,359,871 107 443,963 4,734,278
10 Seven Mile Hill II Maintenance Prepaid 875,418 267,854 107 40,215 1,103,057
11 Dunlap Ranch I Maintenance Prepaid 3,769,646 1,524,703 107 104,519 5,189,830
12 Ekola Flats Maintenance Prepaid 2,990,768 1,618,961 107 211,109 4,398,620
13 Foote Creek Maintenance Prepaid 784,853 457,335 107 102,260 1,139,928
14 Glenrock I Maintenance Prepaid 3,781,344 1,275,303 107 596,436 4,460,211
15 Glenrock III Maintenance Prepaid 1,599,312 267,853 107 232,433 1,634,732
16 Goodnoe Hills Maintenance Prepaid 3,179,343 1,131,653 107 130,110 4,180,886
17 High Plains Maintenance Prepaid 3,585,742 679,935 107 603,103 3,662,574
18 Leaning Juniper Maintenance Prepaid 4,202,344 1,380,475 107 800,749 4,782,070
19 Marengo Maintenance Prepaid 4,689,865 1,752,587 107 159,388 6,283,064
20 Marengo II Maintenance Prepaid 2,328,259 876,055 107 63,369 3,140,945
21 McFadden Ridge I Maintenance Prepaid 1,311,882 351,144 107 55,114 1,607,912
22 Pryor Mountain Maintenance Prepaid 4,564,978 2,686,833 107 1,133,666 6,118,145
23 Rolling Hills Maintenance Prepaid 4,110,703 1,250,850 107 1,073,592 4,287,961
24 TB Flats Maintenance Prepaid 4,589,494 3,296,764 107 6,875,991 1,010,267
25 (a)
Credit Agreement Costs 1,517,357 2,943,071 427, 431 853,372 3,607,056
26 (b)
PCRB Mode Conversion Costs 152,272 427 68,979 83,293
27 1994 Series Restructuring Costs (16)107,744 427 58,770 48,974
28 Deferred S-3 Shelf Registration Costs 41,596 41,596
29 Emission Reduction Credits 306,510 306,510
30 Sales of Electric Utility Facilities and Properties 61,240 770 62,010
31 IT Licenses and Maintenance Prepaid 108,487 34,494 107 142,981
32 Other Deferred Charges 552,500 131 552,500
47 Miscellaneous Work in Progress
48 Deferred Regulatory Comm. Expenses (See pages
350 - 351)
49 TOTAL 128,330,985 131,002,548
FERC FORM No. 1 (ED. 12-94)
Page 233
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionOfMiscellaneousDeferredDebits
The weighted average remaining life is approximately two years.
(b) Concept: DescriptionOfMiscellaneousDeferredDebits
The weighted average remaining life is approximately one year.
FERC FORM No. 1 (ED. 12-94)
Page 233
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
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.
Line
No.(a)(b)(c)
1 Electric
2 Employee Benefits 59,371,205 51,036,447
3 State Carryfowards 73,141,764 84,489,377
4 Asset Retirement Obligations 79,214,493 85,238,575
5 Regulatory Liabilities 421,123,607 311,486,543
6 Loss Contingencies 45,033,428 338,021,556
7 Other Electric 53,317,506 82,419,368
8 Valuation Allowances (35,417,465)(24,462,489)
7 Other
8 TOTAL Electric (Enter Total of lines 2 thru 7)695,784,538 928,229,377
9 Gas
15 Other
16 TOTAL Gas (Enter Total of lines 10 thru 15)
17.1 Other (Specify)
17 Other (Specify)
18 TOTAL (Acct 190) (Total of lines 8, 16 and 17)695,784,538 928,229,377
Notes
FERC FORM NO. 1 (ED. 12-88)
Page 234
Description and Location Balance at Beginning of Year Balance at End of Year
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
CAPITAL STOCKS (Account 201 and 204)
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.
3. Give 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 noncumulative.
5. State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year.
6. 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 purpose of pledge.
Line
No.
Class and Series of Stock
and Name of Stock Series
(a)
Number of Shares
Authorized by
Charter
(b)
Par or Stated
Value per Share
(c)
Call Price at End
of Year
(d)
Outstanding per
Bal. Sheet (Total
amount outstanding
without reduction
for amounts held by
respondent) Shares
(e)
Outstanding per
Bal. Sheet (Total
amount
outstanding
without reduction
for amounts held
by respondent)
Amount
(f)
Held by
Respondent
As
Reacquired
Stock (Acct
217) Shares
(g)
Held by
Respondent
As
Reacquired
Stock (Acct
217) Cost
(h)
Held by
Respondent
In Sinking
and Other
Funds
Shares
(i)
Held by
Respondent
In Sinking
and Other
Funds
Amount
(j)
1 Common Stock (Account 201)
2 (a)(b)(c)
Common Stock issued 750,000,000 357,060,915 3,417,945,896
6 Total 750,000,000 357,060,915 3,417,945,896
7 Preferred Stock (Account 204)
8 5% Cumulative Preferred 126,533 100.00
9 Serial Preferred, Cumulative:3,500,000
10 (d)
6.00% Series 100.00 5,930 593,000
11 (e)
7.00% Series 100.00 18,046 1,804,600
12 No Par Serial Preferred 16,000,000
28 Total 19,626,533 23,976 2,397,600
1 Capital Stock (Accounts 201
and 204) - Data Conversion
2
3
4
5 Total
FERC FORM NO. 1 (ED. 12-91)
Page 250-251
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: CapitalStockDescription
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.
(b) Concept: CapitalStockDescription
This class of stock is not redeemable.
(c) Concept: CapitalStockDescription
Authorized and Unissued Capital Stock: Authorizations for the issuance of common stock are as follows: (a) Idaho Public Utilities Commission - Case No. PAC-E-06-7, Order No. 30099, dated July 7, 2006; (b) Oregon Public
Utility Commission - Docket No. UF-4228, Order No. 06-417, dated July 17, 2006; and (c) 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.
(d) Concept: CapitalStockDescription
This series of preferred stock is not redeemable.
(e) Concept: CapitalStockDescription
This series of preferred stock is not redeemable.
FERC FORM NO. 1 (ED. 12-91)
Page 250-251
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
2024-04-11
Year/Period of Report
End of: 2023/ Q4
Other Paid-in Capital
1. 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
a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change.
Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation.
Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class
and series of stock to which related.
Gain or 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.
Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to
the reported amounts.
Line No.Item
(a)
Amount
(b)
1
2
3.1
4
5
6
7.1
8
9
10
11.1
12
13
14 (a)1,102,063,956
15
16 1,102,063,956
17
18
19.1
20
40 1,102,063,956
FERC FORM No. 1 (ED. 12-87)
Page 253
a.
b.
c.
d.
Donations Received from Stockholders (Account 208)
Beginning Balance Amount
Increases (Decreases) from Sales of Donations Received from Stockholders
Ending Balance Amount
Reduction in Par or Stated Value of Capital Stock (Account 209)
Beginning Balance Amount
Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
Ending Balance Amount
Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
Beginning Balance Amount
Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
Ending Balance Amount
Miscellaneous Paid-In Capital (Account 211)
Beginning Balance Amount
Increases (Decreases) Due to Miscellaneous Paid-In Capital
Ending Balance Amount
Historical Data - Other Paid in Capital
Beginning Balance Amount
Increases (Decreases) in Other Paid-In Capital
Ending Balance Amount
Total
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
2024-04-11
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: MiscellaneousPaidInCapital
Miscellaneous Paid-In Capital (Account 211):
Share based payments 1,973,218
Tax benefit from stock option exercises (2)14,422,979
Benefit plan separation (3,575,760)
Capital contributions (4)1,089,950,000
Gain on sale of ScottishPower plc stock 136,208
Qualified production activity tax deduction (1,275,241)
Contribution of Intermountain Geothermal Company (7)432,552
Total Miscellaneous Paid-In Capital (Account 211)1,102,063,956
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.
Represents the income tax deduction attributable to the exercise of stock options granted by ScottishPower plc.
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.
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.
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.
Represents amounts associated with Internal Revenue Code Section 199 qualified production activities.
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 its direct parent, PacifiCorp, on August 31, 2007, with PacifiCorp
surviving.
FERC FORM No. 1 (ED. 12-87)
Page 253
(1)
(3)
(5)
(6)
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
CAPITAL STOCK EXPENSE (Account 214)
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.
Line
No.(a)(b)
1 Common Stock 41,101,061
22 TOTAL 41,101,061
FERC FORM No. 1 (ED. 12-87)
Page 254b
Class and Series of Stock Balance at End of Year
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
LONG-TERM DEBT (Account 221, 222, 223 and 224)
1. Report by Balance Sheet Account the 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. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds, and in column (b) include the related account number.
3. 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, and in column (b) include the related account number.
4. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued, and in column (b) include the related account number.
5. In a supplemental statement, 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) principal repaid during year. Give Commission authorization numbers and dates.
6. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge.
7. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote.
8. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (m). Explain in a footnote any difference between the total of
column (m) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
9. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line
No.
(a)
(b)(c)
(d)
(e)(f)(g)(h)(i)(j)(k)
(l)
(m)
1 Bonds (Account
221)
2
First Mortgage
Bonds: 2.95%
Series due 2023
300,000,000 1,859,352 900,000 06/06/2013 06/01/2023 06/06/2013 06/01/2023 3,687,500
3
First Mortgage
Bonds: 3.60%
Series due 2024
425,000,000 3,345,164 255,000 03/13/2014 04/01/2024 03/13/2014 04/01/2024 425,000,000 15,300,000
4
First Mortgage
Bonds: 3.35%
Series due 2025
250,000,000 2,121,421 320,000 06/19/2015 07/01/2025 06/19/2015 07/01/2025 250,000,000 8,375,000
5
First Mortgage
Bonds: 3.50%
Series due 2029
400,000,000 2,134,659 740,000 03/01/2019 06/15/2029 03/01/2019 06/15/2029 400,000,000 14,000,000
6
First Mortgage
Bonds: 2.70%
Series due 2030
400,000,000 2,156,791 720,000 04/08/2020 09/15/2030 04/08/2020 09/15/2030 400,000,000 10,800,000
7
First Mortgage
Bonds: 7.70%
Series due 2031
300,000,000 2,874,150 864,000 11/21/2001 11/15/2031 11/21/2001 11/15/2031 300,000,000 23,100,000
8
First Mortgage
Bonds: 5.90%
Series due 2034
200,000,000 1,892,365 722,000 08/24/2004 08/15/2034 08/24/2004 08/15/2034 200,000,000 11,800,000
9
First Mortgage
Bonds: 5.25%
Series due 2035
300,000,000 2,912,021 1,080,000 06/13/2005 06/15/2035 06/13/2005 06/15/2035 300,000,000 15,750,000
10
First Mortgage
Bonds: 6.10%
Series due 2036
350,000,000 2,907,881 1,141,000 08/10/2006 08/01/2036 08/10/2006 08/01/2036 350,000,000 21,350,000
11
First Mortgage
Bonds: 5.75%
Series due 2037
600,000,000 589,216 24,000 03/14/2007 04/01/2037 03/14/2007 04/01/2037 600,000,000 34,500,000
12
First Mortgage
Bonds: 6.25%
Series due 2037
600,000,000 5,127,281 750,000 10/03/2007 10/15/2037 10/03/2007 10/15/2037 600,000,000 37,500,000
13
First Mortgage
Bonds: 6.35%
Series due 2038
300,000,000 2,290,333 1,671,000 07/17/2008 07/15/2038 07/17/2008 07/15/2038 300,000,000 19,050,000
14
First Mortgage
Bonds: 6.00%
Series due 2039
650,000,000 6,134,687 6,175,000 01/08/2009 01/15/2039 01/08/2009 01/15/2039 650,000,000 39,000,000
15
First Mortgage
Bonds: 4.10%
Series due 2042
300,000,000 2,737,911 987,000 01/06/2012 02/01/2042 01/06/2012 02/01/2042 300,000,000 12,300,000
16
First Mortgage
Bonds: 4.125%
Series due 2049
600,000,000 5,640,085 1,344,000 07/13/2018 01/15/2049 07/13/2018 01/15/2049 600,000,000 24,750,000
17
First Mortgage
Bonds: 4.15%
Series due 2050
600,000,000 5,149,489 2,790,000 03/01/2019 02/15/2050 03/01/2019 02/15/2050 600,000,000 24,900,000
18
First Mortgage
Bonds: 3.30%
Series due 2051
600,000,000 5,183,937 4,944,000 04/08/2020 03/15/2051 04/08/2020 03/15/2051 600,000,000 19,800,000
19
First Mortgage
Bonds: 2.90%
Series due 2052
1,000,000,000 8,390,124 7,670,000 07/09/2021 06/15/2052 07/09/2021 06/15/2052 1,000,000,000 29,000,000
Class and
Series of
Obligation,
Coupon Rate
(For new issue,
give
commission
Authorization
numbers and
dates)
Related
Account
Number
Principal
Amount of
Debt Issued
Total
Expense,
Premium
or
Discount
Total
Expense
Total
Premium
Total
Discount
Nominal
Date of
Issue
Date of
Maturity
AMORTIZATION
PERIOD Date
From
AMORTIZATION
PERIOD Date
To
Outstanding
(Total amount
outstanding
without
reduction for
amounts held
by
respondent)
Interest for
Year
Amount
20
First Mortgage
Bonds: 5.35%
Series due 2053
1,100,000,000 9,208,626 3,300,000 12/01/2022 12/01/2053 12/01/2022 12/01/2053 1,100,000,000 58,850,000
21
(a)
First Mortgage
Bonds: 5.50%
Series due 2054
1,200,000,000 9,133,192 528,000 05/17/2023 05/15/2054 05/17/2023 05/15/2054 1,200,000,000 41,066,667
22
Secured
Medium-Term
Notes: 8.23%
Series E due
2023 - A
5,000,000 37,914 01/20/1993 01/20/2023 01/20/1993 01/20/2023 21,718
23
Secured
Medium-Term
Notes: 8.23%
Series E due
2023 - B
4,000,000 30,331 (81,560)01/29/1993 01/20/2023 01/29/1993 01/20/2023 17,374
24
Secured
Medium-Term
Notes: 7.26%
Series F due
2023 - A
27,000,000 246,981 07/22/1993 07/21/2023 07/22/1993 07/21/2023 1,089,000
25
Secured
Medium-Term
Notes: 7.26%
Series F due
2023 - B
11,000,000 100,622 07/22/1993 07/21/2023 07/22/1993 07/21/2023 443,667
26
Secured
Medium-Term
Notes: 7.23%
Series F due
2023
15,000,000 137,211 08/16/1993 08/16/2023 08/16/1993 08/16/2023 677,813
27
Secured
Medium-Term
Notes: 7.24%
Series F due
2023
30,000,000 274,423 08/16/1993 08/16/2023 08/16/1993 08/16/2023 1,357,500
28
Secured
Medium-Term
Notes: 6.75%
Series F due
2023 - A
5,000,000 38,250 09/14/1993 09/14/2023 09/14/1993 09/14/2023 237,188
29
Secured
Medium-Term
Notes: 6.75%
Series F due
2023 - B
2,000,000 15,300 09/14/1993 09/14/2023 09/14/1993 09/14/2023 94,875
30
Secured
Medium-Term
Notes: 6.72%
Series F due
2023
2,000,000 15,300 09/14/1993 09/14/2023 09/14/1993 09/14/2023 94,453
31
Secured
Medium-Term
Notes: 6.75%
Series F due
2023 - C
20,000,000 152,326 10/26/1993 10/26/2023 10/26/1993 10/26/2023 1,106,250
32
Secured
Medium-Term
Notes: 6.75%
Series F due
2023 - D
16,000,000 121,861 10/26/1993 10/26/2023 10/26/1993 10/26/2023 885,000
33
Secured
Medium-Term
Notes: 6.75%
Series F due
2023 - E
12,000,000 91,396 10/26/1993 10/26/2023 10/26/1993 10/26/2023 663,750
34
Secured
Medium-Term
Notes: 6.71%
Series G due
2026
100,000,000 904,467 01/23/1996 01/15/2026 01/23/1996 01/15/2026 100,000,000 6,710,000
35
(b)
Pollution Control
Revenue
Refunding
Bonds -
Secured:
Sweetwater
County, WY,
Series 1994
21,260,000 510,479 11/17/1994 11/01/2024 11/17/1994 11/01/2024 21,260,000 864,741
36
(c)
Pollution Control
Revenue
Refunding
Bonds -
Secured:
Converse
County, WY,
Series 1994
8,190,000 209,777 11/17/1994 11/01/2024 11/17/1994 11/01/2024 8,190,000 329,552
37
(d)
Pollution Control
Revenue
Refunding
Bonds -
Secured: Emery
County, UT,
Series 1994
121,940,000 3,274,246 11/17/1994 11/01/2024 11/17/1994 11/01/2024 121,940,000 4,671,601
38
(e)
Pollution Control
Revenue
Refunding
Bonds -
Secured: Lincoln
County, WY,
Series 1994
15,060,000 422,858 11/17/1994 11/01/2024 11/17/1994 11/01/2024 15,060,000 622,546
39
(f)
Environment
Improvement
Revenue Bonds
- Secured:
Converse
County, WY,
Series 1995
5,300,000 132,043 11/17/1995 11/01/2025 11/17/1995 11/01/2025 5,300,000 207,437
40
(g)
Environment
Improvement
Revenue Bonds
- Secured:
Lincoln County,
WY, Series 1995
22,000,000 404,262 11/17/1995 11/01/2025 11/17/1995 11/01/2025 22,000,000 906,437
41
Environment
Improvement
Revenue Bonds
- Unsecured:
Sweetwater
County, WY,
Series 1995
24,400,000 225,000 12/14/1995 11/01/2025 12/14/1995 11/01/2025 24,400,000 923,354
42 Subtotal 10,942,150,000 89,133,732 (81,560)36,925,000 10,493,150,000 (h)
486,803,423
43
Reacquired
Bonds (Account
222)
44
45
46
47 Subtotal
48
Advances from
Associated
Companies
(Account 223)
49
50
51
52 Subtotal
53
Other Long Term
Debt (Account
224)
54
(i)
Long-term debt
authorized but
unissued
55 Subtotal
33 TOTAL 10,942,150,000 10,493,150,000 486,803,423
FERC FORM No. 1 (ED. 12-96)
Page 256-257
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: ClassAndSeriesOfObligationCouponRateDescription
In May 2023, PacifiCorp issued $1.2 billion of its 5.50% First Mortgage Bonds due May 2054. State authorizations for this issuance were as follows: (a) Idaho Public Utilities Commission – Case No. PAC-E-23-03, Order
35723, dated March 29, 2023, effective through September 30, 2028; and (b) Oregon Public Utility Commission – Docket No. UF-4337, Order No. 23-105, dated March 21, 2023.
(b) Concept: ClassAndSeriesOfObligationCouponRateDescription
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.
(c) Concept: ClassAndSeriesOfObligationCouponRateDescription
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.
(d) Concept: ClassAndSeriesOfObligationCouponRateDescription
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.
(e) Concept: ClassAndSeriesOfObligationCouponRateDescription
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.
(f) Concept: ClassAndSeriesOfObligationCouponRateDescription
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.
(g) Concept: ClassAndSeriesOfObligationCouponRateDescription
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.
(h) Concept: InterestExpenseBonds
Amount represents interest expense charged to Account 427, Interest on long-term debt, and does not include any amount charged to Account 430, Interest on debt to associated companies, as all such interest was accrued
on amounts included in Account 233, Notes payable to associated companies during the year.
(i) Concept: ClassAndSeriesOfObligationCouponRateDescription
As of December 31, 2023, PacifiCorp had regulatory authorization from the OPUC and IPUC to issue an additional $3.8 billion of long-term debt and must make a notice filing with the Washington Utilities and
Transportation Commission prior to future issuances. In addition, as of December 31, 2023, PacifiCorp had an effective shelf registration statement with the United States Securities Exchange Commission to issue an
indeterminate amount of first mortgage bonds through September 2026. 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, 2023) 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, 2023) is as follows: (a) IPUC -
Case No. PAC-E-08-05, Order No. 30606, dated August 4, 2008; and (b) OPUC - Docket No. UF-4250, Order No. 08-382, dated July 29, 2008.
FERC FORM No. 1 (ED. 12-96)
Page 256-257
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
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.
Line No.Particulars (Details)
(a)
Amount
(b)
1 Net Income for the Year (Page 117)(467,588,533)
2 Reconciling Items for the Year
3
4 Taxable Income Not Reported on Books
5 Allowance for Accounts Receivable 30,441,039
6 Contribution in Aid of Construction 179,951,869
7 Regulatory Asset - BPA Balancing Account - OR 774,760
8 Regulatory Asset - WA Decoupling Mechanism 7,019,149
9 Regulatory Liability - Bridger Accelerated Depreciation - OR 3,634,603
10 Regulatory Liability - Bridger Accelerated Depreciation - WA 2,549,408
11 Regulatory Liability - California Greenhouse Gas Allowance Compliance 2,159,455
12 Regulatory Liability - Deferred Excess RECs in Rates - UT 1,080,929
13 Regulatory Liability - Sale of REC - WA 72,877
14 Regulatory Liability - Utah Home Energy Lifeline 714,619
15 Regulatory Liability - WA Decoupling Mechanism 4,814,027
16 Transmission Service Deposit 726,422
17 Trapper Mining Stock Basis 409,759
18 Unearned Joint Use Pole Contact Revenue 782,578
19 Intercompany Adjustment 1,496,704
9 Deductions Recorded on Books Not Deducted for Return
10 Fed/State Tax Expense-Interest 373,780
11 Accrued Royalties 655,366
12 Accrued Vacation 4,217,913
13 Avoided Costs 147,231,073
14 Book Depreciation 1,088,233,341
15 Book Depreciation Allocated to Medicare and M&E 152,086
16 Capitalization of Test Energy 521,838
17 Capitalized labor and benefit costs 777,899
18 Company Plane 8,600
19 Contra Receivable from Joint Owners 20,756
20 Deferred Compensation 144,885
21 Deferred Revenue - Other 918,383
22 Employee Remuneration - Section 162(m) Limitation 254,734
23 Environmental Liability - Regulated 19,279,988
24 FAS 112 Book Reserve - Postemployment Benefits 1,459,443
25 Fuel Cost Adjustment 6,213,271
26 Hermiston Swap 171,693
27 Hydro Relicensing Obligation 1,413,722
28 Idaho Disallowed Loss 54,818
29 Income Tax Interest 72
30 Injuries and Damages Accrual, net of Insurance Reserves 1,191,657,766
31 Inventory Reserve 88,571
32 Lobbying Expenses 2,367,826
33 Meals and Entertainment 1,685,359
34 Nondeductible Fringe Benefits 72,403
35 Nondeductible Parking Costs 595,170
36 Operating Leases (Liability)381,827
37 Penalties 23,269
38 Prepaid - FSA O& M - East 1,099,824
39 Property Insurance Reserve - OR 4,045,641
40 Regulatory Asset - Arrearage Payments Program - CA 227,343
41 Regulatory Asset - Carbon Decommissioning - CA 28,825
42 Regulatory Asset - Carbon Plant Decom/Inventory 745,601
43 Regulatory Asset - Cedar Springs II - OR 153,469
44 Regulatory Asset - Cholla U4 Closure 6,982,260
45 Regulatory Asset - Covid-19 Bill Assist Program - OR 2,720,242
46 Regulatory Asset - Independent Evaluator Costs - UT 172,340
47 Regulatory Asset - Deferred Intervenor Funding Grants - OR 340,247
48 Regulatory Asset - Deferred Overburden Costs - ID 60,594
49 Regulatory Asset - Deferred Overburden Costs - WY 153,539
50 Regulatory Asset - Depreciation Increase - ID 3,485,076
51 Regulatory Asset - Depreciation Increase - UT 128,043
52 Regulatory Asset - Depreciation Increase - WY 442,191
53 Regulatory Asset - Environmental Costs - WA 713,216
54 Regulatory Asset - FAS 158 Pension Liability 4,454,679
55 Regulatory Asset - Generating Plant Liquidated Damages - UT 35,000
56 Regulatory Asset - Generating Plant Liquidation Damages - WY 5,708
57 Regulatory Asset - Goodnoe Hills Settlement - WY 21,250
58 Regulatory Asset - Klamath Unrecovered Plant 1,101,137
59 Regulatory Asset - Lake Side Settlement - WY 27,331
60 Regulatory Asset - Low-Carbon Energy Standards - WY 1,517,984
61 Regulatory Asset - Meters Replaced by AMI - OR 3,557,611
62 Regulatory Asset - Mobile Home Park Conversion - CA 17,372
63 Regulatory Asset - Pension Settlement - CA 15,099
64 Regulatory Asset - Pension Settlement - OR 654,101
65 Regulatory Asset - Pension Settlement - UT 5,229,029
66 Regulatory Asset - Pension Settlement - WA 254,827
67 Regulatory Asset - Pension Settlement - WY 302,162
68 Regulatory Asset - Post Merger Loss - Reacquired Debt 394,621
69 Regulatory Asset - Post-Retirement Settlement Loss 992,003
70 Regulatory Asset - Preferred Stock Redemption Loss - UT 82,531
71 Regulatory Asset - Preferred Stock Redemption Loss - WA 13,318
72 Regulatory Asset - Preferred Stock Redemption Loss - WY 28,442
73 Regulatory Asset - Property Sales Balancing Account - OR 995,202
74 Regulatory Asset - Renewable Portfolio Standards Compliance - WA 459,667
75 Regulatory Asset - Solar Feed-In Tariff Deferral - OR 1,002,269
76 Regulatory Asset - Solar Incentive Program - UT 11,255,163
77 Regulatory Asset - Subscriber Solar Program - Utah 22,404
78 Regulatory Asset - TB Flats - OR 2,158,807
79 Regulatory Asset - Transportation Electrification Pilot - CA 12,869
80 Regulatory Asset - Transportation Electrification Pilot - OR 2,035,483
81 Regulatory Asset - Utah Mine Disposition 630,074
82 Regulatory Asset - Utility Community Advisory Group - OR 21,411
83 Regulatory Asset - Wildfire Damaged Asset - OR 68,327
84 Regulatory Asset - Wildfire Mitigation - OR 34,932
85 Regulatory Asset - Wildland Fire Protection - UT 1,501,985
86 Regulatory Asset - Wind Test Energy Deferral - WY 7,644
87 Regulatory Liability - ARO/Reg Diff - Trojan - WA Portion 18,122
88 Regulatory Liability - Blue Sky - CA 25,326
89 Regulatory Liability - Blue Sky - ID 29,743
90 Regulatory Liability - Blue Sky - OR 97,281
91 Regulatory Liability - Blue Sky - UT 1,025,571
92 Regulatory Liability - California Energy Savings Assistance 320,017
93 Regulatory Liability - Cholla Decommissioning - CA 55,748
94 Regulatory Liability - Deferred Gains - TerraPower 462,106
95 Regulatory Liability - FAS 158 Post Retirement 6,132,346
96 Regulatory Liability - Fly Ash - WA 3,400,000
97 Regulatory Liability - Klamath River Dams Removal 717
98 Regulatory Liability - Plant Closure Cost - WA 1,355,736
99 Regulatory Liability - Property Insurance Reserve - WA 116,370
100 Regulatory Liability - Steam Decommissioning - CA 742,672
101 Regulatory Liability - Steam Decommissioning - WA 3,569,616
102 Regulatory Liability - Steam Decommmissioning - ID 2,774,994
103 Regulatory Liability - Steam Decommmissioning - UT 17,053,629
104 Regulatory Liability - Steam Decommmissioning - WY 5,668,840
105 Reimbursements 3,050,309
106 Reserve for Bad Debts 11,859,709
107 Utah Klamath Relicensing Costs 3
14 Income Recorded on Books Not Included in Return
15 Book Fixed Asset Gain/Loss (1,936,419)
16 Dividend Received Deduction - Deferred Compensation (92,550)
17 Equity AFUDC (143,775,744)
18 MCI F.O.G. Wire Lease (430,973)
19 Officer's Life Insurance (8,879,305)
20 Regulatory Asset - Alt Rate for Energy Program (CARE) - CA (616,722)
21 Regulatory Asset - BPA Balancing Account - ID (333,711)
22 Regulatory Asset - BPA Balancing Account - WA (1,224,604)
23 Regulatory Asset - Deferred Excess RECs in Rates - WY (891,469)
24 Regulatory Asset - REC Sales Deferral - OR - Noncurrent (144,581)
25 Regulatory Asset - REC Sales Deferral - UT - Noncurrent (1,484,165)
26 Regulatory Liability - Alt Rate for Energy Program (CARE) - CA (32,399)
27 Regulatory Liability - Deferred Excess NPC - OR (4,022,323)
28 Regulatory Liability - Deferred Excess RECs in Rates - WY (121,531)
29 Regulatory Liability - Depreciation Deferral - OR (2,791,260)
30 Regulatory Liability - Excess Income Tax Deferral-CA (306,268)
31 Regulatory Liability - Excess Income Tax Deferral-WA (1,625,292)
32 Regulatory Liability - Excess Income Tax Deferral-WY (651,203)
33 Regulatory Liability - Fly Ash - OR (1,053,764)
34 Regulatory Liability - OR Direct Access 5 Year Opt Out (1,637,355)
35 Regulatory Liability - Renewable Portfolio Standards Compliance - OR (224,021)
36 Regulatory Liability - WA Deferred Steam Depreciation (17,418,111)
37 Regulatory Liability - WA Low Energy Program (555,469)
38 Regulatory Liability - WA Rate Refunds (702,026)
39 Equity Earnings in Subsidiaries (20,109,094)
19 Deductions on Return Not Charged Against Book Income
20 Accrued Bonus (353,000)
21 Accrued Final Reclamation (142,861)
22 Accrued Retention (26,987)
23 Accrued Severance (544,160)
24 Amortization NOPAs 99-00 RAR (11,806)
25 Basis Intangible Difference (421,187)
26 Bear River Settlement Agreement (201,474)
27 Capitalized Depreciation (11,228,894)
28 Cost of Removal (72,871,479)
29 CWIP Reserve (1,801,185)
30 Debt AFUDC (70,096,282)
31 Deferred Compensation Mark to Market Gain / Loss (781,203)
32 Deferred Revenue - Lease Incentives (31,062)
33 Dividend Deduction at 50%(7)
34 Environmental Liability - Non-regulated (92,786)
35 FAS 158 Pension Asset (11,403,747)
36 FAS 158 Post-retirement Asset (1,028,737)
37 FAS 158 SERP Liability (1,646,640)
38 Federal Tax Depreciation (1,173,688,351)
39 Federal Tax Fixed Asset Gain/Loss (25,374,455)
40 Lease Depreciation - Timing Difference (208,039)
41 Lewis River Settlement Agreement (185,253)
42 Long Term Incentive Plan (1,283,847)
43 Long Term Incentive Plan Mark to Market Gain/Loss (1,314,047)
44 Miscellaneous Current and Accrued Liability (250,000)
45 N Umpqua Settlement Agreement (801,824)
46 Oregon Regulatory Asset/Regulatory Liability Consolidation (21,893)
47 Pension/Retirement Accrual (425,077)
48 Pre-1943 Preferred Stock Dividend - Deduction (107,935)
49 Prepaid Aircraft Maintenance (83,585)
50 Prepaid Membership Fees (1,519,721)
51 Prepaid Taxes - ID PUC (18,913)
52 Prepaid Taxes - OR PUC (46,344)
53 Prepaid Taxes - Property Taxes (2,598,862)
54 Prepaid Taxes - UT PUC (66,996)
55 Property Insurance Reserve - CA (1,260,656)
56 Property Insurance Reserve - ID (222,197)
57 Property Insurance Reserve - UT (2,859,848)
58 Property Insurance Reserve - WY (944,058)
59 Regulatory Asset - Arrearage Payment Program - WA (234,000)
60 Regulatory Asset - CA Greenhouse Gas Allowance Compliance (788,378)
61 Regulatory Asset - Carbon Plant Decomm/Inventory-CA RA (52,048)
62 Regulatory Asset - Carbon Plant Decomm/Inventory-WA RA (277,798)
63 Regulatory Asset - Carbon Plant Deferred Depreciation - UT (5,001,096)
64 Regulatory Asset - Catastrophic Event Deferral - CA (20,735,396)
65 Regulatory Asset - Community Solar - OR (177,518)
66 Regulatory Asset - Deferred Excess NPC - CA (10,766,273)
67 Regulatory Asset - Deferred Excess NPC - ID (26,907,463)
68 Regulatory Asset - Deferred Excess NPC - OR (146,341,534)
69 Regulatory Asset - Deferred Excess NPC - UT (252,435,734)
70 Regulatory Asset - Deferred Excess NPC - WA (68,462,521)
71 Regulatory Asset - Deferred Excess NPC - WY (66,355,882)
72 Regulatory Asset - Deferred Independent Evaluator Fees - OR (86,079)
73 Regulatory Asset - Deferred Intervenor Funding - WA (300,000)
74 Regulatory Asset - Deferred Intervenor Funding Grants - CA (15,869)
75 Regulatory Asset - Distribution System Plan - OR (1,213,780)
76 Regulatory Asset - Electric Vehicle Charging Infrastructure - UT (1,164,378)
77 Regulatory Asset - Emergency Service Program-Battery Storage-CA (10,005)
78 Regulatory Asset - Environmental Costs (29,374,965)
79 Regulatory Asset - Equity Advisory Group - WA (346,311)
80 Regulatory Asset - FAS 158 Post Retirement Liability (9,428,101)
81 Regulatory Asset - Fire Risk Mitigation - CA (4,431,241)
82 Regulatory Asset - GRC Memo Account - CA (16,511,539)
83 Regulatory Asset - Low Income Bill Discount - OR (7,068,358)
84 Regulatory Asset - Post Employment Costs (2,069,025)
85 Regulatory Asset - STEP Pilot Program Balance Account - Utah (12,041,205)
86 Regulatory Asset - Transportation Electrification Pilot - WA (216,663)
87 Regulatory Asset/Liability - Demand Side Management (24,861,910)
88 Regulatory Liability - 50% Bonus Tax Depr - WY (376,801)
89 Regulatory Liability - Blue Sky - WA (13,320)
90 Regulatory Liability - Blue Sky - WY (4,233)
91 Regulatory Liability - Cholla Decommissioning - ID (254,325)
92 Regulatory Liability - Cholla Decommissioning - WY (11,744)
93 Regulatory Liability - Cholla Plant Unit No. 4 Decommissioning - OR (1,119,718)
94 Regulatory Liability - Cholla Plant Unit No. 4 Decommissioning - UT (1,893,452)
95 Regulatory Liability - Clean Fuels Program - OR (291,229)
96 Regulatory Liability - Deferred Excess NPC - CA (1,990,883)
97 Regulatory Liability - Injuries & Damages Reserve - OR (1,062,307)
98 Regulatory Liability - OR Energy Conservation Charge (1,154,431)
99 Regulatory Liability - UT Solar Incentive Subscriber Program (12,257,797)
100 Regulatory Liability - Utility Bill Assistance - UT (505,239)
101 Repairs Deduction (207,622,120)
102 Rogue River - Habitat Enhancement Liability (82,739)
103 ROU Asset (Operating Leases)(424,160)
104 Sales & Use Tax Audit Exposure (1,056,186)
105 Tax Depletion-SRC (15,439)
106 Tax Percentage Depletion - Blundell Steam Field (4,560)
107 Trapper Mine Contract Obligation (921,626)
108 Trojan Decommissioning (383,738)
109 Wasatch Workers Comp Reserve (570,616)
110 Western Coal Carrier Retiree Medical Accrual (130,000)
111 State Tax Deductions 14,995,125
27 Federal Tax Net Income (724,413,465)
28 Show Computation of Tax:
29 Federal Income Tax at 21.00%(152,126,828)
30 Provision to Return Adjustment (2,166,356)
31 Tax Reserve Changes (34,380)
32 Renewable Energy Production Tax Credits (179,652,735)
33 Other Federal Tax Credits
34 (a)
Federal Income Tax Accrual (333,980,299)
FERC FORM NO. 1 (ED. 12-96)
Page 261
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: ComputationOfTaxDescription
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
Pacific Minerals, Inc.
BHE Sub-Group:
Aardwolf Transfer Co., Inc.Elmore Company MHC Investment Company
ABA Management, L.L.C.Elmore North Geothermal LLC Mid-America Referral Network, Inc.
AC Eagle Corporation Energy West Mining Company MidAmerican Central California Transco, LLC
AC Palm Desert Corporation Esslinger-Wooten-Maxwell, Inc.MidAmerican Energy Company
AC2015 Corporation E-W-M Referral Services, Inc.MidAmerican Energy Machining Services LLC
Aeronavis, LLC F&R/T LLC MidAmerican Energy Services, LLC
Alamo 6 Solar Holdings, LLC Falcon Power Operating Company MidAmerican Funding, LLC
Alamo 6, LLC Farmington Properties, Inc.MidAmerican Geothermal Development Corporation
Alaska Gas Transmission Company, LLC FFR, Inc.MidAmerican Wind Tax Equity Holdings, LLC
Alliance Relocations, Inc.First Network Realty, Inc.Midland Escrow Services, Inc.
Alliance Title Group, LLC First Realty, Ltd.Mid-States Title Insurance Agency, LLC
Ambassador Real Estate Company First Weber Illinois, LLC Midwest Capital Group, Inc.
American Eagle Referral Service, LLC First Weber Referral Associates, Inc.Midwest Power Midcontinent Transmission Development, LLC
Americana Arizona Referrals, LLC First Weber, Inc.Midwest Power Transmission Arkansas, LLC
Americana Arizona, LLC Fishlake Power LLC Midwest Power Transmission Iowa, LLC
Americana, L.L.C.Flat Top Holdings, LLC Midwest Power Transmission Kansas, LLC
Apex Home Maintenance, LLC Flat Top Wind I, LLC Midwest Power Transmission Oklahoma, LLC
ARE Commercial Real Estate, LLC Florida Network LLC Midwest Power Transmission Texas, LLC
ARE Iowa, LLC Florida Network Property Management, LLC Midwest Preferred Realty, Inc.
Arizona HomeServices, L.L.C.Fluvanna Holdings 2, LLC Midwest Realty Ventures, LLC
Attorneys Title Holdings, Incorporated Fluvanna Wind Energy 2, LLC Modern Transportation Services, Inc.
BDFH, Inc.For Rent, Inc.Modular LNG Holdings, Inc.
Beach Properties of Florida, LLC Fort Dearborn Land Title Company, LLC Moholland Transfer, Inc.
Bennion & Deville Fine Homes, Inc.FRTC, LLC Montana Alberta Tie LP Inc.
Berkshire Hathaway Energy Company Geronimo Community Solar Gardens Holding Company, LLC Montana Alberta Tie US Holdings GP Inc.
BH2H Holdings, LLC Geronimo Community Solar Gardens, LLC Morton Bay Geothermal LLC
BHE AC Holding, LLC Gibraltar Title Services, LLC MPT Heartland Development, LLC
BHE America Transco, LLC GPWH Holdings, LLC MTL Canyon Holdings, LLC
BHE Canada, LLC Grande Prairie Land Holding, LLC NE Hub Partners, L.L.C.
BHE Community Solar, LLC Grande Prairie Wind Holdings, LLC NE Hub Partners, L.P.
BHE Compression Services, LLC Grande Prairie Wind II, LLC Nebraska Referral, Inc.
BHE CS Holdings, LLC Grande Prairie Wind, LLC Nevada Electric Investment Company
BHE Gas, Inc.Greater Metro, LLC Nevada Power Company
BHE Geothermal, LLC Guarantee Appraisal Corporation Niche Storage Solutions, LLC
BHE Glacier Wind 1, LLC Guarantee Real Estate NNGC Acquisition, LLC
BHE Glacier Wind 2, LLC Hegg Limited Referral Company, LLC Northeast Referral Group, LLC
BHE GT&S, LLC HEGG Realtors Iowa, Inc.Northern Natural Gas Company
BHE Hydro, LLC HEGG, Realtors Inc.Northrop Realty, LLC
BHE Infrastructure Group, LLC HN Real Estate Group, L.L.C.NRS Referral Services, LLC
BHE Infrastructure Services, LLC HN Real Estate Group, N.C., Inc.NV Energy, Inc.
BHE Midcontinent Transmission Holdings, LLC HN Referral Corporation NVE Holdings, LLC
BHE Montana, LLC HomeServices Insurance, Inc.NVE Insurance Company, Inc.
BHE Pearl Solar Holdings, LLC HomeServices KOI, Inc.NW Referral Services, LLC
BHE Pearl Solar, LLC HomeServices Lending, LLC Pacific Minerals, Inc.
BHE Pipeline Group, LLC HomeServices MidAtlantic, LLC PacifiCorp
BHE Power Watch, LLC HomeServices Northeast, LLC PCG Agencies, Inc.
BHE Ravenswood, LLC HomeServices of Alabama, Inc.PCRE, L.L.C.
BHE Renewables, LLC HomeServices of America, Inc PHM Holdings, LLC
BHE Rim Rock Wind, LLC HomeServices of Arizona, LLC Pickford Escrow Company, Inc.
BHE Solar, LLC HomeServices of California, LLC Pickford Holdings LLC
BHE Southwest Transmission Holdings, LLC HomeServices of Colorado, LLC Pickford Real Estate, Inc.
BHE Texas Transco, LLC HomeServices of Connecticut, LLC Pickford Services Company
BHE Turbomachinery, LLC HomeServices of Florida, Inc.Pilot Butte, LLC
BHE U.K. Electric, Inc.HomeServices of Georgia, LLC Pinyon Pines Funding, LLC
BHE U.K. Inc.HomeServices of Illinois Holdings, LLC Pinyon Pines I Holding Company, LLC
BHE U.K. Power, Inc.HomeServices of Illinois, LLC Pinyon Pines II Holding Company, LLC
BHE U.S. Transmission, LLC HomeServices of Iowa, Inc.Pinyon Pines Projects Holding, LLC
BHE Wind Watch, LLC HomeServices of Kentucky Real Estate Academy, LLC Pinyon Pines Wind I, LLC
BHE Wind, LLC HomeServices of Minnesota, LLC Pinyon Pines Wind II, LLC
BHE WV Holdings, LLC HomeServices of MOKAN, LLC Pivotal JAX LNG, LLC
BHE WV Renewables, LLC HomeServices of Nebraska, Inc.Pivotal LNG, LLC
BHEM Balancing Authority Services, LLC HomeServices of Nevada, LLC PNJP, LLC
BHER Flat Top Wind Holdings, LLC HomeServices of New York, LLC PNW Referral, LLC
BHER Gopher Wind Holdings, LLC HomeServices of Oregon, LLC PPW Holdings LLC
BHER Independence Wind Holdco, LLC HomeServices of Texas, LLC Preferred Carolinas Realty, Inc.
BHER IWE Holdco, LLC HomeServices of the Carolinas, Inc.Prime Alliance Real Estate Services, LLC
BHER Mariah Wind Holdings LLC HomeServices of Washington, LLC Priority Title Corporation
BHER Market Operations, LLC HomeServices of Wisconsin, LLC PRL Solar, LLC
BHER Minerals, LLC HomeServices Partnership Group, LLC Property Services Northeast, LLC
BHER Operating Company, LLC HomeServices Property Management, LLC Prosperity First Title, LLC
BHER Power Resources, Inc.HomeServices Referral Network, LLC Prosperity Home Mortgage, LLC
BHER Ravenswood Solar 1, LLC HomeServices Relocation, LLC Pru-One, Inc.
BHER San Vicente Holdings LLC HomeServices Title Holdings, LLC Real Estate Knowledge Services, LLC
BHER Santa Rita Holdings, LLC Houlihan Lawrence Associates, LLC Real Living Real Estate, LLC
BHER Santa Rita Investment, LLC Houlihan/Lawrence, Inc.Reece & Nichols Alliance, Inc.
BHER WV Solar, LLC HS Franchise Holding, LLC Reece & Nichols Realtors, Inc.
BHER WV Wind, LLC HSF Affiliates LLC Reece Commercial, Inc.
BHES CSG Holdings, LLC HSGA Real Estate Group, L.L.C.Referral Associates of Georgia, LLC
BHES Pearl Solar Holdings, LLC HSN Holdings, LLC Referral Associates of New Jersey, Inc.
BHH Affiliates, LLC HSNV Title Holding, LLC Referral Network of IL, LLC
BHH Iowa Affiliates, LLC HSTX Title, LLC Renewable Development Ventures LLC
BHH KC Real Estate, LLC HSW Affiliates Holding, LLC REV LNG SSL BC LLC
Bishop Hill Energy II LLC Huff-Drees Realty, Inc.RGS Settlements of Pennsylvania, LLC
Bishop Hill II Holdings, LLC IES Holding II, LLC RGS Title, LLC
Black Rock Geothermal LLC Imperial Magma LLC RHL Referral Company, L.L.C.
BPFLA Referrals, LLC Independence Wind Energy LLC Roberts Brothers, Inc.
CalEnergy Company, Inc.Insight Home Inspections, LLC Roy H. Long Realty Company, Inc.
CalEnergy Generation Operating Company Intero Franchise Services, Inc.S.W. Hydro, Inc.
CalEnergy Geothermal Holding, LLC Intero Nevada Referral Services, LLC Sage Title Group, LLC
CalEnergy International Services, Inc.Intero Nevada, LLC Salton Sea Power Company
CalEnergy Minerals LLC Intero Real Estate Holdings, Inc.Salton Sea Power Generation Company
CalEnergy Operating Corporation Intero Real Estate Services, Inc.Salton Sea Power L.L.C.
CalEnergy Pacific Holdings Corp.Intero Referral Services, Inc.Santa Rita Wind Energy LLC
CalEnergy YCA Partner 2, LLC Iowa Realty Co., Inc.Saranac Energy Company, Inc.
CalEnergy, LLC Iowa Title Company Sequoia Aviation Corporation
California Energy Development Corporation Iroquois GP Holding Company, LLC Shared Success Center, LLC
California Energy Yuma Corporation Iroquois, Inc.Sierra Gas Holdings Company
California Utility Holdco, LLC JBRC, Inc.Sierra Pacific Power Company
CanopyTitle, LLC Jim Huff Realty, Inc.Silver State Property Holdings, LLC
Capitol Title Company Joe Moholland Inc.SoCal Services & Property Management
Carolina Gas Services, Inc.JRHBW Realty, Inc. d/b/a/ RealtySouth Solar San Antonio LLC
Carolina Gas Transmission, LLC Jumbo Road Holdings, LLC Solar Star 3, LLC
CE Electric (NY), Inc Kansas City Title, Inc.Solar Star 4, LLC
CE Generation, LLC Kanstar Transmission, LLC Solar Star California XIX, LLC
CE Geothermal, Inc.Kentucky Residential Referral Service, LLC Solar Star California XX, LLC
CE International Investments, Inc Kentwood Commercial, LLC Solar Star Funding, LLC
CE Leathers Company Kentwood Real Estate Cherry Creek, LLC Solar Star Projects Holding, LLC
CE Turbo LLC Kentwood Real Estate City Properties, LLC Southwest Settlement Services, LLC
Combined Van Lines, Inc.Kentwood Real Estate DTC, LLC SSC XIX, LLC
Commonsite, Inc.Kentwood Real Estate Services, LLC SSC XX, LLC
Cordova Energy Company LLC Kentwood, LLC Texas Emergency Power Reserve, LLC
Cove Point GP Holding Company, LLC Kern River Gas Transmission Company The Escrow Firm, Inc.
Crossroads Moving & Storage, Inc.Keystone Partners, LLC The Long & Foster Companies, Inc.
CTRE, L.L.C.KR Holding, LLC The Referral Co.
Dakota Dunes Development Company Lands of Sierra, Inc.Thoroughbred Title Services, LLC
DCCO INC.Larabee School of Real Estate, Inc.Tioga Properties, LLC
Del Ranch Company Long & Foster Institute of Real Estate, LLC TLTC LLC
Denver Rental, LLC Long & Foster Insurance Agency, LLC Topaz Solar Farms LLC
Desert Valley Company Long & Foster Mortgage Ventures, Inc.TPZ Holding, LLC
DesertLink Investments, LLC Long & Foster Real Estate, Inc.TRMC LLC
Earth Energy Power Link LLC Long & Foster Settlement Services, LLC TX Jumbo Road Wind, LLC
Eastern Energy Field Services, Inc.Lovejoy Realty, Inc.TX Referral Alliance, Inc.
Eastern Energy Gas Holdings, LLC Lovejoy Referral Network LLC Volantes, LLC
Eastern Gas Transmission and Storage, Inc M & M Ranch Acquisition Company, LLC Vulcan Power Company
Eastern Gathering and Processing Inc.M & M Ranch Holding Company, LLC Vulcan/BN Geothermal Power Company
Eastern MLP Holding Company II, LLC Magma Land Company I Wailuku Holding Company, LLC
Ebby Halliday Alliance, LLC Magma Power Company Wailuku Investment, LLC
Ebby Halliday Properties, Inc.Mariah del Norte LLC Wailuku River Hydroelectric Power Company, Inc.
Ebby Halliday Real Estate, Inc.Marshall Wind Energy Holdings, LLC Walnut Ridge Wind, LLC
Ebby Halliday Real Estate, LLC Marshall Wind Energy LLC Watermark Realty Referral, Inc.
Edina Financial Services, Inc.MEHC Investment, Inc.Watermark Realty, Inc.
Edina Realty Referral Network, Inc.MES Holding, LLC Weathervane Referral Network, Inc.
Edina Realty Title, Inc.Metro Referral Associates, Inc.Western Capital Group, LLC
Edina Realty, Inc.Metro Referrals, LLC
Elk Valley Wind, LLC MHC Inc.
With respect to members of the BHE Sub-Group, Berkshire Hathaway Energy Co. (BHE) requires all subsidiaries to pay to 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 stemming from cost borne by utility customers.
Berkshire Hathaway Inc. Sub-Group:
121 Acquisition Co., LLC Fruit of the Loom, Inc. (Sub)NorGUARD Insurance Company
21 SPC, Inc.FTI MANUFACTURING INC Northern States Agency, Inc.
21st Communities, Inc.FTL Regional Sales Co., Inc.Noveon Hilton Davis, Inc.
21st Mortgage Corporation Garan Central America Corp.NSS TECHNOLOGIES INC
2K Polymer Systems, Inc.Garan Incorporated Oak River Insurance Company
Acme Brick Company Garan Manufacturing Corp.Old United Casualty Company
Acme Building Brands, Inc Garan Services Corp Old United Life Insurance Company
Acme Management Company Garat Co. Ltd.Orien Risk Analysts, Inc.
Acme Services Company, LLC Gateway Underwriters Agency, Inc.Oriental Trading Company, Inc.
Adalet/Scott Fetzer Company GEICO Advantage Insurance Company OTC Brands, Inc.
AEROCRAFT HEAT TREATING CO INC GEICO Atlantis Corporation OTC Direct, Inc.
Aero-Hose Corporation GEICO Casualty Co.OTC Worldwide Holdings, Inc.
AEROSPACE DYNAMICS INTERNATIONAL INC GEICO Choice Insurance Company Particle Sciences, Inc.
Affordable Housing Partners, Inc.GEICO Corporation PCC FLOW TECHNOLOGIES HOLDINGS INC
AIPCF V CHI Blocker Inc GEICO Discovery Corporation PCC FLOW TECHNOLOGIES INC.
AJF Warehouse Distributors, Inc.GEICO Endeavor Corporation PCC ROLLMET INC
Albecca, Inc.GEICO General Insurance Co.PCC STRUCTURALS INC
Alleghany Capital Corporation GEICO Indemnity Co.Penn Coal Land, Inc.
Alleghany Corporation GEICO Marine Insurance Company Perfection Hy-Test Company
Alleghany Properties Holdings LLC GEICO Oasis Insurance Company PERMASWAGE HOLDINGS, INC.
Alleghany Reinsurance Company LLC GEICO Perspective Corporation Pine Canyon Land Company
Alpha Cargo Motor Express, Inc GEICO Products, Inc.Piper Finance Company
Alu-Forge, Inc GEICO Protection Insurance Company Platte River Insurance Company
Ambucor Health Solutions, Inc.GEICO Secure Insurance Company Plaza Financial Services Co.
American All Risk Insurance Services Inc.Gen Re Intermediaries Corporation Plaza Resources Co.
American Commercial Claims Administrators Inc General Re Corporation PLICO
American Dairy Queen Corporation General Re Financial Products Corporation Precision Brand Products, Inc.
AmGUARD Insurance Company General Re Life Corporation PRECISION CASTPARTS CORP
Andrews Laser Works Corporation General Reinsurance Corporation Precision Cutting Technologies, Inc.
APACE Holding Company LLC General Star Indemnity Company PRECISION FOUNDERS INC
Artform International Inc.General Star National Insurance Company Press Forge Company
ATLANTIC PRECISION INC Genesis Insurance Company Princeton Insurance Company
AVIBANK MANUFACTURING INC Government Employees Financial Corp.Priority One Financial Services, Inc.
AzGUARD Insurance Company Government Employees Insurance Co.PRISM Holdings LLC
Bayport Systems, Inc.GRD Holdings Corporation PRISM Plastics, Inc.
Ben Bridge Jeweler, Inc.GREENVILLE METALS INC Procrane Holdings, Inc.
Benjamin Moore & Co.GUARDco, Inc.Professional Risk Management Services, Inc.
Benson Industries, Inc.H. H. Brown Shoe Company, Inc.PROGRESSIVE INCORPORATED
Benson, Ltd.H.J. Justin & Sons, Inc.PROTECTIVE COATING INC
Berkshire Hathaway Assurance Corporation HACKNEY LADISH INC QS Partners LLC
Berkshire Hathaway Automotive Inc.Halex/Scott Fetzer Company QS Security Services LLC
Berkshire Hathaway Credit Corporation HAMILTON AVIATION INC R.C. Tway Company, LLC
Berkshire Hathaway Direct Insurance Company Hawthorn Life International, Ltd.R.C. Willey Home Furnishings
Berkshire Hathaway Finance Corporation HeatPipe Technology, Inc.Radnor Specialty Insurance Company
Berkshire Hathaway Global Insurance Services, LLC Heibar Installation, Inc.Railserve, Inc.
Berkshire Hathaway Homestate Insurance Company Heibar Manufacturing, Inc.Railsplitter Holdings Corporation
Berkshire Hathaway Inc.HELICOMB INTERNATIONAL INC RATHGIBSON HOLDING CO LLC
Berkshire Hathaway Life Insurance Company of Nebraska Henley Holdings, LLC Redwood Fire and Casualty Insurance Company
Berkshire Hathaway Specialty Insurance Company Hohmann & Barnard, Inc.RENTCO Trailer Corporation
BH Columbia Inc.Homefirst Agency, Inc.Resolute Management Inc.
BH Credit LLC Homemakers Plaza, Inc.Resurgens Specialty Underwriting, Inc.
BH Finance, Inc.HOWELL PENNCRAFT, INC.Richline Group, Inc
BH Holding H Jewelry Inc.HUNTINGTON ALLOYS CORPORATION Ringwalt & Liesche Co.
BH Holding LLC IdeaLife Insurance Company Rio Grande, Inc.
BH Holding S Furniture Inc IMC International Metalworking Companies Inc.Rochester Crematory, Inc.
BH Media Group, Inc.Ingersoll Cutting Tool Company Inc.Roxell USA, Inc.
BH Shoe Holdings, Inc.Innovative Building Products, Inc RSUI Group, Inc.
BHA Minority Interest Holdco, Inc.Innovative Coatings Technology Corporation RSUI Indemnity Company
BHG Life Insurance Company Interco Tobacco Retailers, Inc.RSUI Insurance Exchange RPG, Inc.
BHG Structured Settlements, Inc.International Dairy Queen, Inc.RSUI Surplus Lines Insurance Services, Inc.
BHHC Special Risks Insurance Company International Insurance Underwriters, Inc.Sager Electrical Supply Co. Inc
BH-IMC Holdings Inc.Intrepid JSB, Inc.Santa Fe Pacific Insurance Company
BHSF, Inc.Ironwood Plastics Inc Santa Fe Pacific Pipeline Holdings, Inc.
biBERK Insurance Services, Inc.Iscar Metals Inc.Santa Fe Pacific Pipelines, Inc.
Blue Chip Stamps, Inc.ITTI Group USA Holdings Inc.Santa Fe Pacific Railroad Company
BMB Machine Enterprises, Inc.ITTI Investment Holdings Inc.Scott Fetzer Financial Group, Inc.
BN Leasing Corporation J.L. Mining Company ScottCare Corporation
BNSF Communications, Inc.Jazplus, LLC See's Candies, Inc.
BNSF Logistics, LLC Jazwares Canada Holdings Inc.See's Candy Shops, Incorporated
BNSF Railway Company Jazwares Entertainment, LLC Seventeenth Street Realty, Inc.
BNSF Spectrum, Inc.Jazwares Soft Creations LLC SFEG Corp.
Boat America Corporation Jazwares, LLC Shaw Asia Pacific Holdings, LLC
Boat Owners Association of the United States Johns Manville China, Ltd.Shaw Diversified Services, Inc.
Borsheim Jewelry Company, Inc Johns Manville Corporation Shaw Floors, Inc.
Bourn & Koch, Inc.Johns Manville, Inc.Shaw Funding Company
Brainy Toys, Inc.Jordan's Furniture, Inc.Shaw Industries Group, Inc.
Brilliant National Services, Inc.Joyce Steel Erection LLC Shaw Industries, Inc.
BRITTAIN MACHINE INC Justin Brands, Inc.Shaw Integrated and Turf Solutions, Inc.
Brooks Sports, Inc.Kahn Ventures, Inc.Shaw International Services, Inc.
Burlington Northern Railroad Holdings, Inc.Kelly Amusement Holdings, LLC Shaw Retail Properties, Inc.
Burlington Northern Santa Fe, LLC Kinexo, Inc.Shaw Sports Turf California, Inc.
Business Wire, Inc.KITCO Fiber Optics, Inc.Shaw Transport, Inc.
CALEDONIAN ALLOYS INC KLUNE HOLDINGS INC Shaw Watershed Holdings, LLC.
Camp Manufacturing Company KLUNE INDUSTRIES INC SHX Flooring, Inc.
Cannon Equipment LLC L.A. Terminals, Inc.SidePlate Systems, Inc.
CANNON MUSKEGON CORPORATION Landmark American Insurance Company Smilemakers Canada Inc.
Capitol Facilities Corporation Larson-Juhl International LLC Smilemakers, Inc.
Capitol Indemnity Corporation LeachGarner, Inc.SN Management, Inc.
Capitol Specialty Insurance Corporation Lipotec USA, Inc.Soco West, Inc.
CapSpecialty, Inc.LiquidPower Specialty Products, Inc.Sonnax Transmission Company
Carefree/Scott Fetzer Company LJ AERO HOLDINGS INC Southern Energy Homes, Inc.
CATA Services Company LJ SYNCH HOLDINGS INC SOUTHWEST UNITED INDUSTRIES INC
Cavalier Homes, Inc.LMG Ventures, LLC SPS INTERNATIONAL INVESTMENT COMPANY
Central States Indemnity Co. of Omaha Loch Vale Logistics, Inc.SPS TECHNOLOGIES LLC
Central States of Omaha Companies, Inc.Los Angeles Junction Railway Company SPS Technologies Mexico LLC
CH Industries, Inc.LSPI Holdings Inc.SSP-SiMatrix Inc.
Charter Brokerage Holdings Corp.Lubrizol Advanced Materials Holding Corporation Stahl/Scott Fetzer Company
Chemtool Incorporated Lubrizol Advanced Materials, Inc.Star Lake Railroad Company
CJE II Lubrizol Global Management, Inc.Summit Distribution Services, Inc.
Claims Services, Inc.Lubrizol Inter-Americas Corporation SXP SCHULZ XTRUDED PRODUCTS LLC FKA SXP SCHULZ XTRUDED PRODUCTS LP
Clayton Education Corp.Lubrizol International, Inc.T Fixtures Co., Inc.
Clayton Homes, Inc.Lubrizol Life Science, Inc.TBS USA, Inc.
Clayton Properties Group II, Inc.Lubrizol Overseas Trading Corporation Tenn-Tex Plastics, Inc.
Clayton Properties Group, Inc.M & C Products, Inc.TEXAS HONING INC
Clayton Supply, Inc.M&M Manufacturing, Inc.The Ben Bridge Corporation
Clayton, Inc.M2 Liability Solutions, Inc.The BVD Licensing Corporation
CMH Capital, Inc.Mapletree Transportation, Inc.The Duracell Company
CMH Homes, Inc.Marmon Beverage Technologies, Inc.The Fechheimer Brothers Co.
CMH Manufacturing West, Inc.Marmon Crane Services, Inc.The Indecor Group, Inc.
CMH Manufacturing, Inc.Marmon Distribution Services, Inc.The Lubrizol Corporation
CMH Services Aviation, Inc.Marmon Energy Services Company The Medical Protective Company
CMH Services, Inc.Marmon Engineered Components Company The Pampered Chef, Ltd.
CMH Transport, Inc.Marmon Foodservice Technologies, Inc.The Scott Fetzer Company
Coil Master Corporation Marmon Holdings, Inc.The Zia Company
Columbia Insurance Company Marmon Link Inc Thermoform Plastics, Inc.
Complementary Coatings Corporation Marmon Metal Solutions, Inc.THI ACQUISITION INC
Composites Horizons LLC Marmon Rail Group, Inc.TIMET REAL ESTATE CORPORATION
Consumer Value Products, Inc.Marmon Railroad Services LLC TITANIUM METALS CORPORATION
Continental Divide Insurance Company Marmon Renew, Inc.TM City Leasing Inc.
Cort Business Services Corporation Marmon Retail & Highway Technologies Company LLC Tool-Flo Manufacturing, Inc.
Covington Specialty Insurance Company Marmon Retail Products, Inc.Top Five Club, Inc.
CPM Development, LLC Marmon Retail Store Equipment LLC Total Quality Apparel Resources
Criterion Insurance Agency Marmon Retail Technologies Company TPC European Holdings, LTD.
Crown Holdco One, Inc.Marmon Tubing, Fittings & Wire Products, Inc.TPC North America, Ltd.
Crown Holdco Two, Inc.Marmon Water, Inc.Transatlantic Holdings, Inc.
Crown Parent, Inc.Marmon Wire & Cable, Inc.Transatlantic Reinsurance Company
CSI Life Insurance Company Marmon-Herrington Company Transco Railcar Repair Inc
CTB Credit Corp Maryland Ventures, Inc..Transco Railway Products Inc.
CTB Inc.McCarty-Hull Cigar Company, Inc.Transco, Inc.
CTB International Corp McLane Beverage Distribution, Inc.Transportation Technology Services, Inc.
CTB Investment Holdings Inc.McLane Beverage Holding, Inc.TransRe Underwriting Managers Agency Ltd.
CTB IW INC McLane Company, Inc.TRH Holding Corp.
CTB Midwest Inc McLane Eastern, Inc.Triangle Suspension Systems, Inc.
CTB MN Investments McLane Express, Inc.Tricycle, Inc.
CTB Technology Holding Inc.McLane Foods, Inc.Trilogy Communications, Inc.
CTMS North America, Inc.McLane Foodservice Distribution, Inc.TrueNorth Development Inc.
Cumberland Asset Management, Inc.McLane Foodservice, Inc.TS City Leasing Inc
Cypress Insurance Company McLane Interstate Warehouse, Inc.TSE Brakes, Inc.
D.I. Properties Inc.McLane Mid-Atlantic, Inc.TTI JV 1
Daniels-Head General Agency, Inc.McLane Midwest, Inc.TTI JV 2
Daniels-Head Insurance Agency, Inc. (CA)McLane Minnesota, Inc.TTI, Inc.
Daniels-Head Insurance Agency, Inc. (TX)McLane Network Solutions, Inc.Tucker Safety Products, Inc.
Daniels-Head Management Corp.McLane New Jersey, Inc.TXFM, Inc.
DCI Marketing Inc.McLane Ohio, Inc.U.S. Investment Corporation
DESIGNED METAL CONNECTIONS, INC.McLane Southern, Inc.U.S. Underwriters Insurance Co.
Diamond Technology Innovations, Inc.McLane Suneast, Inc.UCFS Europe Company
DICKSON TESTING CO INC McLane Tri-States, Inc.UCFS International Holding Company
DL Trading Holdings I, Inc.McLane Western, Inc.Unified Supply Chain, Inc.
DQF, Inc.MCWILLIAMS FORGE COMPANY Uni-Form Components Co.
DQGC, Inc.Medical Protective Finance Corporation Union Tank Car Company
Duracell Industrial Operations, Inc.MedPro Group, Inc Union Underwear Co., Inc
Duracell U.S. Operations Inc MedPro Risk Retention Services, Inc.United Consumer Financial Services Company
Easley Custom Plastics, Inc.Merit Distribution Services, Inc.United Direct Finance, Inc.
EastGUARD Insurance Company METALAC FASTENERS INC United States Aviation Underwriters, Incorporated
Eco Color Company Meyn LLC United States Liability Insurance Company
Ecodyne Corporation MFS Fleet, Inc.V3 Insurance Agency Inc.
Ellis & Watts Global Industries, Inc.Midwest Northwest Properties, Inc.Van Enterprises, Inc.
Elm Street Corporation Miller Sage Holdings, Inc.Vanderbilt ABS Corp.
Empire Distributors of Colorado, Inc.Mindware Corporation Vanderbilt Mortgage and Finance, Inc.
Empire Distributors of North Carolina, Inc.MiTek Holdings, Inc.Vanity Fair, Inc.
Empire Distributors of Tennessee, Inc.MiTek Inc.Veritas Insurance Group, Inc.
Empire Distributors, Inc.MiTek Industries, Inc.Vesta Intermediate Funding, Inc.
ENVIRONMENT ONE CORPORATION MLMIC Insurance Company VFI-Mexico, Inc.
EXACTA AEROSPACE INC MLMIC Services, Inc.Visilinx, Inc.
Executive Jet Management, Inc.Morgantown-National Supply, Inc.Vision Retailing, Inc.
Exponential Technology Group, Inc.Mount Vernon Fire Insurance Company VT Insurance Acquisition Sub Inc.
Exsif Worldwide, Inc.Mount Vernon Specialty Insurance Company Wayne Combustion Systems, Inc.
ExtruMed, Inc.Mouser Electronics, Inc.Wayne/Scott Fetzer Company
Fair American Insurance and Reinsurance Company Mouser JV 1, Inc WEAVER MANUFACTURING INC
Fair American Select Insurance Company Mouser JV 2 Webb Wheel Products, Inc.
FATIGUE TECHNOLOGY INC MPP Co., Inc.Wellfleet Insurance Company
Financial Services Plus, Inc.MPP Pipeline Corporation Wellfleet New York Insurance Company
Finial Holdings, Inc.MS Property Company Western Builders Supply, Inc.
Finial Reinsurance Company MW Wholesale, Inc.Western Fruit Express Company
First Act, LLC National Fire & Marine Insurance Company Western/Scott Fetzer Company
First Berkshire Hathaway Life Insurance Company National Indemnity Company WestGUARD Insurance Company
FlightSafety Capital Corp.National Indemnity Company of Mid-America Whittaker, Clark & Daniels, Inc.
FlightSafety Defense Corporation National Indemnity Company of the South Wilbert Funeral Services, Inc.
FlightSafety Development Corp.National Liability & Fire Insurance Company Wilbert, Inc.
FlightSafety International Inc.Nationwide Uniforms World Book Encyclopedia, Inc.
FlightSafety International Middle East Inc.Nebraska Furniture Mart, Inc.World Book, Inc.
FlightSafety New York, Inc.NetJets Aviation, Inc.World Book/Scott Fetzer Company
FlightSafety Properties, Inc.NetJets Card Holdings, Inc.World Investments, Inc.
Floors, Inc.NetJets Card Partners, Inc.Worldwide Containers, Inc.
Focused Technology Solutions, Inc.NetJets Europe Holdings, LLC WPLG, Inc.
Fontaine Commercial Trailer, Inc.NetJets Financial Holdings LLC WYMAN GORDON COMPANY
Fontaine Engineered Products, Inc.NetJets Inc.WYMAN GORDON FORGINGS CLEVELAND INC
Fontaine Fifth Wheel Company NetJets International, Inc.WYMAN GORDON FORGINGS INC
Fontaine Modification Company NetJets Sales, Inc.WYMAN GORDON INVESTMENT CASTINGS INC
Fontaine Spray Suppression Company NetJets Services, Inc.WYMAN GORDON PENNSYLVANIA LLC
Fontaine Trailer Company LLC NetJets U.S., Inc.Xelix Distribution, Inc.
Forest River Holdings, Inc.New England Asset Management, Inc.X-L-Co., Inc.
Forest River, Inc.NFM Custom Countertops, LLC XTRA Companies, Inc.
Forseti Assurance Company, LLC NFM of Cedar Park, Inc.XTRA Corporation
Frasca International, Inc.NFM of Kansas, Inc.XTRA Finance Corporation
Freedom Warehouse Corp.NFM SERVICES, LLC XTRA Intermodal, Inc.
Fruit of the Loom Direct, Inc.NJE Holdings, LLC Z Global Logistics, LLC
Fruit of the Loom Trading Company NJI Sales, Inc.Zag Toys Holdings, LLC
Fruit of the Loom, Inc.Noranco Manufacturing (USA) Ltd.
FERC FORM NO. 1 (ED. 12-96)
Page 261
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
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 hav
to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are known, 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 (g) and (h). The balancing of this page is not affected
of these taxes.
3. Include in column (g) 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 cu
(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.
5. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (d).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (i) 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 (l) through (o) how the taxes were distributed. Report in column (o) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged
408.1 and 409.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (o) 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.
BALANCE AT
BEGINNING OF YEAR
BALANCE AT END OF
YEAR DISTRIBUTION OF TAXES CHAR
Line
No.
(a)
(b)(c)(d)
(e)(f)
(g)(h)(i)
(j)
(k)
(l)(m)(n)
1 0 0 0
2 Subtotal
Federal Tax 0 0 0
3 Subtotal State
Tax 0 0 0
4 Subtotal Local
Tax 0 0 0
5 Subtotal Other
Tax 0 0 0
6 Property Tax Property Tax Arizona 14,632 0 118,112 96,204 36,540 272,924
7 Property Tax Property Tax California 0 0 4,069,481 4,069,481 0 3,845,342
8 Property Tax Property Tax Colorado 1,750,000 0 1,578,306 1,828,306 1,500,000 1,577,350
9 Property Tax Property Tax Idaho 2,966,298 0 3,563,436 4,402,947 2,126,787 3,563,286
10 Property Tax Property Tax Montana 3,187,865 0 5,592,973 5,987,950 2,792,888 5,592,973
11 Property Tax Property Tax New Mexico 0 0 19,021 19,021 0 19,021
12 Property Tax Property Tax Oregon 0 22,741,356 46,812,965 48,209,880 0 24,138,271 42,710,831
13 Property Tax Property Tax Utah 548,955 10,315,403 66,054,551 55,651,378 636,725 61,286,208
14 Property Tax Property Tax Washington 9,000,000 0 7,757,290 8,157,290 8,600,000 7,617,719
15 Property Tax Property Tax Wyoming 11,534,249 0 26,206,948 24,637,710 13,103,487 26,185,125
16
Goshute
Possessory
Interest
Property Tax Idaho 0 0 30,346 30,346 0 30,346
17
Sho-Ban
Possessory
Interest
Property Tax Utah 0 0 297,208 297,208 0 297,208
18
Navajo
Possessory
Interest
Property Tax Utah 15,000 0 15,907 23,180 7,727 15,907
19 Ute Possessory
Interest Property Tax Colorado 0 0 46,432 46,432 0 46,432
20 Crow
Possessory Tax Property Tax Montana 0 0 91,125 91,125 0 91,125
21
Umatilla
Possessory
Interest
Property Tax Oregon 0 0 148,668 148,668 0 148,668
22 Subtotal
Property Tax 29,016,999 33,056,759 162,402,769 153,697,126 28,804,154 24,138,271 153,300,465
23 Subtotal Real
Estate Tax 0 0 0
24
Federal
Unemployment
Tax
Unemployment
Tax 25,267 0 222,941 12,588 235,620
25
Federal
Unemployment
Tax
Unemployment
Tax Arizona (1)0 640 1,241 (602)
26 Unemployment
Tax
Unemployment
Tax California 358 0 16,492 19,756 (2,906)
Kind of Tax
(See
Instruction 5)
Type of Tax State Tax
Year
Taxes
Accrued
(Account
236)
Prepaid
Taxes
(Include in
Account
165)
Taxes
Charged
During Year
Taxes Paid
During Year Adjustments
Taxes
Accrued
(Account
236)
Prepaid
Taxes
(Included
in
Account
165)
Electric
(Account
408.1, 409.1)
Extraordinary
Items
(Account
409.3)
Adjustme
to Ret.
Earning
(Accoun
439)
27 Unemployment
Tax
Unemployment
Tax Colorado (408)0 638 1,100 (870)
28 Unemployment
Tax
Unemployment
Tax Florida (189)0 567 189 189
29 Unemployment
Tax
Unemployment
Tax Idaho (1,717)0 17,468 26,885 (11,134)
30 Unemployment
Tax
Unemployment
Tax Nevada (384)0 7,218 13,716 (6,882)
31 Unemployment
Tax
Unemployment
Tax Oregon 295,708 4,497 1,325,269 2,444,069 (823,092)4,497
32 Unemployment
Tax
Unemployment
Tax Texas (68)0 213 211 (66)
33 Unemployment
Tax
Unemployment
Tax Utah (18,901)0 277,625 536,692 (277,968)
34 Unemployment
Tax
Unemployment
Tax Washington 217,345 0 113,043 148,347 182,041
35 Unemployment
Tax
Unemployment
Tax Minnesota 5 0 1,771 2,337 (561)
36 Unemployment
Tax
Unemployment
Tax Montana (360)0 640 2,402 (2,122)
37 Unemployment
Tax
Unemployment
Tax Missouri 0 0 234 352 (118)
38 Unemployment
Tax
Unemployment
Tax
South
Carolina (19)0 18 (5)4
39 Unemployment
Tax
Unemployment
Tax Wyoming 3,323 0 20,572 (102,048)125,943
40 Unemployment
Tax
Unemployment
Tax Illinois 0 0 524 1,048 (524)
41 Unemployment
Tax
Unemployment
Tax Indiana 0 0 24 499 (475)
42 Unemployment
Tax
Unemployment
Tax Maryland 0 0 11 207 (196)
43 Unemployment
Tax
Unemployment
Tax
North
Carolina 0 0 296 1,052 (756)
44 Unemployment
Tax
Unemployment
Tax
New
Hampshire 0 0 182 515 (333)
45 Unemployment
Tax
Unemployment
Tax New York 0 0 495 2,089 (1,594)
46 Unemployment
Tax
Unemployment
Tax Pennsylvania 0 0 7 37 (30)
47 Unemployment
Tax
Unemployment
Tax Wisconsin 0 0 1 347 (346)
48
Subtotal
Unemployment
Tax
519,959 4,497 2,006,889 3,113,626 (586,778)4,497
49 Use Tax Sales And Use
Tax California 97,959 0 882,239 915,989 64,209
50 Use Tax Sales And Use
Tax Idaho 31,734 0 286,800 314,357 4,177
51 Use Tax A Sales And Use
Tax Utah 672,577 0 8,189,464 8,298,013 564,028
52 Use Tax B Sales And Use
Tax Utah 1,056,186 0 1,056,186
53 Use Tax Sales And Use
Tax Washington 88,403 0 1,565,363 1,615,260 38,506
54 Use Tax Sales And Use
Tax Wyoming 112,525 0 1,568,708 1,588,338 92,895
55 Subtotal Sales
And Use Tax 2,059,384 0 12,492,574 13,788,143 763,815
56 Federal Income
Tax Income Tax 0 0 (333,980,299)(297,040,925)(a)36,939,374 0 (351,752,881)
57 Income Tax Income Tax Arizona 0 0 (64,729)3,050 (b)67,779 0 (77,036)
58 Franchise -
Income Tax Income Tax California 0 0 (762,535)(965,200)(c)(202,665)0 (1,074,553)
59 Income Tax Income Tax Colorado 0 0 (7,381)(d)7,381 0 (7,568)
60 Income Tax Income Tax Idaho 0 0 (331,524)(662,124)(e)(330,600)0 (571,201)
61
Corporate
License -
Income Tax
Income Tax Montana 0 0 (250,951)(192,695)(f)58,256 0 (294,511)
62 Income Tax Income Tax New Mexico 0 0 (80,794)(57,088)(g)23,706 0 (93,494)
63 Excise - Income
Tax Income Tax Oregon 0 0 (4,561,030)(1,638,227)(h)2,922,803 0 (6,227,260)
64 City of Portland
- Income Tax Income Tax Oregon 0 0 (68,074)(43,900)(i)24,174 0 (76,818)
65 Corporate
Activity Tax Income Tax Oregon 0 0 6,929,853 6,486,528 (j)(443,325)0 6,929,853
66 Metro Business
Income Tax Income Tax Oregon 0 0 (14,469)(k)14,469 0 (14,469)
67 Income Tax Income Tax North
Carolina 0 0 200 200 0 200
68 Public Utility
Tax Income Tax South
Carolina 0 0 25 25 0 25
69 Income Tax Income Tax Utah 0 0 (7,517,230)(3,084,800)(l)4,432,430 0 (9,246,809)
70 Subtotal
Income Tax 0 0 (340,708,938)(297,195,156)43,513,782 0 (362,506,522)
71 Natural Gas
Use Tax Excise Tax Washington 1,892,829 0 5,749,910 7,323,862 318,877
72 Forest Excise
Tax Excise Tax Washington 0 0 10,582 10,582 0
73 Subtotal
Excise Tax 1,892,829 0 5,760,492 7,334,444 318,877
74 Subtotal Fuel
Tax 0 0 0
75
Foreign
Insurance
Premiums
Federal
Insurance Tax 4,054,485 4,054,485 0 4,054,486
76
Subtotal
Federal
Insurance Tax
0 0 4,054,485 4,054,485 0 4,054,486
77 Local Franchise
Tax Franchise Tax California 1,492,200 0 1,340,987 1,385,787 1,447,400 1,340,987
78 Local Franchise
Tax Franchise Tax Oregon 5,287,015 0 34,510,600 33,871,231 5,926,384 34,510,600
79 Local Franchise
Tax Franchise Tax Utah 0 0 8,405 8,405 0 8,405
80 Local Franchise
Tax Franchise Tax Washington 0 0 0
81 Local Franchise
Tax Franchise Tax Wyoming 285,900 0 1,968,430 1,983,330 271,000 1,968,430
82 Subtotal
Franchise Tax 7,065,115 0 37,828,422 37,248,753 7,644,784 37,828,422
83
Subtotal
Miscellaneous
Other Tax
0 0 0
84 Subtotal Other
Federal Tax 0 0 0
85 KWh Other State
Tax Idaho 18,194 0 58,921 60,234 16,881 58,921
86 Wholesale
Energy
Other State
Tax Montana 65,000 0 268,115 263,115 70,000 268,115
87 Energy License Other State
Tax Montana 85,000 0 374,275 369,275 90,000 374,275
88 Commerce Tax Other State
Tax Nevada 12,000 0 25,369 25,369 12,000 25,369
89 Department of
Energy
Other State
Tax Oregon 0 757,036 1,438,991 1,363,911 0 681,956 1,438,991
90 Public Utility
Tax
Other State
Tax Washington 1,600,000 0 15,634,904 15,784,904 1,450,000 15,634,904
91 Business and
Occupation Tax
Other State
Tax Washington 3,200 0 26,544 26,344 3,400 26,544
92 Wind
Generation Tax
Other State
Tax Wyoming 2,207,731 0 2,091,917 2,207,500 2,092,148 2,091,917
93 Annual Report Other State
Tax Wyoming 0 0 125,857 125,857 0 125,857
94 Subtotal Other
State Tax 3,991,125 757,036 20,044,893 20,226,509 3,734,429 681,956 20,044,893
95 Subtotal Other
Property Tax 0 0 0
96 Subtotal Other
Use Tax 0 0 0
97 Subtotal Other
Advalorem Tax 0 0 0
98
Subtotal Other
License And
Fees Tax
0 0 0
99 Federal FICA
Tax Payroll Tax 627,923 24,707 43,580,002 43,203,075 1,004,850 24,707
100 Tri-Met Transit
Tax Payroll Tax Oregon (387,200)0 1,336,068 1,445,538 (496,670)
101 Lane Transit
Tax Payroll Tax Oregon 0 0 1,810 1,810 0
102 Family and
Medical Leave Payroll Tax Colorado 0 0 (213)213
103 Family and
Medical Leave Payroll Tax Oregon 0 0 237,787 (237,787)
104 Family and
Medical Leave Payroll Tax Washington 626 0 84,109 99,802 (15,067)
105 Workers Benefit
Fund EE Payroll Tax Oregon 0 0 15,125 (15,125)
106 Workers Benefit
Fund ER Payroll Tax Oregon 0 0 15,125 (15,125)
107 Long Term Care
EE Payroll Tax Washington 0 0 (24,281)24,281
108 Subtotal
Payroll Tax 241,349 24,707 45,001,989 44,993,768 0 249,570 24,707
109 Subtotal
Advalorem Tax 0 0 0
110 Subtotal Other
Allocated Tax 0 0 0
111 Subtotal
Severance Tax 0 0 0
112 Subtotal
Penalty Tax 0 0 0
113
Subtotal Other
Taxes And
Fees
0 0
40 TOTAL 44,786,760 33,842,999 (51,116,425)(12,738,302)43,513,782 40,928,851 24,849,431 (147,278,256)
FERC FORM NO. 1 (ED. 12-96)
Page 262-263
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents income taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent company.
(b) Concept: TaxAdjustments
Account 143, Other accounts receivable, which represents a reclassification of the balance.
(c) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents income taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent company.
(d) Concept: TaxAdjustments
Account 143, Other accounts receivable, which represents a reclassification of the balance.
(e) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents income taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent company.
(f) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents income taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent company.
(g) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents income taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent company.
(h) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents income taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent company.
(i) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents income taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent company.
(j) Concept: TaxAdjustments
$ (465,625) Account 146, Accounts receivable from other associated companies 22,300 Account 182.3, Other Regulatory Assets, which represents a reclassification of the balance$ (443,325)
(k) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents income taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent company.
(l) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents income taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parent company.
(m) Concept: TaxesIncurredOther
Account 182.3, Other Regulatory Assets
(n) Concept: TaxesIncurredOther
$ 143,604 Account 408.2, Taxes other than income taxes, other income and deductions 80,535 Account 107, Construction work in progress$ 224,139
(o) Concept: TaxesIncurredOther
Account 408.2, Taxes other than income taxes, other income and deductions
(p) Concept: TaxesIncurredOther
Account 408.2, Taxes other than income taxes, other income and deductions
(q) Concept: TaxesIncurredOther
$ 24,115 Account 408.2, Taxes other than income taxes, other income and deductions 176,233 Account 589, Rents 3,901,786 Account 107, Construction work in progress$ 4,102,134
(r) Concept: TaxesIncurredOther
$ 58,890 Account 408.2, Taxes other than income taxes, other income and deductions 4,709,453 Account 107, Construction work in progress$ 4,768,343
(s) Concept: TaxesIncurredOther
$ 34,820 Account 408.2, Taxes other than income taxes, other income and deductions 104,751 Account 107, Construction work in progress$ 139,571
(t) Concept: TaxesIncurredOther
$ 2,893 Account 408.2, Taxes other than income taxes, other income and deductions 18,930 Account 589, Rents$ 21,823
(u) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(v) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(w) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(x) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(y) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(z) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(aa) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(ab) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(ac) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(ad) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(ae) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(af) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(ag) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(ah) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(ai) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(aj) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(ak) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(al) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(am) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(an) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(ao) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(ap) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(aq) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(ar) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(as) Concept: TaxesIncurredOther
Charged to same account as related goods.
(at) Concept: TaxesIncurredOther
Charged to same account as related goods.
(au) Concept: TaxesIncurredOther
Charged to same account as related goods.
(av) Concept: TaxesIncurredOther
Charged to same account as related goods.
(aw) Concept: TaxesIncurredOther
Charged to same account as related goods.
(ax) Concept: TaxesIncurredOther
Account 409.2, Income Taxes - Federal, which represents income tax applicable to other income and deductions.
(ay) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(az) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(ba) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(bb) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(bc) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(bd) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(be) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(bf) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(bg) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(bh) Concept: TaxesIncurredOther
Account 151, Fuel stock
(bi) Concept: TaxesIncurredOther
Account 408.2, Taxes other than income taxes, other income and deductions
(bj) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(bk) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(bl) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
(bm) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
FERC FORM NO. 1 (ED. 12-96)
Page 262-263
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
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.
Deferred for Year Allocations to Current Year's Income
Line
No.
Account Subdivisions
(a)
Balance at
Beginning of Year
(b)
Account No.
(c)
Amount
(d)
Account No.
(e)
Amount
(f)
Adjustments
(g)
Balance at
End of
Year
(h)
Average
Period of
Allocation
to Income
(i)
ADJUSTMENT
EXPLANATION
(j)
1 Electric Utility
2 3%
3 4%
4 7%
5 10%1,465,134 (a)
411.4 759,697 705,437 39.3 years
6 30 2,318,551 (b)
420 153,688 2,164,863 24.0 years
7 Idaho (Pre-2013)13,781 (c)
411.4 5,183 8,598 39.3 years
8 Idaho 20,920 (d)
420 4,291 16,629 30.0 years
8 TOTAL Electric (Enter Total of lines
2 thru 7)3,818,386 922,859 2,895,527
9 Other (List separately and show
3%, 4%, 7%, 10% and TOTAL)
10 `
11 Idaho (nonutility)5,914,053 190 1,186,380 420 (233,300)(e)(167,298)7,166,435 30.0 years
47 OTHER TOTAL 5,914,053 1,186,380 (233,300)(167,298)7,166,435
48 GRAND TOTAL 9,732,439 1,186,380 689,559 (167,298)10,061,962
FERC FORM NO. 1 (ED. 12-89)
Page 266-267
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: AccumulatedDeferredInvestmentTaxCreditsAllocationToIncomeAccountNumber
Internal Revenue Code 46(f) 2
(b) Concept: AccumulatedDeferredInvestmentTaxCreditsAllocationToIncomeAccountNumber
Internal Revenue Code 46(f) 1
(c) Concept: AccumulatedDeferredInvestmentTaxCreditsAllocationToIncomeAccountNumber
Internal Revenue Code 46(f) 2
(d) Concept: AccumulatedDeferredInvestmentTaxCreditsAllocationToIncomeAccountNumber
Internal Revenue Code 46(f) 1
(e) Concept: AccumulatedDeferredInvestmentTaxCreditsAdjustments
Represents an adjustment to the prior year balance that was made in the current year.
FERC FORM NO. 1 (ED. 12-89)
Page 266-267
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
OTHER DEFERRED CREDITS (Account 253)
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.
DEBITS
Line
No.
Description and Other Deferred Credits
(a)
Balance at Beginning of
Year
(b)
Contra Account
(c)
Amount
(d)
Credits
(e)
Balance at End of Year
(f)
1 Working Capital Deposits 6,045,034 131, 242 6,255,703 210,669
2 Reclamation Costs - Trapper Mine 11,029,366 131 2,253,222 1,444,821 10,220,965
3 Western Coal Carriers Benefits Obligation 6,323,000 131, 557 524,000 394,000 6,193,000
4 Deferred Compensation Plans 6,638,669 131 1,474,668 1,619,552 6,783,553
5 Long-Term Incentive Plan 23,708,167 131 4,013,379 2,729,533 22,424,321
6 Regulated Environmental Liabilities 63,757,944 131, 182.3 10,033,151 29,313,140 83,037,933
7 Non-Regulated Environmental Liabilities 1,611,328 131, 426.5 167,166 74,381 1,518,543
8 (a)
Unearned Joint Use Pole Contact Revenue 3,623,694 454 8,748,149 9,530,727 4,406,272
9 Miscellaneous Security Deposits 100,169 100,169
10 Lease Incentives 31,062 931 31,062
11 Cowlitz/Lewis River Operations and Maintenance (1)141,046 242, 539 502,795 361,749
12 Employee Housing Security Deposits 21,600 131 3,700 1,200 19,100
13 Cogeneration Bonds - Sunnyside 413,417 131 413,417
14 MCI F.O.G. Wire Lease (1)559,486 454 1,202,045 771,072 128,513
15 Accrued Right-of-Way Obligations 1,973,642 289,358 2,263,000
16 (b)
Facility Use Fee 696,594 451, 456 171,425 125,393 650,562
17 IT Software Licenses 2,628,111 107, 131 5,663,377 13,600,000 10,564,734
18 Deer Creek Accrued Royalties 15,447,803 654,597 16,102,400
19 Deferred Revenue - Other 1,298 185 1,298
20 Transmission Security Deposits 34,466,820 131 6,989,610 30,605,596 58,082,806
21 Transmission Service Deposits 3,627,826 131, 235, 456 2,604,074 3,330,495 4,354,247
22 Transmission Study Deposits for Financial Security 106,333,090 131 51,083,470 70,207,200 125,456,820
23 Transmission Study Deposits for Site Control 1,460,000 131 540,000 930,000 1,850,000
24 Transmission Deposits for Cluster Studies 33,718,405 131, 235, 242 17,820,846 30,001,260 45,898,819
25 Vendor Retention 68,708,063 232 68,708,063
26 Project Development Security Deposits 4,186,306 4,186,306
47 TOTAL 393,065,634 189,204,620 200,381,049 404,242,063
FERC FORM NO. 1 (ED. 12-94)
Page 269
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionOfOtherDeferredCredits
The weighted average remaining life is approximately one year.
(b) Concept: DescriptionOfOtherDeferredCredits
The weighted average remaining life is approximately eight years.
FERC FORM NO. 1 (ED. 12-94)
Page 269
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
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.
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line
No.
Account
(a)
Balance at
Beginning of Year
(b)
Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Account 411.1
(d)
Amounts Debited
to Account 410.2
(e)
Amounts
Credited to
Account 411.2
(f)
Account
Credited
(g)
Amount
(h)
Account
Debited
(i)
Amount
(j)
Balance at
End of Year
(k)
1 Accelerated Amortization
(Account 281)
2 Electric
3 Defense Facilities
4 Pollution Control Facilities 134,154,544 2,140,018 13,316,622 122,977,940
5 Other
5.1 Other:
8 TOTAL Electric (Enter Total of
lines 3 thru 7)134,154,544 2,140,018 13,316,622 122,977,940
9 Gas
10 Defense Facilities
11 Pollution Control Facilities
12 Other
12.1 Other:
15 TOTAL Gas (Enter Total of lines
10 thru 14)
16 Other
16.1 Other
16.2 Other
17 TOTAL (Acct 281) (Total of 8, 15
and 16)134,154,544 2,140,018 13,316,622 122,977,940
18 Classification of TOTAL
19 Federal Income Tax 109,382,448 433,398 9,546,203 100,269,643
20 State Income Tax 24,772,096 1,706,620 3,770,419 22,708,297
21 Local Income Tax
FERC FORM NO. 1 (ED. 12-96)
Page 272-273
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
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.
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line
No.
Account
(a)
Balance at
Beginning of Year
(b)
Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Account 411.1
(d)
Amounts
Debited to
Account 410.2
(e)
Amounts
Credited to
Account 411.2
(f)
Account
Credited
(g)
Amount
(h)
Account
Debited
(i)
Amount
(j)
Balance at
End of Year
(k)
1 Account 282
2 Electric 3,180,346,057 661,763,280 625,191,431 182.3,
254 47,481,486 182.3,
254 83,741,244 3,253,177,664
3 Gas
4 Other (Specify)
5 Total (Total of lines 2 thru 4)3,180,346,057 661,763,280 625,191,431 47,481,486 83,741,244 3,253,177,664
6
7
8
9 TOTAL Account 282 (Total of
Lines 5 thru 8)3,180,346,057 661,763,280 625,191,431 47,481,486 83,741,244 3,253,177,664
10 Classification of TOTAL
11 Federal Income Tax 2,612,756,057 426,040,150 394,447,551 36,946,086 66,583,500 2,673,986,070
12 State Income Tax 567,590,000 235,723,130 230,743,880 10,535,400 17,157,744 579,191,594
13 Local Income Tax
FERC FORM NO. 1 (ED. 12-96)
Page 274-275
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
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.
3. Provide in the space below explanations for Page 276. Include amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line
No.
Account
(a)
Balance at
Beginning of Year
(b)
Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Account 411.1
(d)
Amounts Debited
to Account 410.2
(e)
Amounts
Credited to
Account 411.2
(f)
Account
Credited
(g)
Amount
(h)
Account
Debited
(i)
Amount
(j)
Balance at
End of Year
(k)
1 Account 283
2 Electric
3 Regulatory Assets 461,407,300 234,418,935 67,704,273 33,146,200 18,942,593 182.3,
190, 283 20,774,199 182.3,
190, 283 9,854,854 631,406,224
4 Other 103,923,747 14,373,925 9,375,433 729,255 407,119 190, 283 77,659,245 190, 283 12,146,060 43,731,190
9 TOTAL Electric (Total of lines
3 thru 8)565,331,047 248,792,860 77,079,706 33,875,455 19,349,712 98,433,444 22,000,914 675,137,414
10 Gas
11
12
13
14
15
16
17 TOTAL Gas (Total of lines 11
thru 16)
18 TOTAL Other
19 TOTAL (Acct 283) (Enter Total
of lines 9, 17 and 18)565,331,047 248,792,860 77,079,706 33,875,455 19,349,712 98,433,444 22,000,914 675,137,414
20 Classification of TOTAL
21 Federal Income Tax 461,161,457 199,558,224 59,552,493 27,798,880 15,955,539 80,356,929 18,037,902 550,691,502
22 State Income Tax 104,169,590 49,234,636 17,527,213 6,076,575 3,394,173 18,076,515 3,963,012 124,445,912
23 Local Income Tax
NOTES
FERC FORM NO. 1 (ED. 12-96)
Page 276-277
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
OTHER REGULATORY LIABILITIES (Account 254)
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.
DEBITS
Line
No.
Description and Purpose of Other Regulatory
Liabilities
(a)
Balance at Beginning of
Current Quarter/Year
(b)
Account Credited
(c)
Amount
(d)
Credits
(e)
Balance at End of Current
Quarter/Year
(f)
1 (a)
DSM Balancing Account - CA 440, 442, 444 687,916 1,107,046 419,130
2 (b)
DSM Balancing Account - ID 1,209,745 440, 442, 444 1,209,745
3 (c)
DSM Balancing Account - WA 3,368,458 440, 442, 444 21,622,283 18,638,468 384,643
4 (d)
Oregon Energy Conservation Charge 7,098,718 440, 442, 444 61,886,734 60,732,303 5,944,287
5 (e)
Deferred Excess Net Power Costs - CA 1,990,883 555 1,990,883
6 (f)
Deferred Excess RECs in Rates - UT 1,042,066 456 1,042,066 2,122,995 2,122,995
7 (g)
Deferred Excess RECs in Rates - WY 296,308 456 404,450 282,921 174,779
8 (h)
Decoupling Mechanism - WA 3,541,565 440, 442 7,698,620 12,512,644 8,355,589
9 (i)
Investment Tax Credit 393,958 190 203,765 131 190,324
10 (j)
Deferred Income Tax Electric 1,163,173,420 190, 282, 411.1 225,960,320 68,419,955 1,005,633,055
11 Corporate Activity Tax - OR 174,021 409.1 393,437 371,138 151,722
12 (k)
Excess Income Tax Deferral 9,307,552 440, 442, 444 4,384,308 1,801,545 6,724,789
13 Tax on Bonus Depreciation 376,801 431, 440, 442, 444 376,801
14 (l)
Other Postretirement 35,317,061 (af)3,295,754 9,428,101 41,449,408
15 (m)
Postemployment Costs 9,976,841 (ag)2,069,026 7,907,815
16 (n)
Revenues Subject to Refund - WA 702,026 440, 442, 444 702,026
17 Bridger Mine Depreciation and Reclamation - OR 7,278,878 3,634,602 10,913,480
18 Bridger Mine Depreciation and Reclamation - WA 5,098,816 2,549,408 7,648,224
19 Cholla Unit No. 4 Closure and Decommissioning
Costs - ID 2,430,427 131 254,324 2,176,103
20 Cholla Plant Unit No. 4 Decommissioning Costs - OR 7,970,978 131 1,119,718 6,851,260
21 Cholla Plant Unit No. 4 Decommissioning Costs - UT 18,394,220 131 1,893,452 16,500,768
22 Cholla Plant Unit No. 4 Decommissioning Costs -
WY 244,921 131 629,572 617,828 233,177
23 Deferral of Coal Plant Closure Costs - WA 2,711,472 1,355,735 4,067,207
24 Klamath Hydro Dam Removal - CA 261,061 716 261,777
25 (o)
Unrealized Gain on Derivative Contracts 270,423,988 175, 244 270,423,988
26 (p)
Renewable Portfolio Standards Compliance - OR 154,239 555 154,239
27 (q)
Solar on Multifamily Affordable Housing - CA 7,851,919 456, 908 102,474 2,261,928 10,011,373
28 Emergency Service Resiliency Program - CA 237,960 908 10,004 227,956
29 Solar Incentive Program - UT (Amortization period: 1
year, starting 01/2023)856,498 440, 442, 444, 908 856,498
30 STEP Pilot Program - UT (Amortization period: 1
year, starting 01/2023)11,401,300 131 11,401,300
31 Deferred Independent Evaluator Costs - UT 72,599 72,599
32 Deferred Gains 462,106 462,106
33 (r)(s)
Utah Home Energy Lifeline 1,097,772 142, 232, 440, 442,
444 4,847 719,467 1,812,392
34 (t)
California Energy Savings Assistance Program 31,516 908, 909, 929 454,340 774,358 351,534
35 FERC Rate True-up - OR (Amortization period: 3
years, starting 01/2021)4,022,323 456 4,075,388 53,065
36 (u)
Blue Sky - CA 162,891 440, 442 63,044 88,370 188,217
37 (v)
Blue Sky - OR 1,634,689 440, 442, 555 1,700,277 1,797,558 1,731,970
38 (w)
Blue Sky - ID 181,017 440, 442 38,467 68,211 210,761
39 (x)
Blue Sky - UT 5,382,261 440, 442 2,448,949 3,474,522 6,407,834
40 (y)
Blue Sky - WA 552,166 440, 442 334,854 321,534 538,846
41 (z)
Blue Sky - WY 616,697 440, 442 237,332 233,098 612,463
42 Depreciation Study Deferral - OR (Amortization
period: 3 years, starting 01/2021)2,791,258 440, 442, 444 2,828,004 36,746
43 Deferred Steam Accelerated Depreciation - WA
(Amortization period: 3 years, starting 01/2021)17,418,111 440, 442, 444 17,418,111
44 Direct Access 5-Year Opt Out - OR (Amortization
period: 10 years, starting 02/2016)5,213,862 442 1,769,315 131,961 3,576,508
45 (aa)
Transportation Electrification Program - OR 440, 442, 908, 909 2,075,565 5,803,699 3,728,134
46 Transportation Electrification Program - CA 229,960 12,869 242,829
47 Transportation Electrification Pilot - UT (Amortization
period: 5 years, starting 07/2022)5,044,149 908 7,598,400 6,434,021 3,879,770
48 (ab)
Oregon Clean Fuels Program 9,617,448 908, 909 3,307,870 3,016,641 9,326,219
49 Pryor Mountain - OR (Amortization period: 3 years,
starting 04/2023)364,127 456 87,272 17,490 294,345
50 Pryor Mountain - WA 119,020 72,876 191,896
51 Fly Ash Sales - OR (Amortization period: 1 year,
starting 04/2023)1,700,000 456 1,121,869 68,106 646,237
52 Fly Ash Sales - WA 3,400,000 3,400,000
53 (ac)
Low-Carbon Energy Standards - WY 922 156,939 1,093,317 936,378
54 (ad)
Alternative Rate For Energy (CARE) - CA 32,399 921, 922, 923, 909 32,399
55 (ae)
Arrearage Payments Program - WA 234,000 182.3, 232 234,000
41 TOTAL 1,629,731,766 666,760,945 213,990,078 1,176,960,899
FERC FORM NO. 1 (REV 02-04)
Page 278
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(b) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(c) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(d) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(e) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average amortization period is approximately one year.
(f) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average amortization period is approximately one year.
(g) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average amortization period is approximately one year.
(h) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(i) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average amortization period is approximately 39 years.
(j) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21%, 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.
(k) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average amortization period is approximately two years.
(l) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average amortization period of portion being amortized is approximately 13 years. Substantially represents amounts not yet recognized as a component of net periodic benefit cost.
(m) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average amortization period is approximately five years.
(n) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average amortization period is approximately one year.
(o) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average amortization period is approximately one year.
(p) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average amortization period is approximately one year.
(q) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(r) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(s) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Includes utility assistance billing.
(t) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(u) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(v) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(w) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(x) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(y) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(z) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(aa) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(ab) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(ac) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(ad) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(ae) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Amortization period varies depending on timing of underlying transactions.
(af) Concept: DecreaseInOtherRegulatoryLiabilities
Other postretirement costs are associated with labor and generally charged to operations and maintenance expense and construction work in progress. Other postretirement settlements are charged to Account 926, Employee
pensions and benefits.
(ag) Concept: DecreaseInOtherRegulatoryLiabilities
Other postemployment costs are associated with labor and generally charged to operations and maintenance expense and work in progress.
FERC FORM NO. 1 (REV 02-04)
Page 278
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
Electric Operating Revenues
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.
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 page 108, 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.
Line
No.
Title of Account
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues
Previous year (no
Quarterly)
(c)
MEGAWATT HOURS
SOLD Year to Date
Quarterly/Annual
(d)
MEGAWATT HOURS
SOLD Amount Previous
year (no Quarterly)
(e)
AVG.NO.
CUSTOMERS PER
MONTH Current Year
(no Quarterly)
(f)
AVG.NO.
CUSTOMERS
PER MONTH
Previous
Year (no
Quarterly)
(g)
1
2 2,230,105,420 2,078,412,458 18,158,770 18,425,415 1,806,004 1,775,303
3
4 1,870,885,495 1,678,840,782 20,491,480 19,570,243 226,900 225,281
5 1,338,645,686 1,324,779,894 17,938,466 19,058,783 32,888 32,930
6 15,218,250 14,513,894 107,612 109,655 3,252 3,534
7
8
9
10 5,454,854,851 5,096,547,028 56,696,328 57,164,096 2,069,044 2,037,048
11 (a)192,214,530 (d)293,666,727 2,910,669 4,836,292
12 5,647,069,381 5,390,213,755 59,606,997 62,000,388 2,069,044 2,037,048
13 (3,239,918)
14 5,647,069,381 5,393,453,673 59,606,997 62,000,388 2,069,044 2,037,048
15
16 15,886,767 8,373,236
17 (b)7,472,581 7,685,047
18 4,980
19 19,597,604 19,493,725
20
21 (c)70,610,905 50,383,628
22 170,206,800 187,147,115
23
24
25
26 283,774,657 273,087,731
27 5,930,844,038 5,666,541,404
Line12, column (b) includes $ 295,002,000 of unbilled revenues.
Line12, column (d) includes 3,062,910 MWH relating to unbilled revenues
FERC FORM NO. 1 (REV. 12-05)
Page 300-301
Sales of Electricity
(440) Residential Sales
(442) Commercial and Industrial Sales
Small (or Comm.) (See Instr. 4)
Large (or Ind.) (See Instr. 4)
(444) Public Street and Highway Lighting
(445) Other Sales to Public Authorities
(446) Sales to Railroads and Railways
(448) Interdepartmental Sales
TOTAL Sales to Ultimate Consumers
(447) Sales for Resale
TOTAL Sales of Electricity
(Less) (449.1) Provision for Rate Refunds
TOTAL Revenues Before Prov. for Refunds
Other Operating Revenues
(450) Forfeited Discounts
(451) Miscellaneous Service Revenues
(453) Sales of Water and Water Power
(454) Rent from Electric Property
(455) Interdepartmental Rents
(456) Other Electric Revenues
(456.1) Revenues from Transmission of
Electricity of Others
(457.1) Regional Control Service Revenues
(457.2) Miscellaneous Revenues
Other Miscellaneous Operating Revenues
TOTAL Other Operating Revenues
TOTAL Electric Operating Revenues
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: SalesForResale
For a complete list of the number of customers during 2023 see pages 310-311, Sales for resale in this Form No. 1. For a complete list of the number of customers during the prior year see pages 310-311, Sales for resale
in PacifiCorp's December 31, 2022 Form No. 1.
(b) Concept: MiscellaneousServiceRevenues
Account 451, Miscellaneous service revenues, includes the following items that were $250,000 or greater during the years ended December 31:
2023 2022
Account service charges - application fees, disconnects, reconnects and returned check charges $6,132,257 $6,710,656
Customer contract flat rate billings and facility buyout charges $1,335,749 $969,666
(c) Concept: OtherElectricRevenue
Account 456, Other electric revenues, includes the following items that were $250,000 or greater during the years ended December 31:
2023 2022
Amortization of California greenhouse gas allowance revenue $24,109,723 $11,984,507
Renewable energy credit sales, net of deferrals and amortization $19,365,059 $14,283,978
Fly-ash and by-product sales $11,876,789 $13,842,399
Amortization of Oregon retail customers' allocated share of the incremental Open Access Transmission Tariff revenues associated with FERC Docket No. ER11-3643, net of deferrals $4,075,388 $4,075,388
Amortization of Oregon clean fuels program credits $3,307,870 $1,168,860
Contract assignment revenues $3,235,419 (a)
Revenues from generation interconnection and transmission service request studies $1,635,191 $1,402,859
Steam sales $1,478,981 $999,434
Phase shifting equipment fee from Western Electricity Coordinating Council $442,156 $345,847
Maintenance charges for work on joint-owned transmission facilities $270,389 (a)
Timber sales $250,406 $1,022,015
Wind-based ancillary services (a)$282,834
(a) Amount is less than $250,000.
(d) Concept: SalesForResale
For a complete list of the number of customers during 2023 see pages 310-311, Sales for resale in this Form No. 1. For a complete list of the number of customers during the prior year see pages 310-311, Sales for resale
in PacifiCorp's December 31, 2022 Form No. 1.
FERC FORM NO. 1 (REV. 12-05)
Page 300-301
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
1. The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately
billed must be detailed below.
Line
No.
Description of Service
(a)
Balance at End of Quarter 1
(b)
Balance at End of Quarter 2
(c)
Balance at End of Quarter 3
(d)
Balance at End of Year
(e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL
FERC FORM NO. 1 (NEW. 12-05)
Page 302
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
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 Page 310.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. 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.
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of
Customers
(d)
KWh of Sales Per
Customer
(e)
Revenue Per KWh Sold
(f)
1 CALIFORNIA - 06BLSKY01R - BLUESKY
ENERGY 0.0000
2 CALIFORNIA - 06CHCK000R-CA RES CHECK M 1 0.0000
3 CALIFORNIA - 06LNX00311 - LINE EXT 80%
GUARANTEE 72 0.0000
4 CALIFORNIA - 06NBDDL136-NET BL LOW INC
RES DEL NORTE 40 3,990 4 10,000 0.0998
5 CALIFORNIA - 06NBLDL136-NET BILLING LOW
INC-RES 169 18,484 16 10,563 0.1094
6 CALIFORNIA - 06NBLDN136-NET BLNG LOW
INC-RES DELNORTE 357 35,457 39 9,154 0.0993
7 CALIFORNIA - 06NETBL136-CALIFORNIA NET
BILLING RES 1,155 120,851 116 9,957 0.1046
8 CALIFORNIA - 06NETMT135 - CA RES NET
METERING 3,681 332,490 539 6,829 0.0903
9 CALIFORNIA - 06OALT015R-OUTD AR LGT SR 239 69,060 256 934 0.2890
10 CALIFORNIA - 06RESD000D-RES SRVC 182,119 21,030,946 17,304 10,525 0.1155
11 CALIFORNIA - 06RESDDL06-CA LOW INCOME 125,372 14,622,586 11,133 11,260 0.1166
12 CALIFORNIA - 06RGNSV025-CA SMALL
GENERAL SVC-RES 1,357 68,949 473 2,869 0.0508
13 CALIFORNIA - 06RNB25136-CA RES NET BILL
GEN SVC<20 KW (198)1 0.0000
14 CALIFORNIA - 06RNM25135 - CA NET MTR, GEN
SVC-RES (349)1 0.0000
15 CALIFORNIA - 06RESD0DM9 - MULTI FAMILY 162 12,516 6 27,000 0.0773
16 CALIFORNIA - 06RESD0DS8-MULT FAM SBMET 1,932 136,246 18 107,333 0.0705
17 CALIFORNIA - INCOME TAX DEFERRAL
ADJUSTMENTS 150,956 0.0000
18 CALIFORNIA - REVENUE_ACCOUNTING
ADJUSTMENTS (803,971)0.0000
19 CALIFORNIA - REVENUE ADJUSTMENT -
DEFERRED NPC 99,192 0.0000
20 CALIFORNIA - 06RESD00DN - CA RES SRVC -
DEL NORTE CTY 78,556 9,143,381 7,062 11,124 0.1164
21 CALIFORNIA - DSM REVENUE-RESIDENTIAL 386,835 0.0000
22 CALIFORNIA - BLUE SKY REVENUE-
RESIDENTIAL 56,943 0.0000
23 CALIFORNIA - OTHER CUSTOMER RETAIL
REVENUE 4,918 0.0000
24 IDAHO - 07BLSKY01R-BLUESKY ENERGY 0.0000
25 IDAHO - 07LNX00010-MNTHLY 80%GUAR 919 0.0000
26 IDAHO - 07NBL36136-ID TOU RES NET BILLING 1,488 70,250 155 9,600 0.0472
27 IDAHO - 07NETBL136-ID RES NET BILLING 6,792 638,300 869 7,807 0.0940
28 IDAHO - 07NETMT135 - ID RESIDENTIAL NET
METERING 9,127 978,967 1,132 8,063 0.1073
29 IDAHO - 07NMT36135-IDAHO TIME-OF-DAY RES
NET MTR 3,689 268,531 263 14,027 0.0728
30 IDAHO - 07OALT07AR-SECURITY AR LG 85 20,344 107 794 0.2393
31 IDAHO - 07RESD0001-RES SRVC 615,268 74,049,966 59,947 10,264 0.1204
32 IDAHO - 07RESD0036-RES SRVC-OPTIO 170,272 18,060,055 9,736 17,489 0.1061
33 IDAHO - 07RGNSV06A-ID LRG GENERAL SVC-
RES 358 31,639 4 89,500 0.0884
34 IDAHO - 07RGNSV23A-ID SMALL GENERAL
SVC-RES 10,899 1,241,255 1,160 9,396 0.1139
35 IDAHO - 07RN23A136-RES NET BILLING SMALL
GEN SVC 6 (1,044)3 2,000 (0.1740)
36 IDAHO - 07RNM23135-RES USE NET MTR
SMALL GEN SVC 307 26,402 9 34,111 0.0860
37 IDAHO - 07UPPL000R-BASE SCH FALL 2 0.0000
38 IDAHO - DSM REVENUE-RESIDENTIAL 2,700,088 0.0000
39 IDAHO - BLUE SKY REVENUE-RESIDENTIAL 35,228 0.0000
40 IDAHO - REVENUE_ACCOUNTING
ADJUSTMENTS 573,143 0.0000
41 OREGON - 01CHCK000R-RES CHECK MTR 1 0.0000
42 OREGON - 01COST0004 - 01RESD0004 5,367,092 331,726,626 0.0618
43 OREGON - 01COST0006 - 01RESD0006 5,286 287,934 0.0545
44 OREGON - 01COSTR023, OR RES GEN SRV,
COST BASED 96,139 5,799,238 0.0603
45 OREGON - 01COSTR028, OR RES GEN
SVC>30KW CST BSD 46,575 2,677,501 0.0575
46 OREGON - 01FXRENEWR - Fixed Renewable
Blue Sky (1)0.0000
47 OREGON - 01HABIT004 - 01RESD0004 62,176 3,838,930 0.0617
48 OREGON - 01HABTR023-RES GEN SVC
HABITAT BLND 196 12,056 0.0615
49 OREGON - 01LNX00102-LINE EXT 80% G 15 0.0000
50 OREGON - 01LNX00109-REF/NREF ADV +13,512 0.0000
51 OREGON - 01NETMT135-NET METERING 6,950,816 14,937 0.0000
52 OREGON - 01NMT06135-RES TOU PILOT NET
METERING 24,853 54 0.0000
53 OREGON - 01NMT07135-OR RES NET
METERING LOW INC 127,628 230 0.0000
54 OREGON - 01NMTOU135-TOU NET METERING 35,220 61 0.0000
55 OREGON - 01OALTB15R-OR OUTD AR LGT RES 1,819 294,383 2,201 826 0.1618
56 OREGON - 01PTOU0004 - 01RESD0004 12,658 770,200 0.0608
57 OREGON - 01PTOURB23-RES GEN SVC; TOU
SUPPLY SVC 31 1,817 0.0586
58 OREGON - 01RENEW004 - 01RESD0004 513,248 31,702,323 0.0618
59 OREGON - 01RENWR023-RENEW USAGE SPLY
SVC-GEN SVC 620 37,995 0.0613
60 OREGON - 01RESD0004-RES SRVC 355,460,905 485,572 0.0000
61 OREGON - 01RESD0006-RES TIME-OF-DA 304,188 379 0.0000
62 OREGON - 01RESD0007-OR RESIDENTIAL LOW
INCOME 25,261,249 32,810 0.0000
63 OREGON - 01RESD004T - RES Time Option 727,801 817 0.0000
64 OREGON - 01RESD007T-OR TOU RESIDENTIAL
LOW INCOME 47,289 56 0.0000
65 OREGON - 01RESD0607-OR RES TOU PILOT
LOW INC 15,870 21 0.0000
66 OREGON - 01RGNS2807-RES GEN SVC > 30 KW
LOW INC 11,183 1 0.0000
67 OREGON - 01RGNSB023-SMALL GENERAL
SVC-RES 8,694,398 16,851 0.0000
68 OREGON - 01RGNSB028 - GENERAL SVC > 30
KW - RES 1,650,665 218 0.0000
69 OREGON - 01RGNSB029-OR RES GEN SVC
TOU PILOT 0.0000
70 OREGON - 01RGNSB23T-RES GEN SVC TOU
PORTFOLIO 2,340 3 0.0000
71 OREGON - 01RNETM023-NET METER
RESIDENTIAL GEN SVC 145,225 341 0.0000
72 OREGON - 01RNETM028-NET METER
RESIDENTIAL GEN SVC 85,759 7 0.0000
73 OREGON - 01UPPL000R-BASE SCH FALL 2 0.0000
74 OREGON - 01VIR04136-OR RES VOLUME
INCENTIVE 482,849 458 0.0000
75 OREGON - 01VIR06136-OR RES VOLUME
INCENTIVE 1,933 3 0.0000
76 OREGON - 01VIR07136-OR RES VOLUME
INCNTV LOW INC 5,651 7 0.0000
77 OREGON - REVENUE_ACCOUNTING
ADJUSTMENTS (1,106,712)0.0000
78 OREGON - SOLAR FEED-IN REVENUE 1,916,315 0.0000
79 OREGON - OTHER CUSTOMER RETAIL
REVENUE 941,297 0.0000
80 OREGON - COMMUNITY SOLAR REVENUE 405,180 0.0000
81 OREGON - DSM REVENUE-RESIDENTIAL 28,260,766 0.0000
82 OREGON - BLUE SKY REVENUE-RESIDENTIAL 658,005 0.0000
83 UTAH - 08BLSKY01R-BLUESKY ENERGY (4)0.0000
84 UTAH - 08CFR00001-MTH FACILITY S 568 0.0000
85 UTAH - 08CGENR136-UT RES TRANSITION
GENERATION 631 69,549 71 8,887 0.1102
86 UTAH - 08CGNSL136-UT RES TRANSITION GEN-
SOLEIL 3,369 340,900 600 5,615 0.1012
87 UTAH - 08CGR01136-UTAH RESIDENTIAL
TRANS GEN 152,689 16,619,276 17,118 8,920 0.1088
88 UTAH - 08CGR01137-UT RES CUST
GENERATION 137 138,848 15,188,106 17,322 8,016 0.1094
89 UTAH - 08CGR02136-UT RES TOU TRANSITION
GEN 235 24,858 23 10,217 0.1058
90 UTAH - 08CGR02137-UT RES TOU CUST GEN
137 262 27,727 29 9,034 0.1058
91 UTAH - 08CGR03136-UTAH LOW INC RES
TRANS GEN 1,016 110,473 115 8,835 0.1087
92 UTAH - 08CGR03137-UT LOW INC RES CUST
GEN 137 658 72,162 83 7,928 0.1097
93 UTAH - 08CGR06136-RES USE, GEN SVC RATE,
MANUAL 241 23,313 2 120,500 0.0967
94 UTAH - 08CGR23136-RESIDENTIAL SMALL GEN
SVC 658 59,395 9 73,111 0.0903
95 UTAH - 08CGR23137-RES SM GEN SVC - CUST
GEN 137 386 39,787 35 11,029 0.1031
96 UTAH - 08CGR2E136-UT RES EV TOU PILOT-
TRAN GEN 361 29,487 31 11,645 0.0817
97 UTAH - 08CGR2E137-UT RES EV TOU PILOT
CUST GEN 880 70,066 70 12,571 0.0796
98 UTAH - 08CGRA1137-UT RES CUST GEN
AGGEGATED 271 30,317 41 6,610 0.1119
99 UTAH - 08CGRW1136-UT RES TRANS GEN-
WATTSMART 95 10,429 13 7,308 0.1098
100 UTAH - 08CGRW1137-UT RES CUST GEN 137-
WATTSMART 4,890 547,326 867 5,640 0.1119
101 UTAH - 08CGS23136-RES SMALL GEN SVC
MANUAL 605 62,832 51 11,863 0.1039
102 UTAH - 08CGW2E137-RES EV TOU PILOT-CUST
GEN 137 4 333 1 4,000 0.0834
103 UTAH - 08CHCK000R-UT RES CHECK M 1 0.0000
104 UTAH - 08COOLKPRR - Utah Cool Keeper
Program 1 0.0000
105 UTAH - 08CRA23137-UT RES SML GEN SVC 137
AGGREG 5 654 1 5,000 0.1308
106 UTAH - 08LNX00001-MTHLY 80% GUAR 8,215 0.0000
107 UTAH - 08LNX00013-80% MNTHLY MIN 24,345 0.0000
108 UTAH - 08LNX00108-ANN COST MTHLY 1,224 0.0000
109 UTAH - 08MHTP0006-MOBILE HOME & TRAILER 11,104 838,313 9 1,233,778 0.0755
110 UTAH - 08MHTP0023-MOBILE HOME & TRAILER 143 11,193 1 143,000 0.0783
111 UTAH - 08NETAGFEE-> 6 NET METER
AGGREGATION FEE 925 3 0.0000
112 UTAH - 08NETMT135 - Net Metering 164,513 19,267,283 29,546 5,568 0.1171
113 UTAH - 08NETMW135-UT RES NET METER-
WATTSMART 25 3,119 8 3,125 0.1247
114 UTAH - 08NMT03135-LOW INCOME RES NET
METERING 1,449 156,618 191 7,547 0.1081
115 UTAH - 08OALT007R-SECURITY AR LG 2,025 346,222 2,136 948 0.1710
116 UTAH - 08PTLD000R-POST TOP LIGHT 1 72 2 500 0.0721
117 UTAH - 08RCG23136-RES NET METER, SMALL
GEN SVC 222 20,537 15 14,800 0.0925
118 UTAH - 08RESD0001-RES SRVC 7,338,621 799,452,437 827,114 8,873 0.1089
119 UTAH - 08RESD0002-RES SRVC-OPTIO 4,039 434,903 442 9,138 0.1077
120 UTAH - 08RESD0003-LIFELINE PRGRM 144,229 15,487,506 18,736 7,698 0.1074
121 UTAH - 08RESD002E-RES ELCTRC VEHICLE
TOU PILOT 11,483 1,046,982 765 15,010 0.0912
122 UTAH - 08RESD003E-UT RES LOW INC ELEC V
TOU PLT 37 3,896 3 12,333 0.1053
123 UTAH - 08RGNSV006-GEN SRVC-RES 126,884 9,533,909 315 402,806 0.0751
124 UTAH - 08RGNSV008-UT RESIDENTIAL
GENERAL SVC 740 52,534 1 740,000 0.0710
125 UTAH - 08RGNSV023-GEN SRVC-RES 105,965 11,278,655 14,491 7,312 0.1064
126 UTAH - 08RGNSV06A-UT SMALL GENERAL SVC-
RES-TOU 8,698 688,130 30 289,933 0.0791
127 UTAH - 08RNM06135 - UT NET MTR, GEN SVC-
RES 3,529 288,487 11 320,818 0.0817
128 UTAH - 08RNM23135 - UT NET MTR, GEN SVC-
RES 1,492 179,788 415 3,595 0.1205
129 UTAH - 08RNM6A135-RES GEN SVC NET
METERING 141 13,069 3 47,000 0.0927
130 UTAH - 08RTCVLNGA-TCV LNX GAR 1,858 0.0000
131 UTAH - 08SSLR0001 - RESIDENTIAL SUBSCRB
SOLAR 27,085 3,225,797 0.1191
132 UTAH - 08SSLR0003-RES LOW INC SUBSCR
SOLAR 272 32,541 22 12,364 0.1196
133 UTAH - 08SSLRRG23-RES SMALL GEN SV
SUBSCR SOLAR 51 7,394 17 3,000 0.1450
134 UTAH - 08UPPL000R-BASE SCH FALL 1 0.0000
135 UTAH - REVENUE_ACCOUNTING
ADJUSTMENTS 1,162,844 0.0000
136 UTAH - REVENUE ADJUSTMENT - DEFERRED
NPC 39,904,316 0.0000
137 UTAH - SOLAR FEED-IN REVENUE 0.0000
138 UTAH - OTHER CUSTOMER RETAIL REVENUE 671,060 0.0000
139 UTAH - DSM REVENUE-RESIDENTIAL 11,815,767 0.0000
140 UTAH - BLUE SKY REVENUE-RESIDENTIAL 1,634,904 0.0000
141 WASHINGTON - 02BLSKY01R-BLUESKY
ENERGY 0.0000
142 WASHINGTON - 02CHCK000R-WA RES CHECK
M 1 0.0000
143 WASHINGTON - 02LNX00109-REF/NREF ADV +1,101 0.0000
144 WASHINGTON - 02NETMT135 - WA RES NET
METERING 23,346 2,731,652 2,409 9,691 0.1170
145 WASHINGTON - 02NMT17135-WA RES BILL
ASSIST NET MTR 102 11,689 12 8,500 0.1146
146 WASHINGTON - 02NMT18135-WA 3 PHASE RES
NET MTR 6 1,130 2 3,000 0.1883
147 WASHINGTON - 02NMT19135-RES TOU PILOT
NET METERING 5 731 2 2,500 0.1461
148 WASHINGTON - 02OALTB15R-WA OUTD AR LGT
RES 871 110,250 962 905 0.1266
149 WASHINGTON - 02RESD0016-WA RES SRVC 1,504,837 168,208,818 101,244 14,863 0.1118
150 WASHINGTON - 02RESD0017-BILL ASSISTANC 128,614 14,403,320 8,163 15,756 0.1120
151 WASHINGTON - 02RESD0018-WA 3 PHASE RES 2,107 258,790 73 28,863 0.1228
152 WASHINGTON - 02RESD018X-WA 3 PHASE RES 245 29,068 10 24,500 0.1186
153 WASHINGTON - 02RESD019T-WA RESIDENTIAL
TOU PILOT 353 38,118 23 15,348 0.1080
154 WASHINGTON - 02RGNSB024-WA SMALL
GENERAL SVC-RES 21,768 2,971,665 3,413 6,378 0.1365
155 WASHINGTON - 02RGNSB029-RES GEN SVC
TOU PILOT 4 705 1 4,000 0.1762
156 WASHINGTON - 02RGNSB036-RES LRG GEN
SVC < 1000 KW 2,608 248,918 5 521,600 0.0954
157 WASHINGTON - 02RNM24135-RES NET METER
SMALL GEN SVC 413 55,914 67 6,164 0.1354
158 WASHINGTON - RESIDENTIAL CUSTOMER BILL
CREDITS (149,770)0.0000
159 WASHINGTON - INCOME TAX DEFERRAL
ADJUSTMENTS 820,898 0.0000
160 WASHINGTON - REVENUE ADJUSTMENT -
DEFERRED NPC 1,055,092 0.0000
161 WASHINGTON - REVENUE_ACCOUNTING
ADJUSTMENTS (8,033,556)0.0000
162 WASHINGTON - DSM REVENUE-RESIDENTIAL 9,933,366 0.0000
163 WASHINGTON - BLUE SKY REVENUE-
RESIDENTIAL 304,925 0.0000
164 WASHINGTON - ALT REVENUE PROGRAM
ADJUSTMENTS 14,381,865 0.0000
165 WYOMING - 05LNX00102-LINE EXT 80% G 581 0.0000
166 WYOMING - 05LNX00109-REF/NREF ADV + -A 286 0.0000
167 WYOMING - 05NETMT135 - EXPERIMENTAL
PARTIAL REQ -A 3,349 408,011 456 7,344 0.1218
168 WYOMING - 05NMT19135-RES NET METER TOU
PILOT 11 1,358 1 11,000 0.1234
169 WYOMING - 05OALT015R-OUTD AR LGT SR -A 752 88,139 913 824 0.1172
170 WYOMING - 05RESD0002-WY RES SRVC -A 918,557 101,796,515 103,822 8,847 0.1108
171 WYOMING - 05RESD0019-WY RES TOU PILOT -
A 194 18,938 15 12,933 0.0976
172 WYOMING - 05RGNSV025-WY SMALL GENERAL
SVC-RES -A 10,204 1,251,099 1,561 6,537 0.1226
173 WYOMING - 05RNM25135-WY RES SMALL GEN
SVC NET MTR 401 1 0.0000
174 WYOMING - INCOME TAX DEFERRAL
ADJUSTMENTS 243,539 0.0000
175 WYOMING - REVENUE ADJUSTMENT -
DEFERRED NPC (384,430)0.0000
176 WYOMING - REVENUE_ACCOUNTING
ADJUSTMENTS 42,106 0.0000
177 WYOMING - DSM REVENUE-RESIDENTIAL -A 691,256 0.0000
178 WYOMING - DSM REVENUE-RESIDENTIAL GEN
SVC -A 45,532 0.0000
179 WYOMING - BLUE SKY REVENUE-RESIDENTIAL
-A 197,711 0.0000
180 WYOMING - OTHER CUSTOMER RETAIL
REVENUE 89,077 0.0000
181 WYOMING - 05RESD0002-WY RES SRVC -B 120,042 13,335,067 12,867 9,330 0.1111
182 WYOMING - 05RESD0019-WY RES TOU PILOT -
B 21 2,106 2 10,500 0.1003
183 WYOMING - 05RGNSV025-WY SMALL GENERAL
SVC-RES -B 636 93,983 154 4,130 0.1478
184 WYOMING - 05LNX00109-REF/NREF ADV + -B 5,880 0.0000
185 WYOMING - 05NETMT135 - EXPERIMENTAL
PARTIAL REQ -B 1,393 176,649 220 6,332 0.1268
186 WYOMING - 05OALT015R-OUTD AR LGT SR -B 65 8,931 80 813 0.1374
187 WYOMING - 09RES00002 1 0.0000
188 WYOMING - 09RESD0002 3 0.0000
189 WYOMING - DSM REVENUE-RESIDENTIAL -B 91,598 0.0000
190 WYOMING - DSM REVENUE-RESIDENTIAL GEN
SVC -B 1,774 0.0000
191 WYOMING - BLUE SKY REVENUE-RESIDENTIAL
-B 21,627 0.0000
192 LESS MULTIPLE BILLINGS (26,625)
41 TOTAL Billed Residential Sales 18,318,625 2,228,991,420 1,806,004 10,055 0.1228
42 TOTAL Unbilled Rev. (See Instr. 6)(159,855)1,114,000 0.0001
43 TOTAL 18,158,770 2,230,105,420 1,806,004 10,055 0.1229
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
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 Page 310.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. 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.
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of
Customers
(d)
KWh of Sales Per
Customer
(e)
Revenue Per KWh Sold
(f)
1 CALIFORNIA - 06GNSV0025-CA GEN SRVC 52,852 6,895,509 6,521 8,105 0.1305
2 CALIFORNIA - 06GNSV025F-GEN SRVC-< 20 911 153,910 83 10,976 0.1689
3 CALIFORNIA - 06GNSV0A32-GEN SRVC-20 KW 93,908 14,915,668 1,164 80,677 0.1588
4 CALIFORNIA - 06LGSV048T-LRG GEN SERV 26,788 2,857,487 9 2,976,444 0.1067
5 CALIFORNIA - 06NMT48135-CA GEN SVC NET
MTR->500 KW 2,612 261,239 1 2,612,000 0.1000
6 CALIFORNIA - 06LGSV0A36-LRG GEN SRVC-O 54,812 7,321,795 135 406,015 0.1336
7 CALIFORNIA - 06LNX00102-LINE EXT 80% G 10,293 0 0.0000
8 CALIFORNIA - 06LNX00109-REF/NREF ADV +93,952 0 0.0000
9 CALIFORNIA - 06LNX00110-REF/NREF ADV +1,481 0 0.0000
10 CALIFORNIA - 06LNX00300 - 80% MONTHLY MIN
GUAR + 80%918 0 0.0000
11 CALIFORNIA - 06LNX00311 - LINE EXT 80%
GUARANTEE 15,672 0 0.0000
12 CALIFORNIA - 06NBL25136-CA NET BILL GEN
SVC < 20 KW 31 2,584 7 4,429 0.0833
13 CALIFORNIA - 06NBL32136-CA NET BILL GEN
SVC >= 20 KW 364 57,008 5 72,800 0.1566
14 CALIFORNIA - 06NMT36135-CA GEN SVC NET
MTR->100 KW 3,308 462,438 5 551,333 0.1398
15 CALIFORNIA - 06OALT015N-OUTD AR LGT SR 568 165,027 429 1,324 0.2905
16 CALIFORNIA - 06RCFL0042-AIRWAY & ATHLE 180 40,745 37 4,865 0.2264
17 CALIFORNIA - 06NMT25135-CA GEN SVC NET
MTR<20KW 273 32,300 45 6,067 0.1183
18 CALIFORNIA - 06NMT32135-CA GEN SVC NET
MTR>20KW 3,819 621,275 35 109,114 0.1627
19 CALIFORNIA - INCOME TAX DEFERRAL
ADJUSTMENTS 92,368 0 0.0000
20 CALIFORNIA - REVENUE_ACCOUNTING
ADJUSTMENTS (452,667)0 0.0000
21 CALIFORNIA - REVENUE ADJUSTMENT -
DEFERRED NPC 60,695 0 0.0000
22 CALIFORNIA - DSM REVENUE-COMMERCIAL 197,350 0 0.0000
23 CALIFORNIA - BLUE SKY REVENUE-
COMMERCIAL 4,269 0 0.0000
24 CALIFORNIA - OTHER CUSTOMER RETAIL
REVENUE 3,009 0 0.0000
25 IDAHO - 07GNSV0006-GEN SRVC-LRG P 242,365 21,522,931 1,012 239,491 0.0888
26 IDAHO - 07GNSV0009-GEN SRVC-HI VO 55,557 3,722,868 3 18,519,000 0.0670
27 IDAHO - 07GNSV0023-GEN SRVC-SML P 202,852 20,484,753 8,348 24,299 0.1010
28 IDAHO - 07GNSV0035-GEN SRVCOPTION 325 30,811 3 108,333 0.0948
29 IDAHO - 07GNSV006A-GEN SRVC-LRG P 19,807 1,825,450 158 124,572 0.0922
30 IDAHO - 07GNSV023A-GEN SRVC-SML P 30,334 3,053,794 1,268 23,923 0.1007
31 IDAHO - 07GNSV023F-GEN SRVC SML P 6 1,877 4 1,500 0.3129
32 IDAHO - 07GNSV035A-GEN SRVCOPTION 50 7,212 1 50,000 0.1442
33 IDAHO - 07LNX00010-MNTHLY 80%GUAR 25,091 0 0.0000
34 IDAHO - 07LNX00035-ADV 80%MO GUAR 219,643 0 0.0000
35 IDAHO - 07LNX00040-ADV+REFCHG+80%22,830 0 0.0000
36 IDAHO - 07OALT007N-SECURITY AR LG 222 44,227 159 1,396 0.1992
37 IDAHO - 07OALT07AN-SECURITY AR LG 8 2,269 11 727 0.2836
38 IDAHO - 07TCVLNAGN-TCV LNX ANNUAL GAR-
NON RES 1,352 0 0.0000
39 IDAHO - 07TCVLNXGN-TCV LNX - 80% GAR -
NON RES 1,890 0 0.0000
40 IDAHO - 07LNX00312 - ID LINE EXT 15,251 0 0.0000
41 IDAHO - 07NBL23136-ID NET BILLING SML GEN
SVC 369 25,457 16 23,063 0.0690
42 IDAHO - 07NBL6A136-ID NET BILLING LRG GEN
SVC 242 23,044 1 242,000 0.0952
43 IDAHO - 07NMT06135 - ID NET MTR - LARGE
GEN SVC 3,197 292,938 8 399,625 0.0916
44 IDAHO - 07NMT23135 - ID NET MTR - SMALL
GEN SVC 1,480 131,417 43 34,419 0.0888
45 IDAHO - 07NMT6A135-NET METERING LARGE
GEN SVC 92 8,535 1 92,000 0.0928
46 IDAHO - 07LNX00015-ANNUAL 80%GUAR 489 0 0.0000
47 IDAHO - 07LNX00311 - LINE EXT 80%
GUARANTEE 27,273 0 0.0000
48 IDAHO - 07LNX00300 - 80% MONTHLY MIN
GUAR + 80%1,249 0 0.0000
49 IDAHO - 07LNX00310 80% ANNUAL
GUARANTEE 926 0 0.0000
50 IDAHO - REVENUE_ACCOUNTING
ADJUSTMENTS 337,228 0 0.0000
51 IDAHO - DSM REVENUE-COMMERCIAL 1,479,137 0 0.0000
52 IDAHO - BLUE SKY REVENUE-COMMERCIAL 3,153 1 0.0000
53 OREGON - 01COST0023, OR GEN SRV, COST
BASED 1,032,809 60,002,161 0 0.0581
54 OREGON - 01COST0048 - 01LGSV0048 1,924,493 95,645,095 0 0.0497
55 OREGON - 01COST023F - OR GEN SRV - COST-
BASED 2,902 179,790 0 0.0620
56 OREGON - 01COST23MT-OR GEN SVC COST
TOU MTR 158 8,359 0 0.0529
57 OREGON - 01COST28MT-OR GEN SVC>30KW
COST TOU MTR 2,053 118,209 0 0.0576
58 OREGON - 01COST30MT-LG GEN SVC>200KW
COST TOU MTR 84,514 3,421,688 0 0.0405
59 OREGON - 01COSTB023 - OR GEN SRV, CST-
BSD SPLY 22,132 1,312,409 0 0.0593
60 OREGON - 01COSTEV45-ELECT VEHICLE DC
FAST CHG SVC 10,552 611,353 0 0.0579
61 OREGON - 01COSTL030 - OR LRG GEN SRV,
CST >200 kW 1,004,098 40,679,766 0 0.0405
62 OREGON - 01COSTS028, OR GEN SERV, COST
> 30kW 1,929,992 111,178,355 0 0.0576
63 OREGON - 01COSTS029-OR GEN SVC TOU
PILOT COS>30KW 2 118 0 0.0589
64 OREGON - 01FXRENEWN - Fixed Renewable
Blue Sky 0 0.0000
65 OREGON - 01GNCEL23F-OR SMALL CELL FLAT
RATE 4,259 3 0.0000
66 OREGON - 01GNSB0023, OR GEN SRV, BPA, <
30 kW 1,839,729 2,733 0.0000
67 OREGON - 01GNSB0028, OR GEN SRV, BPA, >
30 kW 2,191,977 254 0.0000
68 OREGON - 01GNSB023T - OR GEN SRV - TOU -
BPA 19,821 33 0.0000
69 OREGON - 01GNSEV45T-ELECT VEHICLE DC
FAST CHG<1MW 771,235 29 0.0000
70 OREGON - 01GNSV0023, OR GEN SRV, < 30 KW 71,658,075 62,200 0.0000
71 OREGON - 01GNSV0028, OR GEN SRV > 30 kW 71,681,473 9,076 0.0000
72 OREGON - 01GNSV0029-OR GEN SVC TOU
PILOT > 30 KW 649 1 0.0000
73 OREGON - 01GNSV023F - OR GEN SRV - FLAT
RATE 9,428 1,674,084 779 12,103 0.1776
74 OREGON - 01GNSV023M - OR GEN SRV,
MANUAL BILL 76 8,803 2 38,000 0.1158
75 OREGON - 01GNSV023T, OR GEN SRV, TOU
Option 159,304 162 0.0000
76 OREGON - 01HABT0023, OR HABITAT BLENDED
SPLY SRV 2,553 150,944 0 0.0591
77 OREGON - 01HABTB023 - OR HABITAT
BLENDED 10 600 0 0.0600
78 OREGON - 01LGSB0030, GEN DEL SRV, > 200
kW(R)1,383,765 19 0.0000
79 OREGON - 01LGSV0030 - OR LRG GEN SRV, >
1000 kW 43,402,400 613 0.0000
80 OREGON - 01LGSV0048-1000KW AND OVR 34,968,594 81 0.0000
81 OREGON - 01LGSV048M-LRG GEN SRVC 1 50,688 3,495,396 1 50,688,000 0.0690
82 OREGON - 01LGSVT030-OR LG GEN
SVC>200KW TOU MTR 3,398,943 28 0.0000
83 OREGON - 01LNX00100-LINE EXT 60% G 6,714 0 0.0000
84 OREGON - 01LNX00102-LINE EXT 80% G 1,254,048 0 0.0000
85 OREGON - 01LNX00103-LINE EXT 80% G 5,945 0 0.0000
86 OREGON - 01LNX00105-CNTRCT $ MIN G 11,657 0 0.0000
87 OREGON - 01LNX00109-REF/NREF ADV +1,394,589 0 0.0000
88 OREGON - 01LNX00110-REF/NREF ADV +12,411 0 0.0000
89 OREGON - 01LNX00311 - LINE EXT 80% G 154,490 0 0.0000
90 OREGON - 01LNX00312 - OR IRG LINE EXT 2,658 0 0.0000
91 OREGON - 01LNX00120 - Line Extension 60% Gar 426,623 0 0.0000
92 OREGON - 01LNX00300 - LINE EXT 80%
GUARANTEE 330,577 0 0.0000
93 OREGON - 01LNX00310-LINE EXTENSION
CONTRACT 1,276 0 0.0000
94 OREGON - 01LPRS047M-PART REQ SRVC 45,113 4,114,953 5 9,022,600 0.0912
95 OREGON - 01NM23T135-OR NET MTR TOU GEN
SVC<30 KW 3,093 2 0.0000
96 OREGON - 01NMB23135-OR NET MTR GEN SVC
<= 30 KW 27,811 70 0.0000
97 OREGON - 01NMB28135-OR NET MTR GEN SVC
> 30 KW 59,915 6 0.0000
98 OREGON - 01NMT23135 - OR NET MTR, GEN, <
30 kW 663,158 613 0.0000
99 OREGON - 01NMT28135 - OR NET MTR, GEN, >
30 kW 2,980,722 339 0.0000
100 OREGON - 01NMT30135 - OR NET MTR, GEN, >
200 kW 2,939,619 40 0.0000
101 OREGON - 01NMT48135-NET METERING GEN
SVC => 1000 691,539 5 0.0000
102 OREGON - 01OALT015N-OUTD AR LGT NR 4,803 573,417 2,679 1,793 0.1194
103 OREGON - 01OALTB15N-OR OUTD AR LGT NR 1,275 201,834 977 1,305 0.1583
104 OREGON - 01PTOU0023, OR GEN SRV, TOU
ENG SPLY SRV 2,241 129,505 0 0.0578
105 OREGON - 01PTOUB023, OR GEN SRV, TOU
SPLY SRV 228 13,629 0 0.0598
106 OREGON - 01RCFL0054-REC FIELD LGT 1,531 153,750 98 15,622 0.1004
107 OREGON - 01RENW0023, OR RENW USAGE
SPLY SRV 12,447 736,477 0 0.0592
108 OREGON - 01RENWB023 - OR RENEWABLE
USAGE 74 4,453 0 0.0602
109 OREGON - 01STDAY023 - OR DAY STD OFR,
SCH 23 3,522 298,172 0 0.0847
110 OREGON - 01STDAY028 - OR DAY STD OFF,
SCH 28 8,405 713,874 0 0.0849
111 OREGON - 01STDAY030 - OR STD DAY OFF,
SCH 27 4,193 280,244 0 0.0668
112 OREGON - 01VIR23136-OR VOLUME INCENTIVE
<= 30 KW 238,139 124 0.0000
113 OREGON - 01VIR28136-OR VOLUME INCENTIVE
> 30 KW 687,267 87 0.0000
114 OREGON - 01VIR30136-OR VOLUME INCENTIVE
> 200 kW 274,267 4 0.0000
115 OREGON - 01VIR48136-OR VOLUME INCENTIVE
> 1000 KW 118,175 1 0.0000
116 OREGON - 01LGSB0048 - LG GEN SVC >
1000KW (R)949,721 2 0.0000
117 OREGON - 01LGSV028M - OR LGSV, <1000 kW,
Manual 467 43,799 1 467,000 0.0938
118 OREGON - 01GNSV0728 - OR GEN SVC DIR
ACCESS >30KW 298,374 14 0.0000
119 OREGON - 01GNSV0730 -OR GEN SVC DIR
ACCESS >200KW 2,226,769 18 0.0000
120 OREGON - 01GNSV0748 LG GEN SVC DIR
ACCESS 1000KW+1,598,572 4 0.0000
121 OREGON - 01GNSV0848-LG GEN SVC > 1000
DA DEL 1,209,590 1 0.0000
122 OREGON - 01GNSVT023-OR GEN SVC <=30 KW
TOU MTR 12,242 5 0.0000
123 OREGON - 01GNSVT028-OR GEN SVC>30KW
TOU MTR 85,381 7 0.0000
124 OREGON - REVENUE_ACCOUNTING
ADJUSTMENTS 685,051 0 0.0000
125 OREGON - SOLAR FEED-IN REVENUE 1,786,993 0 0.0000
126 OREGON - OTHER CUSTOMER RETAIL
REVENUE 989,145 0 0.0000
127 OREGON - COMMUNITY SOLAR REVENUE 374,714 0 0.0000
128 OREGON - DSM REVENUE-COMMERCIAL 27,232,621 0 0.0000
129 OREGON - BLUE SKY REVENUE-COMMERCIAL 807,017 101 0.0000
130 UTAH - 08ABL-NRES - APPLICANT BUILT LINE 434 0 0.0000
131 UTAH - 08ABTCLXGN-LINE EXT 80% CONTRACT
MIN 35,752 0 0.0000
132 UTAH - 08CFR00051-MTH FAC SRVCHG 22,201 0 0.0000
133 UTAH - 08CFR00052-ANN FAC SVCCHG 2 0 0.0000
134 UTAH - 08CGA06137-UT GEN SVC CUST GEN
137 85 11,279 1 85,000 0.1327
135 UTAH - 08CGA23137-UT NET MTR SMALL GEN
SVC 341 33,673 17 20,059 0.0987
136 UTAH - 08CGM06136-UT NET METERING
GENERAL SVC 7,254 660,028 11 659,455 0.0910
137 UTAH - 08CGM23136-UTAH NET METER SM
GEN SVC 946 100,720 53 17,849 0.1065
138 UTAH - 08CGM6A136-UTAH GEN SVC TRANS
GEN TOU 5,244 484,115 23 228,000 0.0923
139 UTAH - 08CGM6A137-UT GEN SVC TRANS TOU
MAN 137 1,177 112,724 5 235,400 0.0958
140 UTAH - 08CGN08136-UT NET MTR GEN SVC >
1000 KW 14,958 1,159,164 2 7,479,000 0.0775
141 UTAH - 08CGN06136-UT GEN SVC TRANSITION
GEN 44,541 4,026,211 81 549,889 0.0904
142 UTAH - 08CGN06137-UT GEN SVC CUST GEN
137 15,901 1,535,937 47 338,319 0.0966
143 UTAH - 08CGN23136-UTAH NET METER SMALL
GEN SVC 2,919 291,817 140 20,695 0.1000
144 UTAH - 08CGN23137-UT NET MTR SMALL GEN
SVC 1,892 186,988 81 23,358 0.0988
145 UTAH - 08GNSV0006-GEN SRVC-DISTR 5,109,895 425,560,292 11,928 428,395 0.0833
146 UTAH - 08GNSV0009-GEN SRVC-HI VO 965,243 54,791,532 53 18,212,132 0.0568
147 UTAH - 08GNSV0023-GEN SRVC-DISTR 1,347,243 130,228,235 80,539 16,728 0.0967
148 UTAH - 08GNSV006A-GEN SRVC-ENERG 293,720 34,103,602 2,010 146,129 0.1161
149 UTAH - 08GNSV006M-MNL DIST VOLTG 1 0.0000
150 UTAH - 08GNSV009A-GEN SRVC HI VO 24,145 1,162,990 2 12,072,500 0.0482
151 UTAH - 08GNSV009M-MANL HIGH VOLT 216,609 12,107,339 1 216,609,000 0.0559
152 UTAH - 08GNSV023F-GEN SRVC FIXED 1,295 182,160 129 10,039 0.1407
153 UTAH - 08GNSV06AM-MNL ENERGY TOD 71 6,481 1 71,000 0.0913
154 UTAH - 08GNSV06MN-GNSV DIST VOLT 28,946 2,303,752 463 62,518 0.0796
155 UTAH - 08GNSVDWY6-UT GEN SVC W WYO
DEDUCT MTR 34 5,766 1 34,000 0.1696
156 UTAH - 08LNX00002-MTHLY 80% GUAR 2,114,807 0 0.0000
157 UTAH - 08LNX00004-ANNUAL 80%GUAR 187,694 0 0.0000
158 UTAH - 08LNX00006-FIXD MTHLY MIN 2,882 0 0.0000
159 UTAH - 08LNX00014-80% MIN MNTHLY 2,360,686 0 0.0000
160 UTAH - 08LNX00017-ADV/REF&80%ANN 196,983 0 0.0000
161 UTAH - 08LNX00158-ANNUALCOST MTH 26,746 0 0.0000
162 UTAH - 08LNX00300 - LINE EXT 80% PLUS
MONTHLY 214,012 0 0.0000
163 UTAH - 08LNX00310 - IRR, 80% ANNUAL MIN +
80% ?40,979 0 0.0000
164 UTAH - 08LNX00312 UT IRG LINE EXT 9,816 0 0.0000
165 UTAH - 08NMT06135-UT NET METERING GEN
SVC 117,872 10,156,182 269 438,186 0.0862
166 UTAH - 08NMT08135 - NET METERING GEN SVC 52,399 3,953,655 12 4,366,583 0.0755
167 UTAH - 08NMT23135 - UT NET MTR, GEN, < 25
KW 11,004 1,111,565 801 13,738 0.1010
168 UTAH - 08NMT6A135-NET METERING GEN SVC
TOU 15,094 1,509,478 91 165,868 0.1000
169 UTAH - 08NMT8135M - NET METERING GEN
SVC MANUAL 9,318 826,118 1 9,318,000 0.0887
170 UTAH - 08OALT007N-SECURITY AR LG 7,104 917,921 3,964 1,792 0.1292
171 UTAH - 08PRSV031M-BKUP MNT&SUPPL 175,594 9,979,629 4 43,898,500 0.0568
172 UTAH - 08PTLD000N-POST TOP LIGHT 6 463 2 3,000 0.0772
173 UTAH - 08REFP034M-RENEWABLE QUAL CUST
> 5000 KW 757,303 32,549,030 1 757,303,000 0.0430
174 UTAH - 08REFS032M-UT RENEWABLE FAC &
SUPP PWR 229,612 12,482,086 3 76,537,333 0.0544
175 UTAH - 08SSLR0006-GENERAL SVC SUBSCR
SOLAR 3,942 423,668 12 328,500 0.1075
176 UTAH - 08SSLR0023-SMALL GEN SVC SUBSCR
SOLAR 4,227 457,038 0 0.1081
177 UTAH - 08SSLR06AM-GEN SVC TOU SOLAR
SUBSCR MAN 47,011 5,101,122 359 130,950 0.1085
178 UTAH - 08TCVLNAGN-UTAH LNX ANNUAL GAR
NON RES 6,278 0 0.0000
179 UTAH - 08TCVLNXGN-TCV LNX - 80% GAR -
NON RES 434,705 0 0.0000
180 UTAH - 08TCVLXACN-GAR ADDED CAPACITY
NON RES 19,737 0 0.0000
181 UTAH - 08TOSS015F-TRAFFIC SIG NM 176 15,605 20 8,800 0.0887
182 UTAH - 08TOSS0015-TRAF & OTHER S 3,574 361,181 1,182 3,024 0.1011
183 UTAH - 08MONL0015-MTR OUTDONIGHT 14,736 726,229 687 21,450 0.0493
184 UTAH - REVENUE_ACCOUNTING
ADJUSTMENTS 2,141,866 0 0.0000
185 UTAH - REVENUE ADJUSTMENT - DEFERRED
NPC 50,227,235 0 0.0000
186 UTAH - OTHER CUSTOMER RETAIL REVENUE 846,504 0 0.0000
187 UTAH - 08LNX00311 - LINE EXT 80%
GUARANTEE 284,826 0 0.0000
188 UTAH - 08GNSV0008 - UT GEN SVC TOU >
1000KW 924,481 65,897,932 120 7,640,339 0.0713
189 UTAH - 08GNSV008M - UT GEN SVC TOU >
1000KW 6,291 412,191 2 3,145,500 0.0655
190 UTAH - DSM REVENUE-COMMERCIAL 14,874,010 0 0.0000
191 UTAH - BLUE SKY REVENUE-COMMERCIAL 703,672 0 0.0000
192 WASHINGTON - 02BLSKY01N-BLUESKY
ENERGY 0 0.0000
193 WASHINGTON - 02GN24EV45-WA ELECTRIC
VEHICLE FAST CHG 317 45,998 4 63,400 0.1451
194 WASHINGTON - 02GNSB0024-WA GEN SRVC
DO 28,019 3,279,507 1,495 18,742 0.1170
195 WASHINGTON - 02GNSB0029-WA NON RES
TOU PILOT 0 0.0000
196 WASHINGTON - 02GNSB024F-GEN SRVC
DOM/F 1 229 1 1,000 0.2289
197 WASHINGTON - 02GNSB24FP-WA GEN SVC
SEASONAL 160 65,662 62 2,581 0.4104
198 WASHINGTON - 02GNSV0024-WA GEN SRVC 479,815 53,840,074 15,087 31,803 0.1122
199 WASHINGTON - 02GNSV0029-WA NON RES
TOU PILOT 192 36,273 1 192,000 0.1889
200 WASHINGTON - 02GNSV024F-WA GEN SRVC-FL 1,211 190,083 106 11,425 0.1570
201 WASHINGTON - 02LGSB0036-LRG GEN SVC
IRG 40,089 3,853,458 66 607,409 0.0961
202 WASHINGTON - 02LGSV0036-WA LRG GEN SRV 801,467 75,132,920 875 915,962 0.0937
203 WASHINGTON - 02LGSV048T-LRG GEN SRVC 1 152,960 13,447,521 36 4,248,889 0.0879
204 WASHINGTON - 02LNX00102-LINE EXT 80% G 105,147 0 0.0000
205 WASHINGTON - 02LNX00103-LINE EXT 80% G 43,430 0 0.0000
206 WASHINGTON - 02LNX00105-CNTRCT $ MIN G 2,260 0 0.0000
207 WASHINGTON - 02LNX00109-REF/NREF ADV +194,820 0 0.0000
208 WASHINGTON - 02LNX00110-REF/NREF ADV +16,856 0 0.0000
209 WASHINGTON - 02LNX00112-YR INCURRED CH 669 0 0.0000
210 WASHINGTON - 02LNX00300-LINE EXT 80% G 466,980 0 0.0000
211 WASHINGTON - 02LNX00310 - IRG, 80%
ANNUAL MIN + 80%9,884 0 0.0000
212 WASHINGTON - 02LNX00311 - LINE EXT 80%
GUARANTEE 28,059 0 0.0000
213 WASHINGTON - 02LNX00312 - WA IRG LINE EXT 10,610 0 0.0000
214 WASHINGTON - 02NMB24135-WA NET
METERING 144 28,811 34 4,235 0.2001
215 WASHINGTON - 02OALT015N-WA OUTD AR LGT 1,346 127,431 741 1,816 0.0947
216 WASHINGTON - 02OALTB15N-WA OUTD AR LGT
NR 466 57,939 436 1,069 0.1243
217 WASHINGTON - 02RCFL0054-WA REC FIELD L 361 24,436 24 15,042 0.0677
218 WASHINGTON - 02NMT24135, Net metering, WA 6,806 796,778 175 38,891 0.1171
219 WASHINGTON - 02NMT36135-WA NET METER
LRG SVC < 1000KW 14,754 1,488,971 22 670,636 0.1009
220 WASHINGTON - 02NMT48135-WA LG SVC NET
METER=>1000 KW 11,539 982,163 2 5,769,500 0.0851
221 WASHINGTON - INCOME TAX DEFERRAL
ADJUSTMENTS 754,544 0 0.0000
222 WASHINGTON - REVENUE ADJUSTMENT -
DEFERRED NPC 969,287 0 0.0000
223 WASHINGTON - REVENUE_ACCOUNTING
ADJUSTMENTS (4,042,013)0 0.0000
224 WASHINGTON - DSM REVENUE-COMMERCIAL 7,803,060 0 0.0000
225 WASHINGTON - BLUE SKY REVENUE-
COMMERCIAL 26,924 2 0.0000
226 WASHINGTON - ALT REVENUE PROGRAM
ADJUSTMENTS (18,773,989)0 0.0000
227 WYOMING - 05CHCK000N-WY NRES CHECK 1 0.0000
228 WYOMING - 05GNCEL25F-WYOMING SMALL
CELL FLAT RATE 5 2,695 1 5,000 0.5391
229 WYOMING - 05GNSV0025-WY GEN SRVC -A 224,618 23,107,079 18,543 12,113 0.1029
230 WYOMING - 05GNSV0028-GEN SVC > 15 KW -A 796,696 69,512,024 3,061 260,273 0.0873
231 WYOMING - 05GNSV0029-WY GEN SVC TOU
PILOT -A 1,517 316,656 5 303,400 0.2087
232 WYOMING - 05GNSV025F-GEN SRVC-FL RA -A 984 158,143 171 5,754 0.1607
233 WYOMING - 05LGSV0046-WY LRG GEN SRV 272,429 18,830,943 26 10,478,038 0.0691
234 WYOMING - 05LGSV048T-LRG GENSRV TIM 14,140 988,963 1 14,140,000 0.0699
235 WYOMING - 05LNX00100-LINE EXT 60% G 22,756 0 0.0000
236 WYOMING - 05LNX00102-LINE EXT 80% G -A 941,785 0 0.0000
237 WYOMING - 05LNX00105-CNTRCT $ MIN G 5,685 0 0.0000
238 WYOMING - 05LNX00109-REF/NREF ADV + -A 349,925 0 0.0000
239 WYOMING - 05LNX00110-REF/NREF ADV + -A 3,983 0 0.0000
240 WYOMING - 05LNX00114-TEMP SVC 12MO>127 0 0.0000
241 WYOMING - 05NMT25135 - WY NET MTR, GEN,
< 25 KW -A 649 63,372 48 13,521 0.0976
242 WYOMING - 05NMT28135-NET MTR SMALL GEN
SVC > 15 KW -A 10,000 955,082 30 333,333 0.0955
243 WYOMING - 05OALT015N-OUTD AR LGT SR -A 2,443 240,799 1,514 1,614 0.0986
244 WYOMING - 05RCFL0054-WY REC FIELD L -A 939 46,054 56 16,768 0.0490
245 WYOMING - 05LNX00300 - LINE EXT 80%
GUARANTEE 87,369 0 0.0000
246 WYOMING - 05LNX00311 - LINE EXT 80%
GUARANTEE -A 44,480 0 0.0000
247 WYOMING - INCOME TAX DEFERRAL
ADJUSTMENTS 329,673 0 0.0000
248 WYOMING - REVENUE ADJUSTMENT -
DEFERRED NPC (520,394)0 0.0000
249 WYOMING - REVENUE_ACCOUNTING
ADJUSTMENTS 56,488 0 0.0000
250 WYOMING - DSM REVENUE-SMALL
COMMERCIAL -A 3,250,258 0 0.0000
251 WYOMING - DSM REVENUE-LARGE
COMMERCIAL 150,728 0 0.0000
252 WYOMING - BLUE SKY REVENUE-
COMMERCIAL -A 16,683 1 0.0000
253 WYOMING - OTHER CUSTOMER RETAIL
REVENUE 120,582 0 0.0000
254 WYOMING - 05GNSV0025-WY GEN SRVC -B 32,046 3,273,933 2,571 12,464 0.1022
255 WYOMING - 05GNSV0028-GEN SVC > 15 KW -B 89,922 7,720,128 389 231,162 0.0859
256 WYOMING - 05GNSV0029-WY GEN SVC TOU
PILOT -B 529 113,903 3 176,333 0.2153
257 WYOMING - 05GNSV025F-GEN SRVC-FL RA -B 199 25,644 33 6,030 0.1289
258 WYOMING - 05LNX00102-LINE EXT 80% G -B 110,300 0 0.0000
259 WYOMING - 05LNX00103-LINE EXT 80% G 684 0 0.0000
260 WYOMING - 05LNX00109-REF/NREF ADV + -B 127,615 0 0.0000
261 WYOMING - 05LNX00110-REF/NREF ADV + -B 8,809 0 0.0000
262 WYOMING - 05NMT25135 - WY NET MTR, GEN,
< 25 KW -B 252 21,906 7 36,000 0.0869
263 WYOMING - 05NMT28135-NET MTR SMALL GEN
SVC > 15 KW -B 418 34,857 2 209,000 0.0834
264 WYOMING - 05OALT015N-OUTD AR LGT SR -B 256 27,758 140 1,829 0.1084
265 WYOMING - 05RCFL0054-WY REC FIELD L -B 225 11,020 14 16,071 0.0490
266 WYOMING - 05LNX00311 - LINE EXT 80%
GUARANTEE -B 3,404 0 0.0000
267 WYOMING - DSM REVENUE-SMALL
COMMERCIAL -B 195,572 0 0.0000
268 WYOMING - BLUE SKY REVENUE-
COMMERCIAL -B 753 0 0.0000
269 LESS MULTIPLE BILLINGS (22,735)
41 TOTAL Billed Small or Commercial 20,408,208 1,857,360,495 226,900 90,311 0.0906
42 TOTAL Unbilled Rev. Small or Commercial (See
Instr. 6)83,272 13,525,000 0.0007
43 TOTAL Small or Commercial 20,491,480 1,870,885,495 226,900 90,311 0.0913
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
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 Page 310.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. 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.
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of
Customers
(d)
KWh of Sales Per
Customer
(e)
Revenue Per KWh Sold
(f)
1 CALIFORNIA - 06GNSV0025-CA GEN SRVC 515 62,452 81 6,358 0.1213
2 CALIFORNIA - 06GNSV0A32-GEN SRVC-20 KW 4,086 641,269 22 185,727 0.1569
3 CALIFORNIA - 06LGSV048T-LRG GEN SERV 51,431 5,488,318 9 5,714,556 0.1067
4 CALIFORNIA - 06LGSV0A36-LRG GEN SRVC-O 5,507 832,082 12 458,917 0.1511
5 CALIFORNIA - INCOME TAX DEFERRAL
ADJUSTMENTS 24,374 0.0000
6 CALIFORNIA - REVENUE_ACCOUNTING
ADJUSTMENTS (70,579)0.0000
7 CALIFORNIA - REVENUE ADJUSTMENT -
DEFERRED NPC 16,016 0.0000
8 CALIFORNIA - DSM REVENUE-INDUSTRIAL 3,173 0.0000
9 CALIFORNIA - BLUE SKY REVENUE-
INDUSTRIAL 1,782 0.0000
10 CALIFORNIA - OTHER CUSTOMER RETAIL
REVENUE 794 0.0000
11 IDAHO - 07CFR00001-MTH FACILITY S 1,293 0.0000
12 IDAHO - 07GNSV0006-GEN SRVC-LRG P 70,089 5,570,652 101 693,950 0.0795
13 IDAHO - 07GNSV0009-GEN SRVC-HI VO 52,614 3,907,765 13 4,047,231 0.0743
14 IDAHO - 07GNSV0023-GEN SRVC-SML P 16,259 1,573,871 303 53,660 0.0968
15 IDAHO - 07GNSV006A-GEN SRVC-LRG P 1,657 167,869 20 82,850 0.1013
16 IDAHO - 07GNSV009M-MANL HIGH VOLT 134,593 8,398,153 1 134,593,000 0.0624
17 IDAHO - 07GNSV023A-GEN SRVC-SML P 1,875 201,374 130 14,423 0.1074
18 IDAHO - 07GNSV023S-IDAHO TRAFFIC
SIGNALS 5 694 1 5,000 0.1388
19 IDAHO - 07LNX00035-ADV 80%MO GUAR 1,675 0.0000
20 IDAHO - 07LNX00108-ANN COST MTHLY 1,996 0.0000
21 IDAHO - 07LNX00311 - LINE EXT 80%
GUARANTEE 520 0.0000
22 IDAHO - 07NMT23135 - ID NET MTR - SMALL
GEN SVC 30 2,949 1 30,000 0.0983
23 IDAHO - 07OALT007N-SECURITY AR LG 12 2,705 16 750 0.2254
24 IDAHO - 07OALT07AN-SECURITY AR LG 65 0.0000
25 IDAHO - 07SPCL0001 1,314,200 86,710,909 1 1,314,200,000 0.0660
26 IDAHO - REVENUE_ACCOUNTING
ADJUSTMENTS 118,681 0.0000
27 IDAHO - DSM REVENUE-INDUSTRIAL 1,081,184 0.0000
28 IDAHO - BLUE SKY REVENUE-INDUSTRIAL 13 0.0000
29 OREGON - 01COST0023, OR GEN SRV, COST
BASED 18,065 1,049,602 0.0581
30 OREGON - 01COST0048 - 01LGSV0048 1,159,182 59,370,245 0.0512
31 OREGON - 01COST28MT-OR GEN SVC>30KW
COST TOU MTR 368 19,328 0.0525
32 OREGON - 01COST30MT-LG GEN SVC>200KW
COST TOU MTR 37,678 1,527,868 0.0406
33 OREGON - 01COSTB023 - OR GEN SRV, CST-
BSD SPLY 136 7,685 0.0565
34 OREGON - 01COSTL030 - OR LRG GEN SRV,
CST >200 kW 142,300 5,762,179 0.0405
35 OREGON - 01COSTS028, OR GEN SERV, COST
> 30kW 77,880 4,480,239 0.0575
36 OREGON - 01GNSB0023, OR GEN SRV, BPA, <
30 kW 10,909 12 0.0000
37 OREGON - 01GNSB0028, OR GEN SRV, BPA, >
30 kW 5,187 1 0.0000
38 OREGON - 01GNSV0023, OR GEN SRV, < 30 KW 1,274,831 936 0.0000
39 OREGON - 01GNSV0028, OR GEN SRV > 30 kW 3,511,463 377 0.0000
40 OREGON - 01GNSV023F - OR GEN SRV - FLAT
RATE 1 116 0.1156
41 OREGON - 01GNSV023M - OR GEN SRV,
MANUAL BILL 305 1 0.0000
42 OREGON - 01GNSV023T, OR GEN SRV, TOU
Option 2,904 3 0.0000
43 OREGON - 01GNSV0730 -OR GEN SVC DIR
ACCESS >200KW 1,697 0.0000
44 OREGON - 01GNSV0748 LG GEN SVC DIR
ACCESS 1000KW+1,314,703 2 0.0000
45 OREGON - 01GNSVT028-OR GEN SVC>30KW
TOU MTR 8,945 0.0000
46 OREGON - 01LGSV0030 - OR LRG GEN SRV, >
1000 kW 8,353,093 106 0.0000
47 OREGON - 01LGSV0048-1000KW AND OVR 28,065,155 73 0.0000
48 OREGON - 01LGSV048M-LRG GEN SRVC 1 42,413 3,387,739 3 14,137,667 0.0799
49 OREGON - 01LGSV30MN-OR LG GEN SVC>200
KW NO AUTO 55,197 1 0.0000
50 OREGON - 01LGSVT030-OR LG GEN
SVC>200KW TOU MTR 1,948,170 12 0.0000
51 OREGON - 01LNX00102-LINE EXT 80% G 87,092 0.0000
52 OREGON - 01LNX00109-REF/NREF ADV +106 0.0000
53 OREGON - 01LNX00300 - LINE EXT 80%
GUARANTEE 13,780 0.0000
54 OREGON - 01LPRS047M-PART REQ SRVC 1,104 515,030 1 1,104,000 0.4665
55 OREGON - 01NMT23135 - OR NET MTR, GEN, <
30 kW 6,112 5 0.0000
56 OREGON - 01NMT28135 - OR NET MTR, GEN, >
30 kW 97,858 8 0.0000
57 OREGON - 01NMT30135 - OR NET MTR, GEN, >
200 kW 107,494 2 0.0000
58 OREGON - 01OALT015N-OUTD AR LGT NR 240 24,878 110 2,182 0.1037
59 OREGON - 01OALTB15N-OR OUTD AR LGT NR 3 388 3 1,000 0.1294
60 OREGON - 01PTOU0023, OR GEN SRV, TOU
ENG SPLY SRV 38 2,162 0.0569
61 OREGON - 01RENW0023, OR RENW USAGE
SPLY SRV 87 5,310 0.0610
62 OREGON - 01VIR23136-OR VOLUME INCENTIVE
<= 30 KW 1,135 1 0.0000
63 OREGON - 01VIR28136-OR VOLUME INCENTIVE
> 30 KW 18,672 2 0.0000
64 OREGON - 01VIR30136-OR VOLUME INCENTIVE
> 200 kW 103,494 1 0.0000
65 OREGON - REVENUE_ACCOUNTING
ADJUSTMENTS 380,004 0.0000
66 OREGON - SOLAR FEED-IN REVENUE 415,746 0.0000
67 OREGON - OTHER CUSTOMER RETAIL
REVENUE 239,588 0.0000
68 OREGON - COMMUNITY SOLAR REVENUE 89,238 0.0000
69 OREGON - DSM REVENUE-INDUSTRIAL 7,210,788 0.0000
70 OREGON - BLUE SKY REVENUE-INDUSTRIAL 353,381 4 0.0000
71 UTAH - 08CFR00051-MTH FAC SRVCHG 15,065 0.0000
72 UTAH - 08CGM23136-UTAH NET METER SM
GEN SVC 12 1,395 1 12,000 0.1163
73 UTAH - 08CGN06136-UT GEN SVC TRANSITION
GEN 1,255 105,298 1 1,255,000 0.0839
74 UTAH - 08CGN06137-UT GEN SVC CUST GEN
137 247 19,990 1 247,000 0.0809
75 UTAH - 08CGN23136-UTAH NET METER SMALL
GEN SVC 42 4,134 1 42,000 0.0984
76 UTAH - 08CGN23137-UT NET MTR SMALL GEN
SVC 59 5,892 2 29,500 0.0999
77 UTAH - 08GNSV0006-GEN SRVC-DISTR 545,319 47,048,446 879 620,386 0.0863
78 UTAH - 08GNSV0009-GEN SRVC-HI VO 2,773,219 154,810,061 97 28,589,887 0.0558
79 UTAH - 08GNSV0023-GEN SRVC-DISTR 47,968 4,689,476 3,003 15,973 0.0978
80 UTAH - 08GNSV006A-GEN SRVC-ENERG 56,411 6,544,086 234 241,073 0.1160
81 UTAH - 08GNSV006M-MNL DIST VOLTG 67 19,828 0.2959
82 UTAH - 08GNSV009A-GEN SRVC HI VO 17,148 1,521,467 6 2,858,000 0.0887
83 UTAH - 08GNSV009M-MANL HIGH VOLT 694,890 36,932,038 11 63,171,818 0.0531
84 UTAH - 08GNSV023F-GEN SRVC FIXED 1 635 0.6350
85 UTAH - 08GNSV06MN-GNSV DIST VOLT 510 49,701 15 34,000 0.0975
86 UTAH - 08LNX00002-MTHLY 80% GUAR 718,374 0.0000
87 UTAH - 08LNX00014-80% MIN MNTHLY 46,514 0.0000
88 UTAH - 08LNX00017-ADV/REF&80%ANN 640 0.0000
89 UTAH - 08LNX00300 - LINE EXT 80% PLUS
MONTHLY 76,461 0.0000
90 UTAH - 08LNX00311 - LINE EXT 80%
GUARANTEE 40 0.0000
91 UTAH - 08OALT007N-SECURITY AR LG 789 87,887 363 2,174 0.1114
92 UTAH - 08TOSS0015-TRAF & OTHER S 57 5,134 8 7,125 0.0901
93 UTAH - 08MONL0015-MTR OUTDONIGHT 7 366 2 3,500 0.0523
94 UTAH - 08NMT06135-UT NET METERING GEN
SVC 2,352 214,282 6 392,000 0.0911
95 UTAH - 08NMT23135 - UT NET MTR, GEN, < 25
KW 148 17,997 17 8,706 0.1216
96 UTAH - 08NMT6A135-NET METERING GEN SVC
TOU 5,592 646,727 14 399,429 0.1157
97 UTAH - 08PRSV031M-BKUP MNT&SUPPL 116,711 7,242,375 3 38,903,667 0.0621
98 UTAH - 08SPCL0001 582,245 35,231,916 1 582,245,000 0.0605
99 UTAH - 08SPCL0002 36,716 1,819,908 1 36,716,000 0.0496
100 UTAH - 08SPCL0003 1,164,893 111,628,473 1 1,164,893,000 0.0958
101 UTAH - 08SSLR0006-GENERAL SVC SUBSCR
SOLAR 315 25,032 1 315,000 0.0795
102 UTAH - 08SSLR0023-SMALL GEN SVC SUBSCR
SOLAR 221 26,501 32 6,906 0.1199
103 UTAH - 08SSLR06AM-GEN SVC TOU SOLAR
SUBSCR MAN 10,270 999,103 31 331,290 0.0973
104 UTAH - 08TCVLNXGN-TCV LNX - 80% GAR -
NON RES 20,887 0.0000
105 UTAH - REVENUE_ACCOUNTING
ADJUSTMENTS 1,096,848 0.0000
106 UTAH - REVENUE ADJUSTMENT - DEFERRED
NPC 37,639,567 0.0000
107 UTAH - 08GNSV0008 - UT GEN SVC TOU >
1000KW 915,771 67,541,882 89 10,289,562 0.0738
108 UTAH - 08GNSV008M - UT GEN SVC TOU >
1000KW 22,823 1,811,434 4 5,705,750 0.0794
109 UTAH - SOLAR FEED-IN REVENUE 0.0000
110 UTAH - OTHER CUSTOMER RETAIL REVENUE 631,056 0.0000
111 UTAH - DSM REVENUE-INDUSTRIAL 11,145,939 0.0000
112 UTAH - BLUE SKY REVENUE-INDUSTRIAL 110,262 6 0.0000
113 WASHINGTON - 02GNSB0024-WA GEN SRVC
DO 770 96,545 41 18,780 0.1254
114 WASHINGTON - 02GNSB24FP-WA GEN SVC
SEASONAL 0.0000
115 WASHINGTON - 02GNSV0024-WA GEN SRVC 15,006 1,684,268 319 47,041 0.1122
116 WASHINGTON - 02GNSV024F-WA GEN SRVC-FL 29 8,636 3 9,667 0.2978
117 WASHINGTON - 02LGSV0036-WA LRG GEN SRV 72,956 7,375,531 82 889,707 0.1011
118 WASHINGTON - 02LGSV048M-WA LRG GEN
SRV 239,868 18,792,407 1 239,868,000 0.0783
119 WASHINGTON - 02LGSV048T-LRG GEN SRVC 1 197,393 17,140,082 28 7,049,750 0.0868
120 WASHINGTON - 02NMB24135-WA NET
METERING 130 1 0.0000
121 WASHINGTON - 02NMT24135, Net metering, WA 62 11,620 5 12,400 0.1874
122 WASHINGTON - 02NMT36135-WA NET METER
LRG SVC < 1000KW 9 12,229 1 9,000 1.3588
123 WASHINGTON - 02OALT015N-WA OUTD AR LGT 82 6,619 36 2,278 0.0807
124 WASHINGTON - 02OALTB15N-WA OUTD AR LGT
NR 26 2,950 14 1,857 0.1134
125 WASHINGTON - 02PRSV47TM-LRG PART
REQMT 1,645 322,115 1 1,645,000 0.1958
126 WASHINGTON - 02LGSB0036-LRG GEN SVC
IRG 930 138,407 7 132,857 0.1488
127 WASHINGTON - INCOME TAX DEFERRAL
ADJUSTMENTS 379,188 0.0000
128 WASHINGTON - REVENUE ADJUSTMENT -
DEFERRED NPC 483,694 0.0000
129 WASHINGTON - REVENUE_ACCOUNTING
ADJUSTMENTS 629,948 0.0000
130 WASHINGTON - BLUE SKY REVENUE-
INDUSTRIAL 0.0000
131 WASHINGTON - DSM REVENUE-INDUSTRIAL 2,349,914 0.0000
132 WASHINGTON - ALT REVENUE PROGRAM
ADJUSTMENTS (738,158)0.0000
133 WYOMING - 05GNSV0025-WY GEN SRVC -A 18,642 1,808,122 1,095 17,025 0.0970
134 WYOMING - 05GNSV0028-GEN SVC > 15 KW -A 238,943 17,439,308 386 619,023 0.0730
135 WYOMING - 05GNSV0029-WY GEN SVC TOU
PILOT 1,049 86,618 7 149,857 0.0826
136 WYOMING - 05GNSV025F-GEN SRVC-FL RA 26 4,326 8 3,250 0.1664
137 WYOMING - 05LGSV0046-WY LRG GEN SRV -A 1,591,149 105,579,272 58 27,433,603 0.0664
138 WYOMING - 05LGSV046M-WY LRG GEN SRV 10,364 786,853 1 10,364,000 0.0759
139 WYOMING - 05LGSV048M-TOU>1000KW MAN -A 321,900 18,657,717 1 321,900,000 0.0580
140 WYOMING - 05LGSV048T-LRG GENSRV TIM -A 1,981,586 112,507,326 11 180,144,182 0.0568
141 WYOMING - 05LNX00100-LINE EXT 60% G 95,319 0.0000
142 WYOMING - 05LNX00102-LINE EXT 80% G -A 402,239 0.0000
143 WYOMING - 05LNX00105-CNTRCT $ MIN G 31,126 0.0000
144 WYOMING - 05LNX00109-REF/NREF ADV + -A 108,812 0.0000
145 WYOMING - 05LNX00300 - LINE EXT 80%
GUARANTEE 128,902 0.0000
146 WYOMING - 05LNX00311 - LINE EXT 80%
GUARANTEE 14,599 0.0000
147 WYOMING - 05OALT015N-OUTD AR LGT SR -A 64 5,038 37 1,730 0.0787
148 WYOMING - 05PRSV033M-PART SERV REQ -A 1,029,945 73,484,022 10 102,994,500 0.0713
149 WYOMING - INCOME TAX DEFERRAL
ADJUSTMENTS 1,458,624 0.0000
150 WYOMING - REVENUE ADJUSTMENT -
DEFERRED NPC (2,302,455)0.0000
151 WYOMING - REVENUE_ACCOUNTING
ADJUSTMENTS 250,709 0.0000
152 WYOMING - DSM REVENUE-SMALL
INDUSTRIAL -A 700,348 0.0000
153 WYOMING - DSM REVENUE-LARGE
INDUSTRIAL -A 2,236,539 0.0000
154 WYOMING - BLUE SKY REVENUE-INDUSTRIAL -
A 344 0.0000
155 WYOMING - OTHER CUSTOMER RETAIL
REVENUE 533,509 0.0000
156 WYOMING - 05GNSV0025-WY GEN SRVC -B 2,972 316,024 276 10,768 0.1063
157 WYOMING - 05GNSV0028-GEN SVC > 15 KW -B 52,435 3,940,622 66 794,470 0.0752
158 WYOMING - 05GNSV028M-GEN SVC > 15 KW
MANUAL BILL 3,861 240,181 3 1,287,000 0.0622
159 WYOMING - 05LGSV0046-WY LRG GEN SRV -B 9,345 646,284 2 4,672,500 0.0692
160 WYOMING - 05LGSV048M-TOU>1000KW MAN -B 107,844 7,529,911 2 53,922,000 0.0698
161 WYOMING - 05LGSV048T-LRG GENSRV TIM -B 833,995 53,402,678 14 59,571,071 0.0640
162 WYOMING - 05LNX00102-LINE EXT 80% G -B 2,396,074 0.0000
163 WYOMING - 05LNX00109-REF/NREF ADV + -B 24,475 0.0000
164 WYOMING - 05NMT25135 - WY NET MTR, GEN,
< 25 KW 44 3,757 1 44,000 0.0854
165 WYOMING - 05OALT015N-OUTD AR LGT SR -B 7 518 4 1,750 0.0741
166 WYOMING - 05PRSV033M-PART SERV REQ -B 1,620 335,786 1 1,620,000 0.2073
167 WYOMING - DSM REVENUE-SMALL
INDUSTRIAL -B 78,902 0.0000
168 WYOMING - DSM REVENUE-LARGE
INDUSTRIAL -B 581,637 0.0000
169 WYOMING - BLUE SKY REVENUE-INDUSTRIAL -
B 140 0.0000
170 LESS MULTIPLE BILLINGS (791)
171 CALIFORNIA - 06APSV0020-AG PMP SRVC 9,924 1,206,796 798 12,436 0.1216
172 CALIFORNIA - 06APSV0115-CA AGRI PUMP TOU
PILOT,GHG CR 28 7,255 5 5,600 0.2591
173 CALIFORNIA - 06APSV020L-AG PMP SRVC-NO
GHG CREDIT 46,692 7,032,420 546 85,516 0.1506
174 CALIFORNIA - 06APSV115L-CA AGRI PUMP TOU,
NO GHG CR 616 78,595 6 102,667 0.1276
175 CALIFORNIA - 06LGSV048T-LRG GEN SERV 1,404 0.0000
176 CALIFORNIA - 06LNX00103-LINE EXT 80% G 8,684 0.0000
177 CALIFORNIA - 06LNX00110-REF/NREF ADV +28,740 0.0000
178 CALIFORNIA - 06LNX00310 - IRG, 80% ANNUAL
MIN + 80%81 0.0000
179 CALIFORNIA - 06LNX00312 - CA IRG LINE EXT 19,651 0.0000
180 CALIFORNIA - 06NB20L136-CA IRG NET BILL NO
GHG CR 301 40,083 2 150,500 0.1332
181 CALIFORNIA - 06NBL20136-CA IRG NET BILLING 131 15,201 0.1160
182 CALIFORNIA - 06NML20135-AGRI PUMP-NET
MTR NO GHG CR 1,076 327,104 42 25,619 0.3040
183 CALIFORNIA - 06NMT20135-AGRICULTURAL
PUMP-NET METER 94 9,158 20 4,700 0.0974
184 CALIFORNIA - 06USBR0020-KLAM IRG ONPRJ 4,126 663,552 313 13,182 0.1608
185 CALIFORNIA - 06USBR0115-CA AGR PMP TOU
PLT USBR GHG 46 9,924 3 15,333 0.2157
186 CALIFORNIA - 06USBR020L-KLAM IRG ONPRJ-
NO CHG CREDIT 12,392 2,187,462 291 42,584 0.1765
187 CALIFORNIA - 06USBR115L-CA AGR PMP TOU
PLT USBR NOGHG 340 50,763 4 85,000 0.1493
188 CALIFORNIA - DSM REVENUE-IRRIGATION 22,368 0.0000
189 CALIFORNIA - BLUE SKY REVENUE-
IRRIGATION 50 0.0000
190 CALIFORNIA - OTHER CUSTOMER RETAIL
REVENUE 1,260 0.0000
191 CALIFORNIA - INCOME TAX DEFERRAL
ADJUSTMENTS 38,686 0.0000
192 CALIFORNIA - REVENUE_ACCOUNTING
ADJUSTMENTS (129,324)0.0000
193 CALIFORNIA - REVENUE ADJUSTMENT -
DEFERRED NPC 25,421 0.0000
194 IDAHO - 07APSA010L - IRG & Pump Large Load 266,418 26,413,762 2,096 127,108 0.0991
195 IDAHO - 07APSA010S - IRG & Pump Small Load 5,068 573,383 306 16,562 0.1131
196 IDAHO - 07APSAL10X - IRG & PUMP - Large load 235,232 23,456,435 2,149 109,461 0.0997
197 IDAHO - 07APSAS10X - IRG & PUMP - Small load 8,835 1,042,742 646 13,676 0.1180
198 IDAHO - 07APSV006A-LRG POWER OPTIONAL
SVC - IRG 215 22,469 1 215,000 0.1045
199 IDAHO - 07APSV023A-SMALL POWER
OPTIONAL SVC-IRG 383 40,059 4 95,750 0.1046
200 IDAHO - 07APSVCNLL-LRG LOAD CANAL 10,047 903,375 36 279,083 0.0899
201 IDAHO - 07APSVCNLS-SML LOAD CANAL 55 7,321 11 5,000 0.1331
202 IDAHO - 07GNSV023A-GEN SRVC-SML P 121 11,185 1 121,000 0.0924
203 IDAHO - 07LNX00015-ANNUAL 80%GUAR 71,292 0.0000
204 IDAHO - 07LNX00035-ADV 80%MO GUAR 1,146 0.0000
205 IDAHO - 07LNX00040-ADV+REFCHG+80%106,057 0.0000
206 IDAHO - 07LNX00310 80% ANNUAL
GUARANTEE 4,738 0.0000
207 IDAHO - 07LNX00312 - ID LINE EXT 15,529 0.0000
208 IDAHO - 07NB10X136-NON BPA ID PUMP LRG
NET BILL (2,618)1 0.0000
209 IDAHO - 07NBL10136-ID IRG LRG LOAD NET
BILLING 25 3,119 1 25,000 0.1247
210 IDAHO - 07NM10X135-ID NET METERING - IRG 254 24,056 3 84,667 0.0947
211 IDAHO - 07APSN010L - ID LG IRR & PUMP 11,230 1,055,061 44 255,227 0.0940
212 IDAHO - 07APSN010S - IRRIGATION, SMALL, 3
PH 77 8,532 3 25,667 0.1108
213 IDAHO - 07APSNS10X - IRRIGATION, SMALL, 3
PHASE 1,046 106,579 23 45,478 0.1019
214 IDAHO - REVENUE_ACCOUNTING
ADJUSTMENTS 412,489 0.0000
215 IDAHO - DSM REVENUE-IRRIGATION 1,578,353 0.0000
216 IDAHO - BLUE SKY REVENUE-IRRIGATION 73 0.0000
217 OREGON - 01APSBA41T-OR IRR TOU OPT A -
2PM-6PM 56,352 44 0.0000
218 OREGON - 01APSBB41T-OR IRR TOU OPT B -
6PM-10PM 6,142 21 0.0000
219 OREGON - 01APSBT041-OR IRG TOU METER 96 1 0.0000
220 OREGON - 01APSV0041-AG PMP SRVC BP 1,365,714 2,132 0.0000
221 OREGON - 01APSV041L-OR Pumping Serv
>30KW 2,160,671 514 0.0000
222 OREGON - 01APSV041T - AGR PUMP SRV-TOU
OPTION 23,694 35 0.0000
223 OREGON - 01APSV041X-AG PMP SRVC<30 kW 1,668,427 2,787 0.0000
224 OREGON - 01APSV41TA-OR IRG PUMPING TOU
OPT-A 30,080 34 0.0000
225 OREGON - 01APSV41TB-OR IRG PUMPING TOU
OPT-B 7,415 17 0.0000
226 OREGON - 01APSV41XL-OR Pumping Serv no
BPA >30KW 2,760,339 523 0.0000
227 OREGON - 01APSVT041-OR IRG TOU METER 1,212 1 0.0000
228 OREGON - 01APSVT41L-OR AGRICULTUARL
PUMPING>30 KW 64 0.0000
229 OREGON - 01COST0041 -01APSV0041-
01APSV041X AG PMP 128,377 7,251,490 0.0565
230 OREGON - 01COST0048 - 01LGSV0048 22,550 1,170,786 0.0519
231 OREGON - 01COST041T- AG IRG TOU ENERGY
SUPPLY SVC 1,386 75,256 0.0543
232 OREGON - 01COST41MT-OR IRG COST SUPPLY
TOU MTR 16 896 0.0560
233 OREGON - 01CSTU41MT-USBR IRG COST
SUPPLY SVC TOU 1,129 63,794 0.0565
234 OREGON - 01CSTUSB41-USBR IRRIGATION
CONTRACTS CSS 60,543 3,421,910 0.0565
235 OREGON - 01GNSV023T, OR GEN SRV, TOU
Option 296 1 0.0000
236 OREGON - 01HABIT041 - 01APSV0041 AG PMP
SRVC 3 193 0.0645
237 OREGON - 01LGSV0048-1000KW AND OVR 614,074 2 0.0000
238 OREGON - 01LNX00103-LINE EXT 80% G 30,673 0.0000
239 OREGON - 01LNX00109-REF/NREF ADV +72 0.0000
240 OREGON - 01LNX00110-REF/NREF ADV +97,612 0.0000
241 OREGON - 01LNX00310-LINE EXTENSION
CONTRACT 5,121 0.0000
242 OREGON - 01PTOU0023, OR GEN SRV, TOU
ENG SPLY SRV 2 102 0.0511
243 OREGON - 01PTOU0041 - 01APSV0041 AG PMP
SRVC 353 19,369 0.0549
244 OREGON - 01RENEW041 - 01APSV0041 AG PMP
SRVC 83 4,662 0.0562
245 OREGON - 01STDAY041 - Daily Standard Offer
Sch 25 98 7,488 0.0764
246 OREGON - 01USBOFT41-OR USBR IRG OFF
PRJCT LND TOU 7,171 8 0.0000
247 OREGON - 01USBONT41-USBR IRG CONTR-
PRJCT LND TOU 59,372 7 0.0000
248 OREGON - 01USBRGV41-IRG TOU W/O BPA 17,709 9 0.0000
249 OREGON - 01USBROF41-KLAMATH BASIN IRG
OFF PRJ LND 1,528,763 484 0.0000
250 OREGON - 01USBRON41-KLAMATH BASIN IRG
ON PJT LND 1,911,716 1,094 0.0000
251 OREGON - 01VIR41136-OR VOLUME
INCENTIVE-AGRI PUMP 69,677 26 0.0000
252 OREGON - 01VRU41136-OR VOL INCENTIVE
USB CONTRACT 435,142 109 0.0000
253 OREGON - SOLAR FEED-IN REVENUE 59,397 0.0000
254 OREGON - OTHER CUSTOMER RETAIL
REVENUE 31,278 0.0000
255 OREGON - COMMUNITY SOLAR REVENUE 16,811 0.0000
256 OREGON - DSM REVENUE-IRRIGATION 936,781 0.0000
257 OREGON - BLUE SKY REVENUE-IRRIGATION 179 0.0000
258 OREGON - 01LNX00312 - OR IRG LINE EXT 42,964 0.0000
259 OREGON - 01LNX00316-LINE EXTENTION 109 0.0000
260 OREGON - 01NB41A135-NET MTR IRG TOU OPT
A 2-6 (1)0.0000
261 OREGON - 01NMB41135-OREGON NET METER
IRRIGATION 36,907 24 0.0000
262 OREGON - 01NMO41135-OR USBR IRG NT MTR
OFF PJ LND 1,148 1 0.0000
263 OREGON - 01NMT41135 - NETMTR AG PMP SVC 36,512 37 0.0000
264 OREGON - 01NMU41135 - OR NET MTR -
PROJECT LAND 28,886 12 0.0000
265 OREGON - REVENUE_ACCOUNTING
ADJUSTMENTS (14,447)0.0000
266 UTAH - 08APSV0010-IRR & SOIL DRA 156,036 12,322,153 3,147 49,582 0.0790
267 UTAH - 08APSV10NS- Irg Soil Drain Pump Non
Seas 34,855 2,552,248 328 106,265 0.0732
268 UTAH - 08CGM10136-UT IRG NET METER
MANUAL 300 23,224 2 150,000 0.0774
269 UTAH - 08CGN10136-UT IRG AND SOIL DRAIN
NET MTR 6 810 1 6,000 0.1351
270 UTAH - 08CGN10137-UT IRRIGATION - NET
METER 137 194 15,500 1 194,000 0.0799
271 UTAH - 08CNS10137-UT IRG NON-SEASONAL
NET MTR 53 4,613 1 53,000 0.0870
272 UTAH - 08LNX00002-MTHLY 80% GUAR 436 0.0000
273 UTAH - 08LNX00004-ANNUAL 80%GUAR 8,092 0.0000
274 UTAH - 08LNX00014-80% MIN MNTHLY (3,123)0.0000
275 UTAH - 08LNX00017-ADV/REF&80%ANN 126,189 0.0000
276 UTAH - 08LNX00300 - LINE EXT 80% PLUS
MONTHLY 308 0.0000
277 UTAH - 08LNX00310 - IRR, 80% ANNUAL MIN +
80% ?21,074 0.0000
278 UTAH - 08LNX00311 - LINE EXT 80%
GUARANTEE 2,629 0.0000
279 UTAH - 08LNX00312 UT IRG LINE EXT 18,392 0.0000
280 UTAH - 08NMT010NS-IRR & SOIL DRAIN NON
SEASONAL 153 20,999 6 25,500 0.1372
281 UTAH - 08NMT10135-UT IRR_SOIL DRNG NET
MTR SVC 6,483 583,710 76 85,303 0.0900
282 UTAH - 08TCVLAACN-UTAH TCV LNX ANNUAL
GAR 3,209 0.0000
283 UTAH - 08TCVLNAGN-UTAH LNX ANNUAL GAR
NON RES 25,827 0.0000
284 UTAH - 08TCVLNXGN-TCV LNX - 80% GAR -
NON RES 124 0.0000
285 UTAH - REVENUE_ACCOUNTING
ADJUSTMENTS 35,106 0.0000
286 UTAH - REVENUE ADJUSTMENT - DEFERRED
NPC 1,204,697 0.0000
287 UTAH - SOLAR FEED-IN REVENUE 0.0000
288 UTAH - OTHER CUSTOMER RETAIL REVENUE 20,136 0.0000
289 UTAH - DSM REVENUE-IRRIGATION 355,966 0.0000
290 UTAH - BLUE SKY REVENUE-IRRIGATION 112 0.0000
291 WASHINGTON - 02APSV0040-WA AG PMP SRVC 81,970 7,921,750 2,281 35,936 0.0966
292 WASHINGTON - 02APSV040X-WA AG PMP SRVC 82,192 8,002,516 2,810 29,250 0.0974
293 WASHINGTON - 02LNX00103-LINE EXT 80% G 23,915 0.0000
294 WASHINGTON - 02LNX00105-CNTRCT $ MIN G 76 0.0000
295 WASHINGTON - 02LNX00109-REF/NREF ADV +1,632 0.0000
296 WASHINGTON - 02LNX00110-REF/NREF ADV +92,593 0.0000
297 WASHINGTON - 02LNX00310 - IRG, 80%
ANNUAL MIN + 80%6,218 0.0000
298 WASHINGTON - 02LNX00312 - WA IRG LINE EXT 16,123 0.0000
299 WASHINGTON - 02NMT40135-WA NET
METERING-IRG 461 54,712 13 35,462 0.1187
300 WASHINGTON - 02NMX40135-WA NET
METERING-IRG 79 12,274 14 5,643 0.1554
301 WASHINGTON - REVENUE ADJUSTMENT -
DEFERRED NPC 100,189 0.0000
302 WASHINGTON - REVENUE_ACCOUNTING
ADJUSTMENTS 803,296 0.0000
303 WASHINGTON - INCOME TAX DEFERRAL
ADJUSTMENTS 78,376 0.0000
304 WASHINGTON - DSM REVENUE-IRRIGATION 892,633 0.0000
305 WASHINGTON - BLUE SKY REVENUE-
IRRIGATION 3,004 0.0000
306 WASHINGTON - ALT REVENUE PROGRAM
ADJUSTMENTS 11,886 0.0000
307 WYOMING - 05APS00040-AG PUMPING SVC -A 17,640 1,745,618 771 22,879 0.0990
308 WYOMING - 05APS0040T-WY IRG TOU PILOT 22 3,050 4 5,500 0.1386
309 WYOMING - 05APSNS040-AG PUMPING SVC -
NON SEASON 1,435 141,310 33 43,485 0.0985
310 WYOMING - 05LNX00103-LINE EXT 80% G 2,723 0.0000
311 WYOMING - 05LNX00109-REF/NREF ADV + -A 427 0.0000
312 WYOMING - 05LNX00110-REF/NREF ADV + -A 69,522 0.0000
313 WYOMING - 05LNX00312 - WY IRG LINE EXT -A 1,513 0.0000
314 WYOMING - 09APSNS210-IRR & SOIL DRA -
NON SEASON -A 5 1,140 1 5,000 0.2280
315 WYOMING - INCOME TAX DEFERRAL
ADJUSTMENTS 7,488 0.0000
316 WYOMING - REVENUE_ACCOUNTING
ADJUSTMENTS 1,320 0.0000
317 WYOMING - REVENUE ADJUSTMENT -
DEFERRED NPC (11,819)0.0000
318 WYOMING - DSM REVENUE-IRRIGATION -A 61,377 0.0000
319 WYOMING - BLUE SKY REVENUE-IRRIGATION -
A 25 0.0000
320 WYOMING - OTHER CUSTOMER RETAIL
REVENUE 2,739 0.0000
321 WYOMING - 05APS00040-AG PUMPING SVC -B 317 30,684 12 26,417 0.0968
322 WYOMING - 05LNX00109-REF/NREF ADV + -B 454 0.0000
323 WYOMING - 05LNX00110-REF/NREF ADV + -B 11,633 0.0000
324 WYOMING - 05LNX00312 - WY IRG LINE EXT -B 1,377 0.0000
325 WYOMING - 09APSNS210-IRR & SOIL DRA -
NON SEASON -B 421 42,504 7 70,167 0.1010
326 WYOMING - 09APSV0210-IRR & SOIL DRA 5,057 474,539 100 50,570 0.0938
327 WYOMING - DSM REVENUE-IRRIGATION -B 9,532 0.0000
328 WYOMING - BLUE SKY REVENUE-IRRIGATION -
B 47 0.0000
329 LESS MULTIPLE BILLINGS IRRIGATION (934)
41 TOTAL Billed Large (or Ind.) Sales 18,079,984 1,358,846,686 32,888 1,921,006 0.1801
42 TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)(141,518)(20,201,000)(0.0002)
43 TOTAL Large (or Ind.)17,938,466 1,338,645,686 32,888 1,921,006 0.1799
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
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 Page 310.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. 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.
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of
Customers
(d)
KWh of Sales Per
Customer
(e)
Revenue Per KWh Sold
(f)
1 CALIFORNIA - 06CUSL053E-SPECIAL CUST O 1,014 170,871 110 9,218 0.1685
2 CALIFORNIA - 06CUSL058F-CUST OWND STR 40 8,068 19 2,105 0.2017
3 CALIFORNIA - 06SLCO0051-COMPANY OWNED
STREET LIGHTING 700 237,332 86 8,140 0.3390
4 CALIFORNIA - DSM REVENUE-PSHL 3,518 0.0000
5 CALIFORNIA - OTHER CUSTOMER RETAIL
REVENUE 23 0.0000
6 CALIFORNIA - INCOME TAX DEFERRAL
ADJUSTMENTS 715 0.0000
7 CALIFORNIA - REVENUE_ACCOUNTING
ADJUSTMENTS (5,458)0.0000
8 CALIFORNIA - REVENUE ADJUSTMENT -
DEFERRED NPC 470 0.0000
9 IDAHO - 07GNSV023S-IDAHO TRAFFIC
SIGNALS 148 18,678 24 6,125 0.1271
10 IDAHO - 07SLCO0011-STR LGT CO-OWN 183 75,267 61 3,000 0.4113
11 IDAHO - 07SLCU012E-ENGY STR LGT-CUST
OWN 486 48,354 64 7,594 0.0995
12 IDAHO - 07SLCU012F-FULL MNT STR LGT-CUST
OWN 1,695 303,161 187 9,064 0.1789
13 IDAHO - 07SLCU012P-PART MNT STR LGT
CUST OWN 186 23,987 15 12,400 0.1290
14 IDAHO - REVENUE_ACCOUNTING
ADJUSTMENTS 5,789 0.0000
15 IDAHO - DSM REVENUE-PSHL 12,983 0.0000
16 OREGON - 01COST023F - OR GEN SRV - COST-
BASED 602 37,547 0.0624
17 OREGON - 01CUSL0053-CUS-OWNED MTRD 449 36,779 71 6,324 0.0819
18 OREGON - 01GNSV023F - OR GEN SRV - FLAT
RATE 114,422 15 0.0000
19 OREGON - 01CUSL053E-STR LGT SVC 6,898 567,004 212 32,538 0.0822
20 OREGON - 01CUSL053F-STR LGT SRVC C 67 5,935 5 13,400 0.0886
21 OREGON - 01CUSL53E2-STR LGT SVC 664 54,560 10 66,400 0.0822
22 OREGON - 01HPSV0051-HI PRESSURE SO 14,603 2,602,672 705 20,713 0.1782
23 OREGON - 01SLCO0051-OR COMPANY OWNED
STREET LIGHT 8,077 1,729,957 524 15,414 0.2142
24 OREGON - COMMUNITY SOLAR REVENUE 760 0.0000
25 OREGON - DSM REVENUE-PSHL 146,897 0.0000
26 OREGON - REVENUE_ACCOUNTING
ADJUSTMENTS 7,424 0.0000
27 OREGON - SOLAR FEED-IN REVENUE 2,061 0.0000
28 OREGON - OTHER CUSTOMER RETAIL
REVENUE 4,987 0.0000
29 UTAH - 08CFR00012-STR LGTS (CONV 54 0.0000
30 UTAH - 08CFR00051-MTH FAC SRVCHG 4,529 0.0000
31 UTAH - 08CFR00062-STREET LIGHTS 79 0.0000
32 UTAH - 08TOSS015F-TRAFFIC SIG NM 1,167 102,075 122 9,566 0.0875
33 UTAH - 08SLCO0011-STR LGT CO-OWN 12,425 3,602,637 796 15,609 0.2900
34 UTAH - 08TOSS0015-TRAF & OTHER S 3,266 351,186 1,407 2,321 0.1076
35 UTAH - 08MONL0015-MTR OUTDONIGHT 919 50,126 109 8,431 0.0545
36 UTAH - 08SLCU012P-STR LGT CUST-O 1,494 129,824 138 10,826 0.0869
37 UTAH - 08SLCU012F-STR LGT CUST-O 729 73,515 59 12,356 0.1008
38 UTAH - 08SLCU012E-DECOR CUST-OWN 35,907 1,658,797 1,137 31,580 0.0462
39 UTAH - DSM REVENUE-PSHL 84,207 0.0000
40 UTAH - REVENUE_ACCOUNTING
ADJUSTMENTS 8,420 0.0000
41 UTAH - REVENUE ADJUSTMENT - DEFERRED
NPC 288,940 0.0000
42 UTAH - SOLAR FEED-IN REVENUE 0.0000
43 UTAH - OTHER CUSTOMER RETAIL REVENUE 4,855 0.0000
44 WASHINGTON - 02CFR00012-STR LGTS (CONV 91 0.0000
45 WASHINGTON - 02CUSL053F-WA STR LGT SRV 1,400 79,025 119 11,765 0.0564
46 WASHINGTON - 02CUSL053M-WA STR LGT SRV 725 40,813 115 6,304 0.0563
47 WASHINGTON - 02SLCO0051-WA COMPANY
STREET LIGHTING 1,978 552,421 229 8,638 0.2793
48 WASHINGTON - INCOME TAX DEFERRAL
ADJUSTMENTS 1,922 0.0000
49 WASHINGTON - SM REVENUE-PSHL 48,112 0.0000
50 WASHINGTON - REVENUE_ACCOUNTING
ADJUSTMENTS (32,490)0.0000
51 WASHINGTON - REVENUE ADJUSTMENT -
DEFERRED NPC 2,663 0.0000
52 WYOMING - 05CUSL0058-CUST OWND STR 30 1,353 8 3,750 0.0451
53 WYOMING - 05CUSL0E58-WY CUST OWNED
STREET LIGHT 1,033 46,612 32 32,281 0.0451
54 WYOMING - 05CUSL0M58-CUST OWNED
STREET LT W/MAIT -A 29 1,765 3 9,667 0.0609
55 WYOMING - 05SLCO0051-WY STREET LIGHT
COMPANY OWNED -A 9,417 1,531,173 434 21,646 0.1626
56 WYOMING - DSM REVENUE-PSHL -A 54,888 0.0000
57 WYOMING - OTHER CUSTOMER RETAIL
REVENUE 1,082 0.0000
58 WYOMING - INCOME TAX DEFERRAL
ADJUSTMENTS 2,957 0.0000
59 WYOMING - REVENUE_ACCOUNTING
ADJUSTMENTS 495 0.0000
60 WYOMING - REVENUE ADJUSTMENT -
DEFERRED NPC (4,668)0.0000
61 WYOMING - 05CUSL0M58-CUST OWNED
STREET LT W/MAIT -B 34 4,556 5 6,800 0.1340
62 WYOMING - 05RCFL0054-WY REC FIELD L 62 4,182 16 3,875 0.0674
63 WYOMING - 05SLCO0051-WY STREET LIGHT
COMPANY OWNED -B 1,494 262,550 52 28,731 0.1757
64 WYOMING - DSM REVENUE-PSHL -B 4,741 0.0000
65 LESS MULTIPLE BILLINGS (3,637)
41 TOTAL Billed Public Street and Highway Lighting 107,921 15,178,250 3,252 33,094 0.1410
42 TOTAL Unbilled Rev. (See Instr. 6)(309)40,000 0.0004
43 TOTAL 107,612 15,218,250 3,252 33,094 0.1414
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
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 Page 310.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. 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.
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of
Customers
(d)
KWh of Sales Per
Customer
(e)
Revenue Per KWh Sold
(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed Provision For Rate Refunds
42 TOTAL Unbilled Rev. (See Instr. 6)
43 TOTAL
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
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 Page 310.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. 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.
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of
Customers
(d)
KWh of Sales Per
Customer
(e)
Revenue Per KWh Sold
(f)
41 TOTAL Billed - All Accounts 56,914,738 5,460,376,851 2,069,044
42 TOTAL Unbilled Rev. (See Instr. 6) - All Accounts (218,410)(5,522,000)
43 TOTAL - All Accounts 56,696,328 5,454,854,851 2,069,044 28,098 0.0907
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
SALES FOR RESALE (Account 447)
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).
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.
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 (g) 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,line 24.
10. Footnote entries as required and provide explanations following all required data.
ACTUAL DEMAND (MW)REVENUE
Line
No.
Name of Company or Public
Authority (Footnote
Affiliations)
(a)
Statistical
Classification
(b)
FERC Rate
Schedule or
Tariff
Number
(c)
Average Monthly
Billing Demand
(MW)
(d)
Average Monthly
NCP Demand
(e)
Average Monthly
CP Demand
(f)
Megawatt
Hours Sold
(g)
Demand
Charges
($)
(h)
Energy
Charges ($)
(i)
Other
Charges ($)
(j)
Total ($)
(h+i+j)
(k)
1 Requirement Sales:
2 Helper City RQ T-6 1 1 1 7,244 137,938 128,007 265,945
3 Helper City Annex RQ T-6 1 1 1 3,575 75,592 63,181 138,773
4 Navajo Tribal Utility Authority RQ T-12 35 35 33 294,731 6,571,489 8,496,082 (r)650,372 15,717,943
5 Navajo Tribal Utility Authority
(Mexican Hat)RQ T-6 0 0 0 870 14,856 15,151 30,007
6 Navajo Tribal Utility Authority
(Red Mesa)RQ T-6 2 2 1 1,865 53,574 32,493 86,067
7 Accrual RQ (286)(s)(230,570)(230,570)
8 Non-Requirement Sales:
9 Altop Energy Trading, LLC SF T-12 1,047 74,542 74,542
10 Arizona Electric Power
Cooperative, Inc.SF T-12 500 55,540 55,540
11 Arizona Public Service
Company SF T-12 2,246 118,650 118,650
12 Avangrid Renewables, LLC SF T-12 20,618 1,550,757 1,550,757
13 Avangrid Renewables, LLC SF T-13 21 (t)1,662 1,662
14 Avangrid Renewables, LLC SF WSPP-Q 650 32,500 32,500
15 Avista Corporation SF T-12 1,415 46,375 46,375
16 Avista Corporation SF T-13 31 (u)1,995 1,995
17 Basin Electric Power
Cooperative SF T-12 11,249 521,593 521,593
18 Black Hills Power, Inc.(c)
LF 441 50 50 48 334,125 905,976 8,989,815 9,895,791
19 Black Hills Power, Inc.SF T-12 82,144 3,828,288 3,828,288
20 Bonneville Power Administration SF T-12 91,220 6,028,159 6,028,159
21 Bonneville Power Administration SF T-13 72 (v)3,282 3,282
22 Bonneville Power Administration SF WSPP-Q 58,700 8,087,325 8,087,325
23 BP Energy Company SF T-12 45,901 5,348,678 5,348,678
24 British Columbia Hydro and
Power Authority SF T-13 19 (w)1,392 1,392
25 Brookfield Renewable Trading
and Marketing LP
(d)
AD T-12 2 (x)104 104
26 Brookfield Renewable Trading
and Marketing LP SF T-12 5,520 722,215 722,215
27 Brookfield Renewable Trading
and Marketing LP SF WSPP-Q 400 25,112 25,112
28 Calpine Energy Services, L.P.SF T-12 6,327 187,972 187,972
29 Citigroup Energy Inc.(e)
AD T-12 177 (y)24,196 24,196
30 Citigroup Energy Inc.SF T-12 293,347 18,983,556 18,983,556
31 City of Burbank SF T-12 1,692 144,377 144,377
32 City of Glendale SF T-12 800 114,600 114,600
33 City of Hurricane IF 560 175 22,846 22,846
34 City of Roseville SF T-12 6,200 606,220 606,220
35 City of St. George, Utah SF T-12 70 3,325 3,325
36 Clatskanie People's Utility
District SF T-12 2,551 131,124 131,124
37 ConocoPhillips Company SF T-12 11,662 845,453 845,453
38 Constellation Energy
Generation, LLC SF T-12 5,703 472,864 472,864
39 Constellation Energy
Generation, LLC SF WSPP-Q 40 6,800 6,800
40 CP Energy Marketing (US) Inc.SF T-12 4 265 265
41 Dynasty Power Inc.SF T-12 124,856 13,100,942 13,100,942
42 Dynasty Power Inc.SF WSPP-Q 1,209 75,696 75,696
43 EDF Trading North America,
LLC SF T-12 169 7,882 7,882
44 El Paso Electric Company (f)
AD T-12 67 (z)7,401 7,401
45 El Paso Electric Company SF T-12 3,099 245,086 245,086
46 Energy Keepers, Inc.SF T-12 1,997 108,332 108,332
47 Eugene Water & Electric Board SF T-12 4,518 234,713 234,713
48 Gridforce Energy Management,
LLC
(g)
AD T-13 (aa)491 491
49 Gridforce Energy Management,
LLC SF T-13 580 (ab)45,770 45,770
50 Guzman Energy, LLC SF T-12 18,476 949,678 949,678
51 Idaho Power Company SF T-13 237 (ac)11,733 11,733
52 Idaho Power Company SF WSPP-Q 40 1,400 1,400
53 Macquarie Energy LLC (h)
AD T-12 110 (ad)13,111 13,111
54 Macquarie Energy LLC (i)
AD WSPP-Q 58 (ae)4,930 4,930
55 Macquarie Energy LLC SF T-12 15,942 1,035,260 1,035,260
56 Macquarie Energy LLC SF WSPP-Q 836 63,708 63,708
57 Mag Energy Solutions Inc SF WSPP-Q 3 135 135
58 Mercuria Energy America, LLC (j)
AD T-12 134 (af)15,625 15,625
59 Mercuria Energy America, LLC SF T-12 97,932 7,806,165 7,806,165
60 Modesto Irrigation District SF T-12 4,640 502,640 502,640
61 Morgan Stanley Capital Group
Inc.SF T-12 10,728 819,100 819,100
62 Morgan Stanley Capital Group
Inc.SF WSPP-Q 844 72,650 72,650
63 NaturEner Power Watch, LLC SF T-13 40 (ag)2,645 2,645
64 (a)
Nevada Power Company SF WSPP-Q 714 60,797 60,797
65 NorthWestern Energy SF T-13 82 (ah)5,106 5,106
66 NorthWestern Energy SF WSPP-Q 1,930 108,691 108,691
67 Phillips 66 Energy Trading, LLC SF T-12 11,880 836,943 836,943
68 Phillips 66 Energy Trading, LLC SF WSPP-Q 105,130 7,520,549 7,520,549
69 Portland General Electric
Company SF T-12 11,287 512,943 512,943
70 Portland General Electric
Company SF T-13 43 (ai)2,962 2,962
71 Powerex Corporation SF T-12 36,225 1,890,286 1,890,286
72 Powerex Corporation SF WSPP-Q 21,488 1,093,033 1,093,033
73 Public Service Company of
Colorado IF T-12 307,977 10,785,901 10,785,901
74 Public Service Company of
Colorado
(k)
AD T-12 155 (aj)83,873 83,873
75 Public Service Company of
Colorado SF T-12 5,477 340,920 340,920
76 Public Service Company of
Colorado SF T-13 197 (ak)16,658 16,658
77 Public Service Company of New
Mexico SF T-12 11,789 855,220 855,220
78 Public Utility District No. 1 of
Chelan County SF T-12 34 2,356 2,356
79 Public Utility District No. 1 of
Chelan County SF T-13 13 (al)1,620 1,620
80 Public Utility District No. 1 of
Snohomish County SF T-12 580 39,175 39,175
81 Public Utility District No. 2 of
Grant County SF T-13 20 (am)1,081 1,081
82 Puget Sound Energy, Inc.SF T-12 11,054 681,011 681,011
83 Puget Sound Energy, Inc.SF T-13 27 (an)2,383 2,383
84 Rainbow Energy Marketing
Corporation SF T-12 1,712 94,382 94,382
85 Rainbow Energy Marketing
Corporation SF WSPP-Q 1,600 240,000 240,000
86 Sacramento Municipal Utility
District SF T-12 400 64,000 64,000
87 Sacramento Municipal Utility
District SF T-13 41 (ao)2,620 2,620
88 Salt River Project SF T-12 2,348 237,714 237,714
89 Seattle City Light SF T-12 1,715 104,800 104,800
90 Seattle City Light SF T-13 7 (ap)489 489
91 Shell Energy North America
(US), L.P.
(l)
AD T-12 194 (aq)20,362 20,362
92 Shell Energy North America
(US), L.P.
(m)
AD WSPP-Q (ar)477,850 477,850
93 Shell Energy North America
(US), L.P.SF T-12 379,438 31,576,680 31,576,680
94 Shell Energy North America
(US), L.P.SF WSPP-Q 112,795 7,935,195 7,935,195
95 (b)
Sierra Pacific Power Company SF T-13 114 (as)8,030 8,030
96 Tacoma Power SF T-12 1,225 64,750 64,750
97 Tacoma Power SF T-13 18 (at)564 564
98 Tenaska Power Services Co.(n)
AD T-12 (au)(500)(500)
99 Tenaska Power Services Co.SF T-12 16,392 1,188,528 1,188,528
100 Tenaska Power Services Co.SF WSPP-Q 302 40,695 40,695
101 The Energy Authority, Inc.SF T-12 16,707 1,440,037 1,440,037
102 The Energy Authority, Inc.SF WSPP-Q 1,010 181,750 181,750
103 TransAlta Energy Marketing
(U.S.) Inc.SF T-12 15,939 1,214,954 1,214,954
104 TransAlta Energy Marketing
(U.S.) Inc.SF WSPP-Q 1,013 50,140 50,140
105 Tri-State Generation and
Transmission Association, Inc.SF T-12 12,085 641,474 641,474
106 Tucson Electric Power
Company SF T-12 10,599 965,540 965,540
107 Tucson Electric Power
Company SF WSPP-Q 70 9,800 9,800
108 Turlock Irrigation District SF T-12 65,485 6,683,575 6,683,575
109 Uniper Global Commodities
North America LLC
(o)
AD T-12 23 (av)1,371 1,371
110 Uniper Global Commodities
North America LLC SF T-12 8,748 1,003,447 1,003,447
111 UNS Electric, Inc.SF T-12 1,224 70,740 70,740
112 Utah Associated Municipal
Power Systems
(p)
AD WSPP-Q (aw)(1,724)(1,724)
113 Utah Associated Municipal
Power Systems SF WSPP-Q 4,060 496,577 496,577
114 Utah Municipal Power Agency SF WSPP-Q 1,600 126,964 126,964
115 Vitol Inc.SF T-12 105,188 8,832,809 8,832,809
116 Vitol Inc.SF WSPP-Q 3,200 93,928 93,928
117
Western Area Power
Administration - Colorado
Missouri
SF T-12 31,031 3,919,790 3,919,790
118
Western Area Power
Administration - Colorado
Missouri
SF T-13 828 (ax)66,253 66,253
119 Western Area Power
Administration - Sierra Nevada SF T-12 2,400 347,200 347,200
120 Western Area Power
Administration - Upper Colorado SF T-12 56,373 6,871,937 6,871,937
121 Western Area Power
Administration - Upper Colorado SF WSPP-Q 140 18,690 18,690
122 Test Generation OS NA (9,355)(ay)(521,838)(521,838)
123 Transmission Loss Sales
Revenue
(q)
AD T-11 236 (az)12,381 12,381
124 Transmission Loss Sales
Revenue OS T-11 351,550 (ba)
17,628,544 17,628,544
125 Netting-Bookouts NA (413,724)(bb)
(25,199,653)(25,199,653)
126 Netting-Trading NA (bc)(807,799)(807,799)
127 Accrual NA 20,694 (bd)2,149,160 2,149,160
15 Subtotal - RQ 307,999 6,853,449 8,734,914 419,802 16,008,165
16 Subtotal-Non-RQ 2,602,670 905,976 181,216,259 (5,915,870)176,206,365
17 Total 2,910,669 7,759,425 189,951,173 (5,496,068)(be)
192,214,530
FERC FORM NO. 1 (ED. 12-90)
Page 310-311
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale
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.
(b) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale
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.
(c) Concept: StatisticalClassificationCode
Black Hills Power, Inc. - contract termination date: December 31, 2023
(d) Concept: StatisticalClassificationCode
Settlement adjustment.
(e) Concept: StatisticalClassificationCode
Settlement adjustment.
(f) Concept: StatisticalClassificationCode
Settlement adjustment.
(g) Concept: StatisticalClassificationCode
Settlement adjustment.
(h) Concept: StatisticalClassificationCode
Settlement adjustment.
(i) Concept: StatisticalClassificationCode
Settlement adjustment.
(j) Concept: StatisticalClassificationCode
Settlement adjustment.
(k) Concept: StatisticalClassificationCode
Settlement adjustment.
(l) Concept: StatisticalClassificationCode
Settlement adjustment.
(m) Concept: StatisticalClassificationCode
Settlement adjustment.
(n) Concept: StatisticalClassificationCode
Settlement adjustment.
(o) Concept: StatisticalClassificationCode
Settlement adjustment.
(p) Concept: StatisticalClassificationCode
Settlement adjustment.
(q) Concept: StatisticalClassificationCode
Settlement adjustment.
(r) Concept: OtherChargesRevenueSalesForResale
Load retention payment $(828,346)
Customer service charges related to:1,478,718
- 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
$650,372
(s) Concept: OtherChargesRevenueSalesForResale
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.
(t) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(u) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(v) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(w) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(x) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(y) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(z) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(aa) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(ab) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ac) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ad) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(ae) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(af) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(ag) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ah) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ai) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(aj) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(ak) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(al) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(am) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(an) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ao) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ap) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(aq) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(ar) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(as) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(at) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(au) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(av) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(aw) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(ax) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ay) Concept: OtherChargesRevenueSalesForResale
The negative revenue reported on this line reflects test energy generated that was transferred to Account 107, Construction work in progress, for the Foote Creek III-IV wind generating facility. 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 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.
(az) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(ba) Concept: OtherChargesRevenueSalesForResale
Transmission loss sales revenues collected from PacifiCorp's third-party transmission service customers.
(bb) Concept: OtherChargesRevenueSalesForResale
Reflects transactions that did not physically settle.
(bc) Concept: OtherChargesRevenueSalesForResale
Reflects transactions that were categorized as trading activities.
(bd) Concept: OtherChargesRevenueSalesForResale
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.
(be) Concept: SalesForResale
For a complete list of the number of customers during 2023 see pages 310-311, Sales for resale in this Form No. 1. For a complete list of the number of customers during the prior year see pages 310-311, Sales for resale
in PacifiCorp's December 31, 2022 Form No. 1.
FERC FORM NO. 1 (ED. 12-90)
Page 310-311
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount for Current Year
(b)
Amount for Previous Year (c)
(c)
1
2
3
4 16,006,755 13,620,311
5 671,791,677 669,378,298
6 73,969,627 81,215,880
7 10,794,276 6,037,863
8
9 745,881 726,226
10 35,504,828 35,516,373
11 373,329 412,916
12
13 809,186,373 806,907,867
14
15 4,970,662 4,940,219
16 24,643,333 21,967,025
17 87,870,198 87,554,667
18 37,663,318 45,590,218
19 14,630,607 13,641,562
20 169,778,118 173,693,691
21 978,964,491 980,601,558
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 12,849,226 11,944,971
45 331,925 342,132
1. POWER PRODUCTION EXPENSES
A. Steam Power Generation
Operation
(500) Operation Supervision and Engineering
(501) Fuel
(502) Steam Expenses
(503) Steam from Other Sources
(Less) (504) Steam Transferred-Cr.
(505) Electric Expenses
(506) Miscellaneous Steam Power Expenses
(507) Rents
(509) Allowances
TOTAL Operation (Enter Total of Lines 4 thru 12)
Maintenance
(510) Maintenance Supervision and Engineering
(511) Maintenance of Structures
(512) Maintenance of Boiler Plant
(513) Maintenance of Electric Plant
(514) Maintenance of Miscellaneous Steam Plant
TOTAL Maintenance (Enter Total of Lines 15 thru 19)
TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)
B. Nuclear Power Generation
Operation
(517) Operation Supervision and Engineering
(518) Fuel
(519) Coolants and Water
(520) Steam Expenses
(521) Steam from Other Sources
(Less) (522) Steam Transferred-Cr.
(523) Electric Expenses
(524) Miscellaneous Nuclear Power Expenses
(525) Rents
TOTAL Operation (Enter Total of lines 24 thru 32)
Maintenance
(528) Maintenance Supervision and Engineering
(529) Maintenance of Structures
(530) Maintenance of Reactor Plant Equipment
(531) Maintenance of Electric Plant
(532) Maintenance of Miscellaneous Nuclear Plant
TOTAL Maintenance (Enter Total of lines 35 thru 39)
TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)
C. Hydraulic Power Generation
Operation
(535) Operation Supervision and Engineering
(536) Water for Power
46 5,263,074 4,545,360
47
48 22,272,349 18,320,087
49 2,193,124 1,840,856
50 42,909,698 36,993,406
51
52
53 28,212 381
54 708,345 751,998
55 1,392,317 1,254,804
56 1,145,838 1,697,404
57 4,953,894 (h)(3,200,022)
58 8,228,606 504,565
59 51,138,304 37,497,971
60
61
62 577,165 470,211
63 486,505,378 562,162,331
64 29,884,779 21,750,565
64.1
65 10,168,786 9,956,030
66 11,220,095 11,209,398
67 538,356,203 605,548,535
68
69
70 4,718,702 3,017,477
71 29,305,442 24,419,168
71.1
72 4,631,097 3,540,853
73 38,655,241 30,977,498
74 577,011,444 636,526,033
75
76 937,845,148 601,324,862
76.1
77 3,499,644 1,682,317
78 49,729,786 44,289,597
79 991,074,578 647,296,776
80 2,598,188,817 2,301,922,338
81
82
83 11,540,431 10,931,628
85
86 7,195,043 7,448,335
87
88 909,952 884,337
89 3,000,366 2,516,573
90 159,306 137,750
91 2,372,399 1,557,787
92 5,572,334 5,576,135
93 4,571,617 3,905,171
93.1
94 1,947,377 1,227,690
(537) Hydraulic Expenses
(538) Electric Expenses
(539) Miscellaneous Hydraulic Power Generation Expenses
(540) Rents
TOTAL Operation (Enter Total of Lines 44 thru 49)
C. Hydraulic Power Generation (Continued)
Maintenance
(541) Mainentance Supervision and Engineering
(542) Maintenance of Structures
(543) Maintenance of Reservoirs, Dams, and Waterways
(544) Maintenance of Electric Plant
(545) Maintenance of Miscellaneous Hydraulic Plant
TOTAL Maintenance (Enter Total of lines 53 thru 57)
TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)
D. Other Power Generation
Operation
(546) Operation Supervision and Engineering
(547) Fuel
(548) Generation Expenses
(548.1) Operation of Energy Storage Equipment
(549) Miscellaneous Other Power Generation Expenses
(550) Rents
TOTAL Operation (Enter Total of Lines 62 thru 67)
Maintenance
(551) Maintenance Supervision and Engineering
(552) Maintenance of Structures
(553) Maintenance of Generating and Electric Plant
(553.1) Maintenance of Energy Storage Equipment
(554) Maintenance of Miscellaneous Other Power Generation Plant
TOTAL Maintenance (Enter Total of Lines 69 thru 72)
TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)
E. Other Power Supply Expenses
(555) Purchased Power
(555.1) Power Purchased for Storage Operations
(556) System Control and Load Dispatching
(557) Other Expenses
TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)
TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)
2. TRANSMISSION EXPENSES
Operation
(560) Operation Supervision and Engineering
(561.1) Load Dispatch-Reliability
(561.2) Load Dispatch-Monitor and Operate Transmission System
(561.3) Load Dispatch-Transmission Service and Scheduling
(561.4) Scheduling, System Control and Dispatch Services
(561.5) Reliability, Planning and Standards Development
(561.6) Transmission Service Studies
(561.7) Generation Interconnection Studies
(561.8) Reliability, Planning and Standards Development Services
(562) Station Expenses
(562.1) Operation of Energy Storage Equipment
(563) Overhead Lines Expenses
95
96 165,141,904 163,235,255
97 3,576,199 3,619,001
98 1,826,421 2,595,723
99 207,813,349 203,635,385
100
101 1,398,118 1,214,070
102 360,460 89,870
103 23,548
104 92,938 133,217
105 5,771,194 5,920,439
106
107 13,778,550 13,778,397
107.1
108 28,947,306 14,478,129
109 207,200 140,445
110 224,842 120,543
111 50,780,608 35,898,658
112 258,593,957 239,534,043
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
134 21,593,220 15,162,245
135 16,872,057 15,291,590
136 5,975,604 4,834,720
137 11,558,803 9,790,876
138
138.1
139 268,155 278,823
140 2,750,008 2,761,699
141 21,176,374 19,851,739
142 3,699,565 1,031,506
143 3,720,526 3,208,385
144 87,614,312 72,211,583
(564) Underground Lines Expenses
(565) Transmission of Electricity by Others
(566) Miscellaneous Transmission Expenses
(567) Rents
TOTAL Operation (Enter Total of Lines 83 thru 98)
Maintenance
(568) Maintenance Supervision and Engineering
(569) Maintenance of Structures
(569.1) Maintenance of Computer Hardware
(569.2) Maintenance of Computer Software
(569.3) Maintenance of Communication Equipment
(569.4) Maintenance of Miscellaneous Regional Transmission Plant
(570) Maintenance of Station Equipment
(570.1) Maintenance of Energy Storage Equipment
(571) Maintenance of Overhead Lines
(572) Maintenance of Underground Lines
(573) Maintenance of Miscellaneous Transmission Plant
TOTAL Maintenance (Total of Lines 101 thru 110)
TOTAL Transmission Expenses (Total of Lines 99 and 111)
3. REGIONAL MARKET EXPENSES
Operation
(575.1) Operation Supervision
(575.2) Day-Ahead and Real-Time Market Facilitation
(575.3) Transmission Rights Market Facilitation
(575.4) Capacity Market Facilitation
(575.5) Ancillary Services Market Facilitation
(575.6) Market Monitoring and Compliance
(575.7) Market Facilitation, Monitoring and Compliance Services
(575.8) Rents
Total Operation (Lines 115 thru 122)
Maintenance
(576.1) Maintenance of Structures and Improvements
(576.2) Maintenance of Computer Hardware
(576.3) Maintenance of Computer Software
(576.4) Maintenance of Communication Equipment
(576.5) Maintenance of Miscellaneous Market Operation Plant
Total Maintenance (Lines 125 thru 129)
TOTAL Regional Transmission and Market Operation Expenses (Enter Total of Lines 123
and 130)
4. DISTRIBUTION EXPENSES
Operation
(580) Operation Supervision and Engineering
(581) Load Dispatching
(582) Station Expenses
(583) Overhead Line Expenses
(584) Underground Line Expenses
(584.1) Operation of Energy Storage Equipment
(585) Street Lighting and Signal System Expenses
(586) Meter Expenses
(587) Customer Installations Expenses
(588) Miscellaneous Expenses
(589) Rents
TOTAL Operation (Enter Total of Lines 134 thru 143)
145
146 13,317,313 (i)(120,037)
147 2,617,893 2,031,776
148 11,034,515 8,874,412
148.1
149 188,912,870 98,222,980
150 42,982,112 35,886,919
151 1,173,446 963,955
152 2,420,043 2,451,203
153 612,575 616,630
154 10,190,475 4,797,944
155 273,261,242 153,725,782
156 360,875,554 225,937,365
157
158
159 2,406,795 2,854,050
160 10,977,236 13,510,987
161 43,316,483 40,915,077
162 34,324,811 17,701,894
163 381
164 91,025,325 74,982,389
165
166
167 1,581
168 170,514,759 138,037,944
169 5,703,041 4,393,603
170 7,205 4,002
171 176,225,005 142,437,130
172
173
174
175
176
177
178
179
180
181 (a)83,531,125 74,576,063
182 15,081,973 16,284,032
183 51,620,742 42,850,057
184 49,202,851 41,115,943
185 (b)20,017,590 16,635,876
186 1,785,095,432 102,109,509
187 (c)123,037,471 130,712,787
188
189 32,148,662 26,166,699
190 (d)144,383,626 132,843,856
191 48,947 15,720
192 2,805,595 2,440,024
193 (e)1,510,492 (278,308)
194 1,916,475,770 234,084,432
195
Maintenance
(590) Maintenance Supervision and Engineering
(591) Maintenance of Structures
(592) Maintenance of Station Equipment
(592.2) Maintenance of Energy Storage Equipment
(593) Maintenance of Overhead Lines
(594) Maintenance of Underground Lines
(595) Maintenance of Line Transformers
(596) Maintenance of Street Lighting and Signal Systems
(597) Maintenance of Meters
(598) Maintenance of Miscellaneous Distribution Plant
TOTAL Maintenance (Total of Lines 146 thru 154)
TOTAL Distribution Expenses (Total of Lines 144 and 155)
5. CUSTOMER ACCOUNTS EXPENSES
Operation
(901) Supervision
(902) Meter Reading Expenses
(903) Customer Records and Collection Expenses
(904) Uncollectible Accounts
(905) Miscellaneous Customer Accounts Expenses
TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)
6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
Operation
(907) Supervision
(908) Customer Assistance Expenses
(909) Informational and Instructional Expenses
(910) Miscellaneous Customer Service and Informational Expenses
TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)
7. SALES EXPENSES
Operation
(911) Supervision
(912) Demonstrating and Selling Expenses
(913) Advertising Expenses
(916) Miscellaneous Sales Expenses
TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)
8. ADMINISTRATIVE AND GENERAL EXPENSES
Operation
(920) Administrative and General Salaries
(921) Office Supplies and Expenses
(Less) (922) Administrative Expenses Transferred-Credit
(923) Outside Services Employed
(924) Property Insurance
(925) Injuries and Damages
(926) Employee Pensions and Benefits
(927) Franchise Requirements
(928) Regulatory Commission Expenses
(929) (Less) Duplicate Charges-Cr.
(930.1) General Advertising Expenses
(930.2) Miscellaneous General Expenses
(931) Rents
TOTAL Operation (Enter Total of Lines 181 thru 193)
Maintenance
196 (f)37,142,082 26,105,037
197 (g)1,953,617,852 260,189,469
198 5,438,526,510 3,245,002,734
FERC FORM NO. 1 (ED. 12-93)
Page 320-323
(935) Maintenance of General Plant
TOTAL Administrative & General Expenses (Total of Lines 194 and 196)
TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156,
164, 171, 178, and 197)
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: AdministrativeAndGeneralSalaries
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Account Ref. Line No.Amount for Current Year
(a)(Column)(b)
(920) Administrative and General Salaries 181(b)$83,531,125
Less: Regulatory asset amortization 234,016
Revised (920) Administrative and General Salaries $83,297,109
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.
(b) Concept: PropertyInsurance
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Account Ref. Line No.Amount for Current Year
(a)(Column)(b)
(924) Property Insurance 185(b)$20,017,590
Less: Situs property loss reserves, net of reimbursements 14,648,267
Revised (924) Property Insurance $5,369,323
To adjust PacifiCorp's formula rate, per FERC Docket No. FA16-4-000 for situs property loss reserves, net of reimbursements.
(c) Concept: EmployeePensionsAndBenefits
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, 2023, pension and
postretirement regulatory asset amortization and deferrals were $7,503,628.
(d) Concept: DuplicateChargesCredit
Includes the offset of pensions and benefits in Account 926, Employee pensions and benefits, pursuant to FERC Docket No. FA16-4-000.
(e) Concept: RentsAdministrativeAndGeneralExpense
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Account Ref. Line No.Amount for Current Year
(a)(Column)(b)
(931) Rents 193(b)$1,510,492
Less: Regulatory asset amortization 9,837
Revised (931) Rents $1,500,655
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.
(f) Concept: MaintenanceOfGeneralPlant
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Account Ref. Line No.Amount for Current Year
(a)(Column)(b)
(935) Maintenance of General Plant 196(b)$37,142,082
Less: Write-off of assets under construction 1,312,586
Less: Regulatory asset amortization 149,082
Revised (935) Maintenance of General Plant $35,680,414
To adjust PacifiCorp's formula rate, per the resolution of the preliminary challenge of PacifiCorp’s OATT Formula Rate 2021 Annual Update, for write-offs of assets under construction.
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.
(g) Concept: AdministrativeAndGeneralExpenses
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:
Account Ref. Line No.Amount for Current Year
(a)(Column)(b)
TOTAL Administrative & General Expenses 197(b)$1,953,617,852
Less: Account 920 regulatory asset amortization 234,016
Less: Situs property loss reserves, net of reimbursements 14,648,267
Less: Pension and postretirement regulatory asset deferrals, net of amortization 7,503,628
Less: Account 931 regulatory asset amortization 9,837
Less: Write-off of assets under construction 1,312,586
Less: Account 935 regulatory asset amortization 149,082
Revised TOTAL Administrative & General Expenses $1,929,760,436
To adjust Account 920, Administrative and General Salaries. Refer to footnote on Page 320, Line No. 181, Column (b)
To adjust Account 924, Property insurance. Refer to footnote on Page 320, Line No. 185, Column (b)
To adjust Account 926, Employee pensions and benefits. Refer to footnote on Page 320, Line No. 187, Column (b).
To adjust Account 931, Rents. Refer to footnote on Page 320, Line No. 193, Column (b)
To adjust Account 935, Maintenance of General Plant. Refer to footnote on Page 320, Line No. 196, Column (b).
(h) Concept: MaintenanceOfMiscellaneousHydraulicPlant
Primarily represents changes in how obligations associated with the implementation of the Klamath Hydroelectric Settlement Agreement will be met.
(i) Concept: MaintenanceSupervisionAndEngineering
Primarily represents wildfire mitigation cost deferrals.
FERC FORM NO. 1 (ED. 12-93)
Page 320-323
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(2)
(1)
(2)
(1)
(2)
(3)
(4)
(5)
(5)
(1)
(2)
(3)
(4)
(5)
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
PURCHASED POWER (Account 555)
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.
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, excluding purchases for energy storage. Report in column (h) the megawatthours shown on bills rendered to the respondent for
energy storage purchases. Report in columns (i) and (j) 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 (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m). Explain in a footnote all components of the
amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of
energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) 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 columns (g) through (n) must be totaled on the last line of the schedule. The total amount in columns (g) and (h) must be reported as Purchases on Page 401, line 10. The total amount in column (i)
must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
Actual Demand (MW)POWER EXCHANGES COST/SETTLEMENT OF POWER
Line
No.
(a)
(b)
(c)(d)(e)(f)
(g)(h)
(i)(j)(k)(l)(m)
(n)
1 Adams Solar
Center, LLC
(d)
AD (bk)15,452 15,452
2 Adams Solar
Center, LLC LU 20,199 1,510,737 (bl)12,133 1,522,870
3 Airport Solar,
LLC OS (bm)376,250 376,250
4 Altop Energy
Trading, LLC SF 22,204 3,561,492 3,561,492
5 Amor IX LLC LU 110,923 6,635,224 6,635,224
6 Appaloosa Solar
I, LLC LU 6,422 141,843 (bn)(368,000)(226,157)
7 Apple, Inc.LU 3,842 321,651 321,651
8
Arizona Electric
Power
Cooperative, Inc.
SF 13,859 649,007 649,007
9
Arizona Public
Service
Company
SF 52,141 2,777,810 2,777,810
10
Arizona Public
Service
Company
(e)
AD (bo)(4,635)(4,635)
11
Avangrid
Renewables,
LLC
SF 1,712,608 159,300,962 (bp)945 159,301,907
12 Avista
Corporation SF 236,930 23,993,203 (bq)4,250 23,997,453
13
Basin Electric
Power
Cooperative, Inc.
SF 8,235 2,742,568 2,742,568
14 BC Solar, LLC LU 16,996 1,276,474 1,276,474
15 Bear Creek Solar
Center, LLC
(f)
AD (br)15,798 15,798
Name of
Company or
Public Authority
(Footnote
Affiliations)
Statistical
Classification
Ferc Rate
Schedule
or Tariff
Number
Average
Monthly
Billing
Demand
(MW)
Average
Monthly
NCP
Demand
Average
Monthly
CP
Demand
MegaWatt
Hours
Purchased
(Excluding
for Energy
Storage)
MegaWatt
Hours
Purchased
for Energy
Storage
MegaWatt
Hours
Received
MegaWatt
Hours
Delivered
Demand
Charges
($)
Energy
Charges ($)
Other
Charges ($)
Total (k+l+m)
of
Settlement
($)
16 Bear Creek Solar
Center, LLC LU 21,953 1,643,068 (bs)16,009 1,659,077
17 Beaver City
Corporation
(g)
LF 17 3,229 3,229
18 Bell Mountain
Hydro, LLC LU 577 50,818 50,818
19 Beryl Solar, LLC LU 3 3 1 6,079 461,065 362,318 823,383
20 Big Top, LLC LU 3,198 251,966 251,966
21 Biomass One,
L.P.LU 136,323 11,642,292 11,642,292
22 Biomass One,
L.P.
(h)
AD (558)(bt)(55,600)(55,600)
23 Biomass One,
L.P.OS (bu)262,060 262,060
24 Birch Power
Company, Inc.LU 21,628 1,172,535 1,172,535
25
(a)
Black Cap Solar,
LLC LU 535 44,448 44,448
26 Black Hills
Power, Inc.SF 22,608 2,372,099 2,372,099
27 Bly Solar Center,
LLC
(i)
AD (bv)13,628 13,628
28 Bly Solar Center,
LLC LU 18,342 1,373,222 (bw)13,509 1,386,731
29 Bonneville Power
Administration OS (bx)180,914 180,914
30 Bonneville Power
Administration SF 367,746 44,166,663 (by)21,675 44,188,338
31 Bourdet, Peter M LU 167 14,274 14,274
32
Box Canyon
Limited
Partnership
LU 0 5 2 17,436 1,060,385 1,060,385
33 BP Energy
Company SF 120,126 8,757,698 8,757,698
34
Brigham Young
University -
Idaho
IU 38,912 2,444,623 2,444,623
35
Brookfield
Renewable
Trading and
Marketing LP
SF 8,224 711,380 711,380
36
Brookfield
Renewable
Trading and
Marketing LP
(j)
AD (bz)5 5
37 Buckhorn Solar,
LLC LU 3 3 1 5,901 463,861 351,727 815,588
38 Butter Creek
Power, LLC LU 10,511 826,691 826,691
39 C Drop Hydro,
LLC LU 1,081 91,293 91,293
40
California
schedule 136
Solar Customers
LU 766 34,438 34,438
41
California
Independent
System Operator
Corporation
SF 1,897 166,051 166,051
42 Calpine Energy
Services, L.P.SF 76,706 3,493,213 3,493,213
43 Carbon
Solutions, LLC OS (ca)133,500 133,500
44 Cedar Springs
III, LLC LU 541,217 9,579,542 9,579,542
45 Cedar Springs
III, LLC
(k)
AD (cb)188,127 188,127
46 Cedar Springs
Wind, LLC LU 763,561 11,835,191 11,835,191
47 Cedar Springs
Wind, LLC
(l)
AD (cc)481,383 481,383
48 Cedar Valley
Solar, LLC LU 3 3 1 5,889 458,822 350,977 809,799
49 Central Oregon
Irrigation District LU 0 3 3 27,668 2,534,841 2,534,841
50 Central Oregon
Irrigation District
(m)
AD (cd)4,647 4,647
51 Central Rivers
Power US, LLC LU 10,962 462,132 462,132
52 Cherry Creek
Solar, LLC LU 416 40,351 40,351
53 Chiloquin Solar
LLC LU 19,277 1,093,189 1,093,189
54 Chopin Wind,
LLC LU 47,797 3,059,825 3,059,825
55 Citigroup Energy
Inc.SF 425,147 36,706,322 36,706,322
56 Citigroup Energy
Inc.
(n)
AD 122 (ce)16,497 16,497
57 City of Albany LU 514 41,825 41,825
58 City of Astoria LU 53 2,905 2,905
59 City of Burbank SF 11,900 863,052 863,052
60 City of Hurricane (o)
AD (cf)(653)(653)
61 City of Hurricane (p)
LF 2,789 516,724 516,724
62 City of Idaho
Falls, Idaho LU 41,444 (cg)2,024,268 2,024,268
63
City of Portland,
Portland Water
Bureau
LU 171 14,303 14,303
64 City of Preston
Idaho LU 2,247 152,275 152,275
65 City of St.
George, Utah SF 500 27,225 27,225
66
Clatskanie
People's Utility
District
SF 2,000 166,375 166,375
67
Commercial
Energy
Management Inc.
LU 1,624 78,903 78,903
68
Commercial
Energy
Management Inc.
(q)
AD (ch)(4,380)(4,380)
69
Confederate
Tribes of Warm
Springs
LU 201 16,432 16,432
70 ConocoPhillips
Company SF 226,189 32,559,444 32,559,444
71
Consolidated
Irrigation
Company
LU 1,755 136,960 136,960
72
Consolidated
Irrigation
Company
(r)
AD (ci)(8,315)(8,315)
73
Constellation
Energy
Generation, LLC
SF 100,601 11,601,018 11,601,018
74 Cottonwood
Hydro, LLC IU 3,624 174,260 174,260
75 Cove Mountain
Solar 2, LLC LU 329,850 9,413,916 9,413,916
76 Cove Mountain
Solar, LLC LU 157,959 3,814,700 (cj)(ck)2,348,792 6,163,492
77
CP Energy
Marketing (US)
Inc.
SF 13,509 1,977,451 1,977,451
78 Crook County
Solar 1, LLC LU 1,000 84,556 84,556
79 Deschutes Valley
Water District LU 0 3 3 24,337 751,773 751,773
80
Deseret
Generation &
Transmission
Cooperative
(s)
LU 100 100 100 665,719 20,256,000 17,203,044 (cl)5,160,000 42,619,044
81 Dorena Hydro,
LLC LU 11,139 933,461 933,461
82
Douglas Co., Inc.
dba Douglas Co.
Forest Products
LU 897 73,666 73,666
83 Draper Irrigation
Company IU 555 44,552 44,552
84 Dynasty Power
Inc.SF 326,615 44,871,995 44,871,995
85 eBay Inc.(t)
AD (cm)(16,385)(16,385)
86
EDF Trading
North America,
LLC
SF 11,027 876,818 876,818
87 El Paso Electric
Company SF 81,738 4,190,185 4,190,185
88 El Paso Electric
Company
(u)
AD 67 (cn)19,509 19,509
89 Elbe Solar
Center, LLC
(v)
AD (co)15,840 15,840
90 Elbe Solar
Center, LLC LU 21,935 1,642,907 (cp)(cq)7,372 1,650,279
91 Energy Keepers,
Inc.SF 27,158 2,299,833 2,299,833
92 Enterprise Solar,
LLC
(w)
AD (cr)197,102 197,102
93 Enterprise Solar,
LLC LU 221,863 12,113,499 (cs)208,816 12,322,315
94 Escalante Solar
I, LLC LU 208,985 11,179,306 11,179,306
95 Escalante Solar
II, LLC LU 207,458 10,547,757 10,547,757
96 Escalante Solar
III, LLC LU 208,114 10,209,823 (ct)102,000 10,311,823
97 Escalante Solar
III, LLC
(x)
AD (cu)51,000 51,000
98 Eugene Water &
Electric Board SF 10,852 639,177 639,177
99 Eurus Combine
Hills I, LLC LU 74,670 3,922,407 3,922,407
100
ExxonMobil
Production
Company
LU 507 19,496 19,496
101
Fall River Rural
Electric
Cooperative, Inc.
LU 26,652 1,472,281 1,472,281
102
Farm Power
Misty Meadow,
LLC
LU 2,279 192,441 192,441
103 Farmers
Irrigation District LU 21,865 1,827,481 1,827,481
104 Fillmore City
Corporation
(y)
LF 29 2,732 2,732
105 Flathead Electric
Cooperative, Inc.
(z)
LF 352 24,686 24,686
106 Four Corners
Windfarm, LLC LU 17,019 1,340,180 1,340,180
107
Four Mile
Canyon
Windfarm, LLC
LU 17,296 1,366,846 1,366,846
108
Georgetown
Irrigation
Company
LU 1,976 93,913 93,913
109
Georgetown
Irrigation
Company
(aa)
AD (cv)(19,951)(19,951)
110 Grand Valley
Power
(ab)
LF 64 11,526 11,526
111 Granite Mountain
Solar East, LLC LU 197,195 10,206,073 10,206,073
112 Granite Mountain
Solar West, LLC LU 121,442 6,606,381 6,606,381
113 Granite Peak
Solar, LLC LU 3 3 1 6,106 295,327 357,620 652,947
114 Graphite Solar I,
LLC LU 197,185 5,511,307 5,511,307
115 Greenville Solar,
LLC LU 2 2 4,313 364,856 257,056 621,912
116
Gridforce Energy
Management,
LLC
SF 10 1,284 1,284
117 Guzman Energy,
LLC SF 37,392 3,629,893 3,629,893
118 Hammerich 1&2 LU 801 65,453 65,453
119 Hay Creek
Community Solar LU 101 9,506 9,506
120
Hayward Paul
Luckey and
Joanne Luckey
Revocable Trust
of 2005
LU 204 8,126 8,126
121
Hayward Paul
Luckey and
Joanne Luckey
Revocable Trust
of 2005
(ac)
AD 6 (cw)243 243
122 Hunter Solar LLC LU 272,263 6,861,039 (cx)985,599 7,846,638
123 Idaho Power
Company SF 77,378 5,370,473 (cy)4,321 5,374,794
124 Idaho Power
Company
(ad)
AD 51,943 (cz)3,010,455 3,010,455
125 Iron Springs
Solar, LLC LU 208,143 11,156,733 11,156,733
126 J Bar 9 Ranch,
Inc.LU 43 299 299
127 J . Aron &
Company SF 400 11,000 11,000
128 Jake Amy LU 1,292 70,533 70,533
129
Joseph
Community
Solar, LLC
LU 586 46,087 46,087
130 Keeton 1 & 2 LU 249 20,206 20,206
131 Klamath Falls
Solar 1, LLC LU 1,261 94,479 94,479
132 Klamath Falls
Solar 2, LLC IU 6,193 351,076 351,076
133 Lacomb Irrigation
District LU 4,169 256,058 256,058
134 Laho Solar, LLC LU 3 3 1 6,203 295,103 363,283 658,386
135 Latigo Wind
Park, LLC LU 151,710 9,202,430 9,202,430
136
Los Angeles
Department of
Water and Power
SF 24,631 1,898,405 1,898,405
137 Loyd Fery LU 183 5,098 5,098
138 Macquarie
Energy LLC SF 385,757 39,400,106 39,400,106
139 Macquarie
Energy LLC
(ae)
AD 293 (da)(105,720)(105,720)
140 Mag Energy
Solutions SF 160 6,400 6,400
141
Marsh Valley
Hydro Electric
Company
LU 6,934 443,153 443,153
142
Meadow Creek
Project Company
LLC
LU 266,174 23,971,466 23,971,466
143 Mercuria Energy
America, LLC SF 376,255 70,620,236 70,620,236
144 Mercuria Energy
America, LLC
(af)
AD 9 (db)4,515 4,515
145 Middle Fork
Irrigation District LU 2,767 88,055 88,055
146 Milford Flat
Solar, LLC LU 3 3 1 6,180 296,662 361,946 658,608
147 Milford Solar I,
LLC LU 260,782 6,798,580 (dc)1,024,877 7,823,457
148 Milford Solar I,
LLC
(ag)
AD (dd)4 4
149 Millican Solar
Energy LLC LU 138,957 2,715,213 (de)1,768,910 4,484,123
150 Mink Creek
Hydro LLC LU 10,513 485,062 485,062
151 Monroe Hydro,
LLC LU 746 62,635 62,635
152 Morgan City
Corporation
(ah)
LF 8 921 921
153
Morgan Stanley
Capital Group
Inc.
SF 291,521 22,054,068 22,054,068
154
Morgan Stanley
Capital Group
Inc.
(ai)
AD (df)92 92
155 Mountain Wind
Power II, LLC LU 152,730 9,861,257 9,861,257
156 Mountain Wind
Power, LLC LU 115,889 6,476,277 6,476,277
157
Myron Jones,
Nola Jones,
Larry Oja and
Christie Oja
LU 665 35,018 35,018
158
(b)
Nevada Power
Company SF 5,362 397,490 397,490
159
Nichols Gap
Limited
Partnership
LU 0 8 3 2,647 160,659 160,659
160 NorthWestern
Energy SF 4,471 330,004 (dg)3,612 333,616
161 NorthWestern
Energy
(aj)
AD 27 (dh)2,044 2,044
162 NorWest Energy
2, LLC IU 19,690 1,474,639 1,474,639
163 NorWest Energy
4, LLC IU 9,835 738,141 738,141
164 NorWest Energy
7, LLC IU 18,129 1,358,919 1,358,919
165 NorWest Energy
9, LLC IU 11,415 647,083 647,083
166 Nucor
Corporation
(ak)
IU (di)8,160,000 8,160,000
167 Oak Lea
Digester LLC LU 702 58,902 58,902
168
Obsidian
Finance Group,
LLC
LU 741 61,823 61,823
169 OneEnergy, Inc.OS (dj)(457,607)(457,607)
170 Old Mill Solar,
LLC LU 7,775 583,092 583,092
171 OR Solar 2, LLC LU 21,435 1,214,779 1,214,779
172 OR Solar 3, LLC LU 23,358 1,323,781 1,323,781
173 OR Solar 5, LLC LU 18,346 1,039,753 1,039,753
174 OR Solar 6, LLC LU 23,397 1,326,967 1,326,967
175 OR Solar 8, LLC LU 24,194 1,371,757 1,371,757
176 Orchard
Windfarm 1, LLC LU 25,544 988,879 988,879
177 Orchard
Windfarm 2, LLC LU 25,571 989,983 989,983
178 Orchard
Windfarm 3, LLC LU 25,441 985,978 985,978
179 Orchard
Windfarm 4, LLC LU 25,570 990,236 990,236
180
Oregon
Environmental
Industries, LLC
LU 13,497 816,876 816,876
181
Oregon
Environmental
Industries, LLC
(al)
AD (1,733)(dk)(138,923)(138,923)
182 Oregon Solar
Incentive LU 8,976 738,933 738,933
183 Oregon Trail
Windfarm, LLC LU 21,222 1,668,207 1,668,207
184 OSLH, LLC IU 22,396 1,268,740 1,268,740
185 P4 Production,
LLC IF (dl)20,600,000 20,600,000
186 Pacific Canyon
Windfarm, LLC LU 16,030 1,262,483 1,262,483
187 Pavant Solar II
LLC LU 102,442 3,906,708 3,906,708
188 Pavant Solar III
LLC LU 40,759 2,152,073 2,152,073
189 Pavant Solar
LLC LU 99,047 6,115,122 (dm)148,571 6,263,693
190 Pavant Solar
LLC
(am)
AD (dn)(3)(3)
191
Phillips 66
Energy Trading,
LLC
SF 122,805 10,279,030 10,279,030
192 Pioneer Wind
Park I, LLC LU 226,332 9,442,925 (do)(844,167)8,598,758
193 Pioneer Wind
Park I, LLC
(an)
AD (dp)(376,403)(376,403)
194 Platte River
Power Authority SF 3,628 55,558 55,558
195
Portland General
Electric
Company
(ao)
LF 12,234 158,154 10,065 168,219
196
Portland General
Electric
Company
(ap)
AD (dq)44,471 44,471
197
Portland General
Electric
Company
SF 104,711 6,151,251 (dr)7,024 6,158,275
198
Power County
Wind Park North,
LLC
LU 48,081 4,308,904 4,308,904
199
Power County
Wind Park North,
LLC
(aq)
AD 409 (ds)37,860 37,860
200
Power County
Wind Park
South, LLC
LU 41,239 3,720,311 3,720,311
201
Power County
Wind Park
South, LLC
(ar)
AD (120)(dt)(11,415)(11,415)
202 Powerex
Corporation SF 58,086 14,575,405 14,575,405
203 Prineville Solar
Energy LLC LU 92,946 1,816,172 (du)1,183,203 2,999,375
204 Provo City
Corporation
(as)
LF 44 3,895 3,895
205
Public Service
Company of
Colorado
SF 18,958 1,061,862 (dv)18,339 1,080,201
206
Public Service
Company of
Colorado
(at)
AD 22 (dw)154,234 154,234
207
Public Service
Company of New
Mexico
SF 51,214 2,971,630 2,971,630
208
Public Utility
District No. 1 of
Chelan County
SF 99,585 11,206,603 (dx)632 11,207,235
209
Public Utility
District No. 1 of
Cowlitz County
SF (dy)125,000 125,000
210
Public Utility
District No. 1 of
Snohomish
County
SF 28,690 1,590,591 1,590,591
211
Public Utility
District No. 2 of
Grant County
LU 74,201 (dz)5,519,956 5,519,956
212
Public Utility
District No. 2 of
Grant County
SF 1,141,527 1,633 (ea)
216,871,523 216,873,156
213
Public Utility
District No. 2 of
Grant County
LU (eb)
(21,016,616)(21,016,616)
214
Public Utility
District No. 2 of
Grant County
(au)
AD (ec)347,455 347,455
215 Puget Sound
Energy, Inc.SF 93,749 6,898,679 (ed)8,297 6,906,976
216 Quichapa 1, LLC LU 3 3 1 7,641 290,897 445,689 736,586
217 Quichapa 2, LLC LU 3 3 1 7,373 285,231 429,564 714,795
218 Quichapa 3, LLC LU 3 3 1 7,502 289,909 437,854 727,763
219
Rainbow Energy
Marketing
Corporation
SF 24,139 1,585,215 1,585,215
220 Rocket Solar I,
LLC LU 5,506 132,278 132,278
221
Roseburg Forest
Products
Company
LU 100,806 4,544,684 4,544,684
222 Roseburg LFG
Energy, LLC LU 6,075 508,140 508,140
223 Sage Solar I LLC LU 41,297 1,941,356 (ee)(67,803)1,873,553
224 Sage Solar II
LLC LU 37,796 1,761,592 (ef)(82,085)1,679,507
225 Sage Solar III
LLC LU 41,446 1,929,319 1,929,319
226 Salt River Project SF 120,258 6,941,942 6,941,942
227 Salt River Project (av)
AD (eg)492 492
228 Sand Ranch
Windfarm, LLC LU 19,206 1,512,944 1,512,944
229 Seattle City Light SF 29,016 2,309,551 (eh)(ei)127,363 2,436,914
230
Shell Energy
North America
(US), L.P.
SF 626,196 64,314,593 64,314,593
231
Shell Energy
North America
(US), L.P.
(aw)
AD (1,339)(ej)(135,186)(135,186)
232
(c)
Sierra Pacific
Power Company SF 347 6,131 (ek)13,180 19,311
233 Sigurd Solar LLC LU 199,194 5,382,215 (el)848,566 6,230,781
234 Simplot
Phosphates LLC LU 61 3,584 3,584
235 Skysol Solar,
LLC LU 3,025 150,398 (em)
(1,085,827)(935,429)
236 Solarize Rogue
LLC LU 152 14,812 14,812
237 Solwatt, LLC LU 802 65,453 65,453
238
Spanish Fork
Wind Park 2,
LLC
LU 45,304 2,830,252 2,830,252
239 Sprague Hydro
LLC LU 221 1 1,942 20,213 327,160 347,373
240 St. Anthony
Hydro, LLC LU 4,793 369,298 369,298
241 Stahlbush Island
Farms, Inc.IU 1,214 71,263 71,263
242
Strawberry
Electric Service
District
(ax)
LF 8 550 550
243
STX
Commodities
B.V.
OS (en)102,750 102,750
244 SunE DB18, LLC LU 3 3 1 7,157 455,370 426,585 881,955
245 SunE DB24, LLC LU 2 3 4 6,575 259,256 385,082 644,338
246 SunE Solar XVII
Project1, LLC LU 3 8 3 6,941 434,977 413,702 848,679
247 SunE Solar XVII
Project1, LLC
(ay)
AD (eo)(29,487)(29,487)
248 SunE Solar XVII
Project2, LLC LU 3 8 3 6,981 431,559 416,096 847,655
249 SunE Solar XVII
Project3, LLC LU 3 8 3 7,351 284,473 430,519 714,992
250 Sunny Bar
Ranch LLLP LU 1,995 101,726 101,726
251
Sunnyside
Cogeneration
Associates
LU 48 50 51 246,379 7,770,693 13,357,402 21,128,095
252
Sunnyside
Cogeneration
Associates
(az)
AD (ep)259,772 259,772
253 Swalley Irrigation
District LU 2,089 168,607 168,607
254 Sweetwater
Solar LLC LU 174,324 7,504,295 7,504,295
255 Tacoma Power SF 16,011 2,164,114 (eq)(er)200,812 2,364,926
256
Tata Chemicals
(Soda Ash)
Partners
LU 1,713 55,053 55,053
257 Tenaska Power
Services Co.SF 63,587 4,942,760 4,942,760
258
Tesoro Refining
& Marketing
Company, LLC
LU 3,674 144,979 144,979
259 Thayn Hydro
LLC LU 0 1 1 4,014 222,478 222,478
260 The Energy
Authority, Inc.SF 68,421 6,076,845 6,076,845
261 Three Buttes
Windpower, LLC LU 296,059 18,888,547 18,888,547
262 Three Peaks
Power, LLC LU 201,301 8,572,959 8,572,959
263 Three Sisters
Irrigation District LU 2,419 143,282 143,282
264 Three Sisters
Irrigation District
(ba)
AD (es)814 814
265
Threemile
Canyon Wind I,
LLC
LU 20,267 1,623,382 1,623,382
266 TMF Biofuels,
LLC LU 37,601 2,477,351 2,477,351
267 Tooele Army
Depot LU 278 7,575 7,575
268
Top of the World
Wind Energy
LLC
LU 254,849 16,820,063 (et)22,030,392 38,850,455
269
TransAlta Energy
Marketing (U.S.)
Inc.
SF 113,825 12,177,482 12,177,482
270
TransCanada
Energy Sales
Ltd.
SF 4,478 380,490 380,490
271
Tri-State
Generation and
Transmission
Association, Inc.
SF 9,421 807,753 807,753
272
Tri-State
Generation and
Transmission
Association, Inc.
(bb)
AD 99 (eu)8,285 8,285
273 Tucson Electric
Power Company SF 37,819 2,172,266 2,172,266
274 Tumbleweed
Solar LLC LU 18,855 1,068,459 1,068,459
275
U.S. Department
of the Interior -
Bureau of Land
Management
LU 7 841 841
276 Uniper Global
Commodities SF 43,984 6,446,513 6,446,513
277 Uniper Global
Commodities
(bc)
AD 48 (ev)4,282 4,282
278
United States Air
Force at Hill Air
Force Base
LU 13,554 852,851 852,851
279 UNS Electric,
Inc.SF 7,443 311,752 311,752
280 US Magnesium
LLC LU (ew)316,250 316,250
281
Utah Associated
Municipal Power
Systems
SF 380 16,800 16,800
282 Utah Municipal
Power Agency SF 73,417 8,385,844 8,385,844
283
Utah Red Hills
Renewable Park,
LLC
LU 191,056 11,096,177 11,096,177
284
Utah schedule
136 / 137 Solar
Customers
LU 207,809 14,300,060 14,300,060
285
Utah schedule
136 / 137 Solar
Customers
(bd)
AD 66,062 (ex)3,471,323 3,471,323
286 Vitol Inc.SF 28,304 2,108,881 2,108,881
287 Vitol Inc.OS (ey)386,421 386,421
288 Wagon Trail, LLC LU 6,237 491,633 491,633
289 Wallowa County
Community Solar LU 740 71,608 71,608
290 Ward Butte
Windfarm, LLC LU 14,227 1,117,412 1,117,412
291 Weber County (be)
AD (ez)4,385 4,385
292
Western Area
Power
Administration
(bf)
LF 70 6,919 6,919
293
Western Area
Power
Administration
SF 90,437 3,195,525 (fa)12,627 3,208,152
294 Whisky Creek
Community Solar LU 161 15,314 15,314
295 Wocus Marsh
Community Solar LU 862 83,102 83,102
296 Wolverine Creek
Energy, LLC LU 134,639 8,556,332 8,556,332
297 Woodline Solar,
LLC IU 17,398 986,499 986,499
298 Yakima-Tieton
Irrigation District LU 5,224 352,244 352,244
299 Liquidated
Damages
(fb)(3,432,151)(3,432,151)
300 Liquidated
Damages
(bg)
AD (fc)(2,125,739)(2,125,739)
301
California GHG
Allowance
Purchases -
Wholesale
Program
(fd)2,845,333 2,845,333
302
California GHG
Allowance
Purchases -
Retail Program
(fe)10,877,375 10,877,375
303
Washington
GHG Allowance
Purchases –
Wholesale
Program
(ff)42,054,785 42,054,785
304 Net Power Cost
Deferrals
(fg)
(521,199,290)(521,199,290)
305 Netting -
Bookouts (413,724)(fh)
(25,199,654)(25,199,654)
306 Netting - Trading (fi)(807,799)(807,799)
307 System
Deviation 7,277
308 Accrual (fj)(3,082,609)(3,082,609)
309 Power
Exchanges:
310 Avista
Corporation EX 382 1,186
311 Bonneville Power
Administration EX T- BPA 343,407 4,411
312 Bonneville Power
Administration EX 237 1,559,460 1,565,591 (fk)(15,379)(15,379)
313
California
Independent
System Operator
EX T-12 4,543,360 4,328,622 (fl)(3,721,191)(3,721,191)
314
California
Independent
System Operator
EX T-11 (fm)
(31,090,075)(31,090,075)
315
California
Independent
System Operator
(bh)
AD T-11 (fn)(156,089)(156,089)
316
Emerald
People's Utility
District
EX T-6 933 (fo)(23,622)(23,622)
317 Idaho Power
Company EX T-6 2,212 2,313
318 Idaho Power
Company EX 708 133,911 119,262
319
Los Angeles
Department of
Water and Power
EX OV1 2,693 (fp)309,153 309,153
320
Milford Wind
Corridor Phase I,
LLC
EX OV1 1,792 (fq)(206,102)(206,102)
321
Milford Wind
Corridor Phase
II, LLC
EX OV1 901 (fr)(103,051)(103,051)
322 NorthWestern
Corporation EX 160 26,349
323
Portland General
Electric
Company
EX T-8 3,199
324
Public Utility
District No. 1 of
Cowlitz County
EX 442 198,051 207,092
325
Western Area
Power
Administration
EX LAS-4 185,047 87,575 (fs)393,905 393,905
326
Western Area
Power
Administration
(bi)
AD LAS-4 (1,982)(ft)11,023 11,023
327 Imbalance
Energy Accrual EX T-11 416,832 (fu)15,247,794 15,247,794
328 Imbalance
Energy Accrual
(bj)
AD T-11 (17,653)(fv)(2,455,857)(2,455,857)
15 TOTAL 17,677,912 7,394,886 6,319,678 33,572,428 1,151,270,689 (246,997,969)937,845,148
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
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.
(b) Concept: NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
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.
(c) Concept: NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
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.
(d) Concept: StatisticalClassificationCode
Settlement adjustment.
(e) Concept: StatisticalClassificationCode
Settlement adjustment.
(f) Concept: StatisticalClassificationCode
Settlement adjustment.
(g) Concept: StatisticalClassificationCode
Under Electric Service Agreement subject to termination upon timely notification.
(h) Concept: StatisticalClassificationCode
Settlement adjustment.
(i) Concept: StatisticalClassificationCode
Settlement adjustment.
(j) Concept: StatisticalClassificationCode
Settlement adjustment.
(k) Concept: StatisticalClassificationCode
Settlement adjustment.
(l) Concept: StatisticalClassificationCode
Settlement adjustment.
(m) Concept: StatisticalClassificationCode
Settlement adjustment.
(n) Concept: StatisticalClassificationCode
Settlement adjustment.
(o) Concept: StatisticalClassificationCode
Settlement adjustment.
(p) Concept: StatisticalClassificationCode
City of Hurricane - contract termination dates: January 31, 2023 and January 31, 2024.
(q) Concept: StatisticalClassificationCode
Settlement adjustment.
(r) Concept: StatisticalClassificationCode
Settlement adjustment.
(s) Concept: StatisticalClassificationCode
Deseret Generation & Transmission Cooperative - contract termination date: September 30, 2024.
(t) Concept: StatisticalClassificationCode
Settlement adjustment.
(u) Concept: StatisticalClassificationCode
Settlement adjustment.
(v) Concept: StatisticalClassificationCode
Settlement adjustment.
(w) Concept: StatisticalClassificationCode
Settlement adjustment.
(x) Concept: StatisticalClassificationCode
Settlement adjustment.
(y) Concept: StatisticalClassificationCode
Under Electric Service Agreement subject to termination upon timely notification.
(z) Concept: StatisticalClassificationCode
Flathead Electric Cooperative, Inc. - contract termination date: July 31, 2025.
(aa) Concept: StatisticalClassificationCode
Settlement adjustment.
(ab) Concept: StatisticalClassificationCode
Under Electric Service Agreement subject to termination upon timely notification.
(ac) Concept: StatisticalClassificationCode
Settlement adjustment.
(ad) Concept: StatisticalClassificationCode
Settlement adjustment.
(ae) Concept: StatisticalClassificationCode
Settlement adjustment.
(af) Concept: StatisticalClassificationCode
Settlement adjustment.
(ag) Concept: StatisticalClassificationCode
Settlement adjustment.
(ah) Concept: StatisticalClassificationCode
Under Electric Service Agreement subject to termination upon timely notification.
(ai) Concept: StatisticalClassificationCode
Settlement adjustment.
(aj) Concept: StatisticalClassificationCode
Settlement adjustment.
(ak) Concept: StatisticalClassificationCode
Nucor Corporation - contract termination date: December 31, 2031
(al) Concept: StatisticalClassificationCode
Settlement adjustment.
(am) Concept: StatisticalClassificationCode
Settlement adjustment.
(an) Concept: StatisticalClassificationCode
Settlement adjustment.
(ao) Concept: StatisticalClassificationCode
Portland General Electric Company - contract termination date: When the Round Butte project no longer operates for power production purposes.
(ap) Concept: StatisticalClassificationCode
Settlement adjustment.
(aq) Concept: StatisticalClassificationCode
Settlement adjustment.
(ar) Concept: StatisticalClassificationCode
Settlement adjustment.
(as) Concept: StatisticalClassificationCode
Under Electric Service Agreement subject to termination upon timely notification.
(at) Concept: StatisticalClassificationCode
Settlement adjustment.
(au) Concept: StatisticalClassificationCode
Settlement adjustment.
(av) Concept: StatisticalClassificationCode
Settlement adjustment.
(aw) Concept: StatisticalClassificationCode
Settlement adjustment.
(ax) Concept: StatisticalClassificationCode
Under Electric Service Agreement subject to termination upon timely notification.
(ay) Concept: StatisticalClassificationCode
Settlement adjustment.
(az) Concept: StatisticalClassificationCode
Settlement adjustment.
(ba) Concept: StatisticalClassificationCode
Settlement adjustment.
(bb) Concept: StatisticalClassificationCode
Settlement adjustment.
(bc) Concept: StatisticalClassificationCode
Settlement adjustment.
(bd) Concept: StatisticalClassificationCode
Settlement adjustment.
(be) Concept: StatisticalClassificationCode
Settlement adjustment.
(bf) Concept: StatisticalClassificationCode
Western Area Power Administration - contract termination date: July 1, 2025.
(bg) Concept: StatisticalClassificationCode
Settlement adjustment.
(bh) Concept: StatisticalClassificationCode
Settlement adjustment.
(bi) Concept: StatisticalClassificationCode
Settlement adjustment.
(bj) Concept: StatisticalClassificationCode
Settlement adjustment.
(bk) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bl) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(bm) Concept: OtherChargesOfPurchasedPower
Purchases of reactive supply and voltage control, per FERC Docket ER20-2528, effective September 28, 2020.
(bn) Concept: OtherChargesOfPurchasedPower
Liquidated damages.
(bo) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bp) Concept: OtherChargesOfPurchasedPower
Reserve share.
(bq) Concept: OtherChargesOfPurchasedPower
Reserve share.
(br) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bs) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(bt) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bu) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(bv) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bw) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(bx) Concept: OtherChargesOfPurchasedPower
Ancillary services.
(by) Concept: OtherChargesOfPurchasedPower
Reserve share.
(bz) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ca) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(cb) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cc) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cd) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ce) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cf) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cg) Concept: OtherChargesOfPurchasedPower
Labor, equipment and administration fees associated with a hydro project in Idaho Falls, Idaho.
(ch) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ci) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cj) Concept: OtherChargesOfPurchasedPower
Purchases of reactive supply and voltage control, per FERC Docket ER20-2528, effective September 28, 2020.
(ck) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(cl) Concept: OtherChargesOfPurchasedPower
Fixed operations and maintenance component of the purchased power price.
(cm) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cn) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(co) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cp) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(cq) Concept: OtherChargesOfPurchasedPower
Reimbursement for transmission service charges.
(cr) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cs) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(ct) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(cu) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cv) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cw) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cx) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(cy) Concept: OtherChargesOfPurchasedPower
Reserve share.
(cz) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(da) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(db) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dc) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(dd) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(de) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(df) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dg) Concept: OtherChargesOfPurchasedPower
Reserve share.
(dh) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(di) Concept: OtherChargesOfPurchasedPower
Ancillary services.
(dj) Concept: OtherChargesOfPurchasedPower
Liquidated damages.
(dk) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dl) Concept: OtherChargesOfPurchasedPower
Compensation for interruptible service and operating reserves.
(dm) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(dn) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(do) Concept: OtherChargesOfPurchasedPower
Liquidated damages.
(dp) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dq) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dr) Concept: OtherChargesOfPurchasedPower
Reserve share.
(ds) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dt) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(du) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(dv) Concept: OtherChargesOfPurchasedPower
Reserve share.
(dw) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dx) Concept: OtherChargesOfPurchasedPower
Reserve share.
(dy) Concept: OtherChargesOfPurchasedPower
Grant County Meaningful Priority assignment fees.
(dz) Concept: OtherChargesOfPurchasedPower
Reasonable Portion and Conversion Amendment Costs.
(ea) Concept: OtherChargesOfPurchasedPower
Meaningful Priority award to PacifiCorp of generation output from the Priest Rapids Project from Grant County.
(eb) Concept: OtherChargesOfPurchasedPower
Meaningful priority proceeds.
(ec) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ed) Concept: OtherChargesOfPurchasedPower
Reserve share.
(ee) Concept: OtherChargesOfPurchasedPower
Liquidated damages.
(ef) Concept: OtherChargesOfPurchasedPower
Liquidated damages.
(eg) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(eh) Concept: OtherChargesOfPurchasedPower
Reserve share.
(ei) Concept: OtherChargesOfPurchasedPower
Grant County Meaningful Priority assignment fees.
(ej) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ek) Concept: OtherChargesOfPurchasedPower
Reserve share.
(el) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(em) Concept: OtherChargesOfPurchasedPower
Liquidated damages.
(en) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(eo) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ep) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(eq) Concept: OtherChargesOfPurchasedPower
Reserve share.
(er) Concept: OtherChargesOfPurchasedPower
Grant County Meaningful Priority assignment fees.
(es) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(et) Concept: OtherChargesOfPurchasedPower
Compensation curtailment charges.
(eu) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ev) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ew) Concept: OtherChargesOfPurchasedPower
Ancillary services.
(ex) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ey) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standard requirements.
(ez) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(fa) Concept: OtherChargesOfPurchasedPower
Reserve share.
(fb) Concept: OtherChargesOfPurchasedPower
Liquidated damages.
(fc) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(fd) Concept: OtherChargesOfPurchasedPower
Purchases of greenhouse gas allowances for compliance with the California Air Resources Board greenhouse gas cap-and-trade program.
(fe) Concept: OtherChargesOfPurchasedPower
Purchases of greenhouse gas allowances for compliance with the California Air Resources Board greenhouse gas cap-and-trade program.
(ff) Concept: OtherChargesOfPurchasedPower
Purchases of greenhouse gas allowances for compliance with the Washington cap-and-invest program.
(fg) Concept: OtherChargesOfPurchasedPower
Regulatory net power cost and renewable energy credit deferrals.
(fh) Concept: OtherChargesOfPurchasedPower
Reflects transactions that did not physically settle.
(fi) Concept: OtherChargesOfPurchasedPower
Reflects transactions that were categorized as trading activities.
(fj) Concept: OtherChargesOfPurchasedPower
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.
(fk) Concept: OtherChargesOfPurchasedPower
Storage and energy exchange charges.
(fl) Concept: OtherChargesOfPurchasedPower
Energy Imbalance Market (EIM) participating resource settlements in EIM.
(fm) Concept: OtherChargesOfPurchasedPower
Energy Imbalance Market (EIM) entity settlements in EIM.
(fn) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(fo) Concept: OtherChargesOfPurchasedPower
Exchange energy credit.
(fp) Concept: OtherChargesOfPurchasedPower
Station service for a third-party wind project.
(fq) Concept: OtherChargesOfPurchasedPower
Reimbursement for providing station service to a third-party wind project.
(fr) Concept: OtherChargesOfPurchasedPower
Reimbursement for providing station service to a third-party wind project.
(fs) Concept: OtherChargesOfPurchasedPower
Imbalance energy settlements between PacifiCorp merchant function and third-party transmission providers.
(ft) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(fu) Concept: OtherChargesOfPurchasedPower
Imbalance energy settlements between the PacifiCorp transmission provider and third-party transmission customers.
(fv) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
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.
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.
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 (0) 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.
TRANSFER OF
ENERGY
REVENUE FROM TRANSMISSION OF ELECTRICITY
FOR OTHERS
Line
No.
(a)(b)(c)(d)(e)
(f)(g)
(h)(i)(j)(k)(l)(m)(n)
1 Airport Solar LLC Airport Solar LLC Portland General Electric
Company
(c)
LFP SA 965 Trona
Substation
Red Butte/Mona
Sub 50 109,056 109,056 1,703,375 (fd)383,788 2,087,163
2 Airport Solar LLC Airport Solar LLC Portland General Electric
Company
(d)
AD SA 965 Trona
Substation
Red Butte/Mona
Sub 52 2,819 2,819 (fe)103,916 103,916
3 Altop Energy Trading LLC various signatories various signatories NF SA 1059 various various 480 480 6,422 (ff)407 6,829
4 Arizona Electric Power
Cooperative, Inc.various signatories various signatories SFP SA 1010 various various 295 295 2,446 (fg)154 2,600
5 Arizona Electric Power
Cooperative, Inc.various signatories various signatories (e)
AD SA 1010 various various 10 10 (fh)99 99
6 Arizona Public Service Company various signatories various signatories (f)
AD SA 042 various various 72 72 (fi)395 395
7 Avangrid Renewables, LLC various signatories various signatories NF SA 121 various various 147,548 147,548 1,999,645 (fj)125,914 2,125,559
8 Avangrid Renewables, LLC various signatories various signatories (g)
AD SA 121 various various 25,849 25,849 (fk)185,556 185,556
9 Avangrid Renewables, LLC various signatories various signatories SFP SA 122 various various 47,662 47,662 448,615 (fl)28,268 476,883
10 Avangrid Renewables, LLC various signatories various signatories (h)
AD SA 122 various various 3,510 3,510 (fm)38,743 38,743
11 Avangrid Renewables, LLC
Avangrid Renewables, LLC and
Utah Associated Municipal Power
Systems
Avangrid Renewables, LLC and
Utah Associated Municipal Power
Systems
(i)
OS SA 476
Long Hollow,
WY switching
station
Long Hollow,
WY switching
station
(fn)195,720 195,720
12 Avangrid Renewables, LLC
Avangrid Renewables, LLC and
Utah Associated Municipal Power
Systems
Avangrid Renewables, LLC and
Utah Associated Municipal Power
Systems
(j)
AD SA 476
Long Hollow,
WY switching
station
Long Hollow,
WY switching
station
(fo)25,775 25,775
13 Avangrid Renewables, LLC Exxon Mobil Nevada Power Company (k)
LFP SA 895 Trona
Substation
Red Butte/Mona
Sub 31 51,183 51,183 1,064,609 (fp)67,043 1,131,652
14 Avangrid Renewables, LLC Exxon Mobil Nevada Power Company (l)
AD SA 895 Trona
Substation
Red Butte/Mona
Sub 9,754 9,754 (fq)93,818 93,818
15 Avangrid Renewables, LLC Bonneville Power Administration Oregon Direct Access FNO SA 742 Ponderosa
Substation various 34 265,043 265,043 1,159,984 (fr)530,031 1,690,015
16 Avangrid Renewables, LLC Avangrid Renewables, LLC various signatories (m)
AD SA 742 Ponderosa
Substation various 35 25,157 25,157 (fs)95,585 95,585
Payment By (Company of
Public Authority) (Footnote
Affiliation)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
Energy Delivered To (Company
of Public Authority) (Footnote
Affiliation)
Statistical
Classification
Ferc Rate
Schedule of
Tariff Number
Point of
Receipt
(Substation
or Other
Designation)
Point of
Delivery
(Substation or
Other
Designation)
Billing
Demand
(MW)
Megawatt
Hours
Received
Megawatt
Hours
Delivered
Demand
Charges ($)
Energy
Charges
($)
Other
Charges
($)
Total
Revenues
($) (k+l+m)
17 Avista Corporation various signatories various signatories NF SA 887 various various 30 30 133 (ft)8 141
18 Basin Electric Power
Cooperative, Inc.
Western Area Power
Administration
Powder River Energy
Corporation FNO SA 505 Yellowtail Sub Sheridan
Substation 10 68,594 68,594 345,345 (fu)52,370 397,715
19 Basin Electric Power
Cooperative, Inc.
Western Area Power
Administration
Powder River Energy
Corporation
(n)
AD SA 505 Yellowtail Sub Sheridan
Substation 13 7,798 7,798 (fv)29,740 29,740
20 Basin Electric Power
Cooperative, Inc.
Western Area Power
Administration
Powder River Energy
Corporation NF SA 607 various various 89,059 89,059 933,125 (fw)58,889 992,014
21 Basin Electric Power
Cooperative, Inc.
Western Area Power
Administration
Powder River Energy
Corporation
(o)
AD SA 607 various various 2,386 2,386 (fx)156,114 156,114
22 Basin Electric Power
Cooperative, Inc.
Western Area Power
Administration
Powder River Energy
Corporation SFP SA 606 various various 3,860 3,860 26,759 (fy)1,669 28,428
23 Basin Electric Power
Cooperative, Inc.
Western Area Power
Administration
Powder River Energy
Corporation
(p)
AD SA 606 various various 428 428 (fz)4,569 4,569
24 Black Hills/Colorado Electric
Utility Company, L.P.various signatories various signatories NF SA 563 various various 559 (ga)35 594
25 Black Hills/Colorado Electric
Utility Company, L.P.various signatories various signatories SFP SA 562 various various 930 (gb)59 989
26 Black Hills Corporation PacifiCorp Montana-Dakota Utilities FNO SA 347 various Sheridan
Substation 47 274,312 274,312 1,589,804 (gc)100,128 1,689,932
27 Black Hills Corporation PacifiCorp Montana-Dakota Utilities (q)
AD SA 347 various Sheridan
Substation 64 32,830 32,830 (gd)137,664 137,664
28 Black Hills Corporation PacifiCorp Black Hills Corporation (r)
LFP SA 67 various Wyodak
Substation 52 96,758 96,758 1,771,916 (ge)112,321 1,884,237
29 Black Hills Corporation PacifiCorp Black Hills Corporation (s)
AD SA 67 various Wyodak
Substation 52 18,688 18,688 (gf)84,874 84,874
30 Black Hills Corporation various signatories various signatories NF SA 768 various various 1,080 1,080 11,986 (gg)759 12,745
31 Black Hills Corporation various signatories various signatories (t)
AD SA 768 various various 65 65 (gh)643 643
32 Black Hills Power Marketing various signatories various signatories NF SA 43 various various 562 562 2,864 (gi)181 3,045
33 Black Hills Power Marketing various signatories various signatories (u)
AD SA 112 various various 20 20 (gj)141 141
34 Black Hills Power Marketing various signatories various signatories SFP SA 111 various various 154 154 1,121 (gk)164 1,285
35 Bonneville Power Administration
Capacity exchanged and
operated by each transmission
provider with no receipt or
delivery of energy.
Capacity exchanged and
operated by each transmission
provider with no receipt or
delivery of energy.
(v)
OS RS 369 Midpoint
Substation
Summer Lake
Sub
36 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (w)
OS RS 237 various various 426 1,057,064 1,057,064 4,328,265 (gl)67,947 4,396,212
37 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (x)
AD RS 237 various various 428 99,406 99,406 (gm)406,946 406,946
38 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (y)
LFP SA 656 Lost Creek
Hydro Plt
Alvey
Substation 58 205,048 205,048 1,987,271 (gn)44,415 2,031,686
39 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (z)
AD SA 656 Lost Creek
Hydro Plt
Alvey
Substation 58 13,941 13,941 (go)90,929 90,929
40 Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility
Cooperative FNO SA 229
Bonneville
Power
Administration
Gazley
Substation 3 22,822 22,822 117,442 (gp)157,194 274,636
41 Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility
Cooperative
(aa)
AD SA 229
Bonneville
Power
Administration
Gazley
Substation 3 2,190 2,190 (gq)20,263 20,263
42 Bonneville Power Administration Bonneville Power Administration Benton Rural Electric Association FNO SA 539
Bonneville
Power
Administration
Tieton
Substation 1 6,445 6,445 34,625 (gr)4,477 39,102
43 Bonneville Power Administration Bonneville Power Administration Benton Rural Electric Association (ab)
AD SA 539
Bonneville
Power
Administration
Tieton
Substation 2 1,023 1,023 (gs)(1,807)(1,807)
44 Bonneville Power Administration Bonneville Power Administration
Umatilla Electric Cooperative
Association and Columbia Basin
Electric Cooperative, Inc.
FNO SA 538 McNary
Substation
Hinkle
Substation 1 1,371 1,371 8,920 (gt)970 9,890
45 Bonneville Power Administration Bonneville Power Administration
Umatilla Electric Cooperative
Association and Columbia Basin
Electric Cooperative, Inc.
(ac)
AD SA 538 McNary
Substation
Hinkle
Substation 1 203 203 (gu)(1,210)(1,210)
46 Bonneville Power Administration United States Department of
Interior, Bureau of Reclamation Bonneville Power Administration (ad)
LFP SA 229 USBR Green
Springs
Bonneville
Power Adm
(gv)61,064 61,064
47 Bonneville Power Administration United States Department of
Interior, Bureau of Reclamation Bonneville Power Administration (ae)
AD SA 229 USBR Green
Springs
Bonneville
Power Adm
(gw)(838)(838)
48 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (af)
OS RS 368 Malin
Substation
Malin
Substation 468,434 468,434 (gx)232,452 232,452
49 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (ag)
AD RS 368 Malin
Substation
Malin
Substation 34,594 34,594 (gy)21,132 21,132
50 Bonneville Power Administration Bonneville Power Administration Yakama Power FNO SA 328
Bonneville
Power
Administration
White
Swan/Toppenish
Substations
7 45,112 45,112 252,765 (gz)124,011 376,776
51 Bonneville Power Administration Bonneville Power Administration Yakama Power (ah)
AD SA 328
Bonneville
Power
Administration
White
Swan/Toppenish
Substations
7 3,791 3,791 (ha)17,182 17,182
52 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO SA 827
Bonneville
Power
Administration
Neff Substation 4 694 694 888 (hb)284 1,172
53 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (ai)
AD SA 827
Bonneville
Power
Administration
Neff Substation 3 92 92 (hc)602 602
54 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO SA 746 Goshen
Substation various 237 1,426,077 1,426,077 8,167,379 (hd)
1,862,996 10,030,375
55 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (aj)
AD SA 746 Goshen
Substation various 375 198,767 198,767 (he)796,904 796,904
56 Bonneville Power Administration various signatories various signatories NF SA 44 various various 317,525 (hf)20,143 337,668
57 Bonneville Power Administration various signatories various signatories FNO SA 747 Goshen
Substation various 114 700,955 700,955 3,551,194 (hg)661,366 4,212,560
58 Bonneville Power Administration various signatories various signatories (ak)
AD SA 747 Goshen
Substation various 121 76,118 76,118 (hh)232,853 232,853
59 Bonneville Power Administration Bonneville Power Administration Public Utility District No. 1 of
Clark County FNO SA 735 Cardwell-
Merwin
Chelatchie/View
115kV 22 116,714 116,714 765,246 (hi)82,797 848,043
60 Bonneville Power Administration Bonneville Power Administration Public Utility District No. 1 of
Clark County
(al)
AD SA 735 Cardwell-
Merwin
Chelatchie/View
115kV 22 16,607 16,607 (hj)100,654 100,654
61 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO SA 865 Goshen
Substation various 1 551 551 969 (hk)241 1,210
62 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (am)
AD SA 865 Goshen
Substation various 1 71 71 (hl)512 512
63 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO SA 975
Bonneville
Power
Administration
various 1 3,780 3,780 15,656 (hm)2,169 17,825
64 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (an)
AD SA 975
Bonneville
Power
Administration
various 1 8 8 (hn)(641)(641)
65 BP Energy Company various signatories various signatories SFP SA 1083 various various 2,425 2,425 13,819 (ho)876 14,695
66 BP Energy Company various signatories various signatories NF SA 1084 various various 30,032 30,032 360,059 (hp)22,830 382,889
67 Brookfield Renewable Trading
and Marketing LP various signatories various signatories NF SA 941 various various 325 325 15,816 (hq)992 16,808
68 Brookfield Renewable Trading
and Marketing LP various signatories various signatories SFP SA 940 various various 2,808 2,808 39,482 (hr)2,463 41,945
69 Brookfield Renewable Trading
and Marketing LP various signatories various signatories (ao)
AD SA 940 various various 6,800 6,800 (hs)47,483 47,483
70 Calpine Energy Solutions, LLC Bonneville Power Administration Oregon Direct Access FNO SA 299
Bonneville
Power
Administration
various 18 124,245 124,245 608,891 (ht)102,757 711,648
71 Calpine Energy Solutions, LLC Bonneville Power Administration Oregon Direct Access (ap)
AD SA 299
Bonneville
Power
Administration
various 17 11,453 11,453 (hu)31,679 31,679
72 City of Roseville City of Roseville City of Roseville (aq)
LFP SA 881 Malin 500
Substation
Round Mountain
Sub 50 1,701,197 (hv)33,663 1,734,860
73 City of Roseville City of Roseville City of Roseville (ar)
AD SA 881 Malin 500
Substation
Round Mountain
Sub 50 (hw)75,544 75,544
74 Clatskanie People's Utility District Clatskanie People's Utility District Clatskanie People's Utility District (as)
LFP SA 899 Troutdale
Substation various 14 60,863 60,863 461,332 (hx)29,053 490,385
75 Clatskanie People's Utility District Clatskanie People's Utility District Clatskanie People's Utility District (at)
AD SA 899 Troutdale
Substation various 6,403 6,403 (hy)18,930 18,930
76 Clatskanie People's Utility District Clatskanie People's Utility District Clatskanie People's Utility District (au)
LFP SA 901 Troutdale
Substation various 2 13,107 13,107 58,076 (hz)3,651 61,727
77 Clatskanie People's Utility District Clatskanie People's Utility District Clatskanie People's Utility District (av)
AD SA 901 Troutdale
Substation various (ia)6,859 6,859
78 ConocoPhillps Company various signatories various signatories NF SA 280 various various 1,170 1,170 10,906 (ib)678 11,584
79 CP Energy Marketing (US) Inc.various signatories various signatories NF SA 968 various various 4,230 4,230 39,930 (ic)2,532 42,462
80 CP Energy Marketing (US) Inc.various signatories various signatories (aw)
AD SA 968 various various (id)4,462 4,462
81 CP Energy Marketing (US) Inc.various signatories various signatories SFP SA 967 various various 399 (ie)26 425
82 Deseret Generation and
Transmission Co-operative
Deseret Generation and
Transmission Co-operative
Deseret Generation and
Transmission Co-operative
(ax)
OS RS 280 various various 143 1,068,333 1,068,333 4,922,165 (if)
1,499,427 6,421,592
83 Deseret Generation and
Transmission Co-operative
Deseret Generation and
Transmission Co-operative
Deseret Generation and
Transmission Co-operative
(ay)
AD RS 280 various various 109 89,844 89,844 (ig)385,368 385,368
84 Deseret Generation and
Transmission Co-operative various signatories various signatories NF SA 156 various various 12,743 12,743 96,011 (ih)25,565 121,576
85 Deseret Generation and
Transmission Co-operative various signatories various signatories (az)
AD SA 156 various various 1,387 1,387 (ii)11,926 11,926
86 Dynasty Power Inc.various signatories various signatories NF SA 1014 various various 103,498 103,498 918,379 (ij)57,855 976,234
87 Dynasty Power Inc.(ba)
AD SA 1014 various various 10,854 10,854 (ik)190,308 190,308
88 Dynasty Power Inc.various signatories various signatories SFP SA 1013 various various 45,362 45,362 309,569 (il)45,889 355,458
89 Dynasty Power Inc.(bb)
AD SA 1013 various various 14,667 14,667 (im)161,949 161,949
90 Energy Keepers, Inc.various signatories various signatories NF SA 814 various various 101,525 101,525 631,842 (in)39,644 671,486
91 Energy Keepers, Inc.various signatories various signatories SFP SA 815 various various 3,108 3,108 237,136 (io)15,037 252,173
92 Evergreen Biopower LLC NextEra Energy Resources, LLC various signatories (bc)
LFP SA 874 various various 10 34,781 34,781 354,869 (ip)62,563 417,432
93 Evergreen Biopower LLC NextEra Energy Resources, LLC Public Utility District No. 2 of
Grant County
(bd)
AD SA 874 various various 10 4,333 4,333 (iq)21,242 21,242
94 Exelon Generation Company,
LLC Bonneville Power Administration Oregon Direct Access FNO SA 943
Bonneville
Power
Administration
various 1 3,969 3,969 21,233 (ir)3,461 24,694
95 Exelon Generation Company,
LLC Bonneville Power Administration Oregon Direct Access (be)
AD SA 943
Bonneville
Power
Administration
various 1 415 415 (is)(300)(300)
96 Exelon Generation Company,
LLC various signatories various signatories NF SA 759 various various 90,006 90,006 1,866,263 (it)
3,397,141 5,263,404
97 Exelon Generation Company,
LLC various signatories various signatories (bf)
AD SA 759 various various 20,074 20,074 (iu)962,317 962,317
98 Exelon Generation Company,
LLC various signatories various signatories SFP SA 760 various various 161,076 161,076 599,263 (iv)60,306 659,569
99 Exelon Generation Company,
LLC various signatories various signatories (bg)
AD SA 760 various various 3,557 3,557 (iw)32,662 32,662
100 Fall River Rural Electric
Cooperative, Inc.Marysville Hydro Partners Idaho Power Company (bh)
OS RS 322 Targhee
Substation
Goshen
Substation
(ix)138,699 138,699
101 Fall River Rural Electric
Cooperative, Inc.Marysville Hydro Partners Idaho Power Company (bi)
AD RS 322 Targhee
Substation
Goshen
Substation
(iy)12,609 12,609
102 Falls Creek H.P. Limited
Partnership Lakeview Airport 10 Portland General Electric (bj)
LFP SA 868
Falls Creek
H.P. Limited
Partnership
Bonneville
Power
Administration
4 13,387 13,387 145,189 (iz)21,673 166,862
103 Falls Creek H.P. Limited
Partnership Lakeview Airport 10 Portland General Electric (bk)
AD SA 868
Falls Creek
H.P. Limited
Partnership
Bonneville
Power
Administration
3 1,302 1,302 (ja)11,591 11,591
104 Garrett Solar LLC Garrett Solar LLC Portland General Electric (bl)
LFP SA 966 Wallula
Substation
Wala-MIDC
path 10 24,852 24,852 354,869 (jb)81,174 436,043
105 Garrett Solar LLC Garrett Solar LLC Portland General Electric (bm)
AD SA 966 Wallula
Substation
Wala-MIDC
path 10 915 915 (jc)22,086 22,086
106 Guzman Energy LLC various signatories various signatories NF SA 786 various various 299,193 299,193 2,603,853 (jd)163,376 2,767,229
107 Guzman Energy LLC various signatories various signatories (bn)
AD SA 786 various various 33,643 33,643 (je)299,529 299,529
108 Guzman Energy LLC various signatories various signatories SFP SA 785 various various 49,244 49,244 396,711 (jf)26,300 423,011
109 Guzman Energy LLC various signatories various signatories (bo)
AD SA 785 various various 25 25 (jg)414 414
110 Idaho Power Company Exxon Mobil Nevada Power Company (bp)
LFP SA 212 Trona
Substation
Red Butte/Mona
Sub 52 38,866 38,866 806,119 (jh)51,126 857,245
111 Idaho Power Company Exxon Mobil Nevada Power Company (bq)
AD SA 212 Trona
Substation
Red Butte/Mona
Sub
(ji)(32,914)(32,914)
112 Idaho Power Company Exxon Mobil Nevada Power Company (br)
LFP SA 1023 Trona
Substation
Red Butte/Mona
Sub 82 1,700,334 (jj)107,047 1,807,381
113 Idaho Power Company various signatories various signatories NF SA 14 various various 675 675 84,667 (jk)5,356 90,023
114 Idaho Power Company various signatories various signatories (bs)
AD SA 14 various various 82 8,845 8,845 (jl)73,537 73,537
115 Idaho Power Marketing
Operations various signatories various signatories NF SA 725 various various 9,830 9,830 12,417 (jm)773 13,190
116 Los Angeles Department of
Water & Power various signatories various signatories SFP SA 143 various various 677 677 6,299 (jn)399 6,698
117 Macquarie Energy LLC various signatories various signatories NF SA 755 various various 127,064 127,064 1,227,003 (jo)77,207 1,304,210
118 Macquarie Energy LLC various signatories various signatories (bt)
AD SA 755 various various 14,837 14,837 (jp)334,465 334,465
119 Macquarie Energy LLC various signatories various signatories SFP SA 754 various various 2,168 2,168 46,651 (jq)2,952 49,603
120 Macquarie Energy LLC various signatories various signatories (bu)
AD SA 754 various various 1,277 1,277 (jr)9,119 9,119
121 MAG Energy Solutions, Inc.various signatories various signatories NF SA 903 various various 6,738 6,738 146,285 (js)9,138 155,423
122 MAG Energy Solutions, Inc.various signatories various signatories (bv)
AD SA 903 various various 8,291 8,291 (jt)189,655 189,655
123 MAG Energy Solutions, Inc.various signatories various signatories SFP SA 902 various various 110 110 10,756 (ju)668 11,424
124 Mercuria Energy America LLC various signatories various signatories NF SA 998 various various 76,089 76,089 666,710 (jv)41,982 708,692
125 Mercuria Energy America LLC various signatories various signatories (bw)
AD SA 998 various various 1,173 1,173 (jw)24,224 24,224
126 Mercuria Energy America LLC various signatories various signatories SFP SA 997 various various 70,450 70,450 376,728 (jx)23,935 400,663
127 Mercuria Energy America LLC various signatories various signatories (bx)
AD SA 997 various various 750 750 (jy)6,784 6,784
128 Moon Lake Electric Association
Inc.Moon Lake Electric Association Moon Lake Electric Association (by)
OS RS 302 Duchesne Duchesne 20,143 20,143 (jz)18,722 18,722
129 Moon Lake Electric Association
Inc.Moon Lake Electric Association Moon Lake Electric Association (bz)
AD RS 302 Duchesne Duchesne 2,180 2,180 (ka)1,702 1,702
130 Morgan Stanley Capital Group,
Inc.various signatories various signatories NF SA 157 various various 202,361 202,361 2,020,366 (kb)127,272 2,147,638
131 Morgan Stanley Capital Group,
Inc.various signatories various signatories (ca)
AD SA 157 various various 10,943 10,943 (kc)94,985 94,985
132 Morgan Stanley Capital Group,
Inc.various signatories various signatories SFP SA 160 various various 103,423 103,423 548,939 (kd)34,808 583,747
133 Morgan Stanley Capital Group,
Inc.various signatories various signatories (cb)
AD SA 160 various various 3,731 3,731 (ke)65,588 65,588
134 Navajo Tribal Utility Authority Navajo Tribal Utility Authority Navajo Tribal Utility Authority FNO SA 894 Four Corners Pinto-Four
Corners 4 25,690 25,690 137,843 (kf)316,112 453,955
135 Navajo Tribal Utility Authority Navajo Tribal Utility Authority Navajo Tribal Utility Authority (cc)
AD SA 894 Four Corners Pinto-Four
Corners 1 1,673 1,673 (kg)5,122 5,122
136 (a)
Nevada Power Company various signatories various signatories NF SA 455 various various 52,498 52,498 288,472 (kh)18,184 306,656
137 Nevada Power Company various signatories various signatories SFP SA 454 various various 4,707 4,707 25,778 (ki)1,626 27,404
138 NextEra Energy Resources, LLC NextEra Energy Resources, LLC Public Utility District No. 2 of
Grant County
(cd)
LFP SA 733 Wallula
Substation
Wala-MIDC
path 94 432 432 1,154,713 (kj)
(199,124)955,589
139 NextEra Energy Resources, LLC NextEra Energy Resources, LLC Public Utility District No. 2 of
Grant County
(ce)
AD SA 733 Wallula
Substation
Wala-MIDC
path 103 1,488 1,488 (kk)238,161 238,161
140 Pacific Gas & Electric Company various signatories various signatories NF SA 338 various various 1,108 1,108 9,101 (kl)578 9,679
141 Phillips 66 Energy Trading various signatories various signatories NF SA 1081 various various 20,770 20,770 149,640 (km)9,504 159,144
142 Phillips 66 Energy Trading various signatories various signatories SFP SA 1080 various various 27,347 27,347 249,500 (kn)80,620 330,120
143 Portland General Electric
Company
Operation, maintenance or
facility lease services with no
receipt or delivery of energy.
Operation, maintenance or
facility lease services with no
receipt or delivery of energy.
(cf)
OS RS 137 various various (ko)3,314 3,314
144 Portland General Electric
Company various signatories various signatories NF SA 8 various various 11,155 11,155 126,052 (kp)7,903 133,955
145 Portland General Electric
Company various signatories various signatories (cg)
AD SA 8 various various 370 370 (kq)4,855 4,855
146 Powerex Corporation Bonneville Power Administration California Independent System
Operator Corporation
(ch)
LFP SA 169
Bonneville
Power
Administration
CRAG View
Substation 83 618,432 618,432 2,838,957 (kr)178,783 3,017,740
147 Powerex Corporation Bonneville Power Administration California Independent System
Operator Corporation
(ci)
AD SA 169
Bonneville
Power
Administration
CRAG View
Substation 83 3,881 3,881 (ks)137,549 137,549
148 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(cj)
LFP SA 1016 Borah Red Butte/Mona
Sub 104 99,784 99,784 3,548,697 (kt)223,479 3,772,176
149 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(ck)
AD SA 1016 Borah Red Butte/Mona
Sub 104 (ku)171,999 171,999
150 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(cl)
LFP SA 1017 Borah Red Butte/Mona
Sub 104 96,595 96,595 3,548,697 (kv)223,479 3,772,176
151 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(cm)
AD SA 1017 Borah Red Butte/Mona
Sub 104 (kw)171,999 171,999
152 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(cn)
LFP SA 1040 Malin 500
Substation
Round Mountain
Sub 100 2,903,802 (kx)182,578 3,086,380
153 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(co)
AD SA 1040 Malin 500
Substation
Round Mountain
Sub 100 (ky)235,108 235,108
154 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(cp)
LFP SA 700 Malin 500
Substation
Round Mountain
Sub 100 3,402,394 (kz)67,324 3,469,718
155 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(cq)
AD SA 700 Malin 500
Substation
Round Mountain
Sub 100 (la)151,089 151,089
156 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(cr)
LFP SA 701 Malin 500
Substation
Round Mountain
Sub 100 3,402,394 (lb)67,324 3,469,718
157 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(cs)
AD SA 701 Malin 500
Substation
Round Mountain
Sub 100 (lc)151,089 151,089
158 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(ct)
LFP SA 702 Malin 500
Substation
Round Mountain
Sub 100 3,402,394 (ld)67,324 3,469,718
159 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(cu)
AD SA 702 Malin 500
Substation
Round Mountain
Sub 100 (le)151,089 151,089
160 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(cv)
LFP SA 748 Malin 500
Substation
Round Mountain
Sub 50 2,628,659 (lf)52,410 2,681,069
161 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(cw)
AD SA 748 Malin 500
Substation
Round Mountain
Sub 50 (lg)391,004 391,004
162 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(cx)
LFP SA 749 Malin 500
Substation
Round Mountain
Sub 150 4,176,129 (lh)82,240 4,258,369
163 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(cy)
AD SA 749 Malin 500
Substation
Round Mountain
Sub 150 (li)(88,827)(88,827)
164 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(cz)
LFP SA 995 Malin 500
Substation
Round Mountain
Sub 100 3,402,394 (lj)67,324 3,469,718
165 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(da)
AD SA 995 Malin 500
Substation
Round Mountain
Sub 100 (lk)151,089 151,089
166 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(db)
LFP SA 996 Malin 500
Substation
Round Mountain
Sub 100 3,402,394 (ll)67,324 3,469,718
167 Powerex Corporation Powerex Corporation California Independent System
Operator Corporation
(dc)
AD SA 996 Malin 500
Substation
Round Mountain
Sub 100 (lm)151,089 151,089
168 Powerex Corporation various signatories various signatories NF SA 47 various various 241,275 241,275 3,739,989 (ln)236,621 3,976,610
169 Powerex Corporation various signatories various signatories (dd)
AD SA 47 various various 11,246 11,246 (lo)169,953 169,953
170 Powerex Corporation various signatories Sacramento Municipal Utility
District SFP SA 151 various various 273,848 273,848 553,646 (lp)35,105 588,751
171 Powerex Corporation various signatories various signatories (de)
AD SA 151 various various 2,875 2,875 (lq)372 372
172 Public Service Co of Co
Various signatories to the Volume
11 Point-to-Point Transmission
Tariff.
Various signatories to the Volume
11 Point-to-Point Transmission
Tariff.
(df)
SFP SA 665 Various Various 250 250 2,329 (lr)145 2,474
173 Public Service of New Mexico
Various signatories to the Volume
11 Point-to-Point Transmission
Tariff.
Various signatories to the Volume
11 Point-to-Point Transmission
Tariff.
(dg)
SFP SA 665 Various Various 222 (ls)14 236
174 Public Utility District No. 1 of
Cowlitz County
Public Utility District No. 1 of
Cowlitz County Bonneville Power Administration (dh)
OS RS 234 Swift Unit No.
2
Woodland
Substation
(lt)202,790 202,790
175 Public Utility District No. 1 of
Cowlitz County
Public Utility District No. 1 of
Cowlitz County Bonneville Power Administration (di)
AD RS 234 Swift Unit No.
2
Woodland
Substation
(lu)18,273 18,273
176 Puget Sound Energy various signatories various signatories NF SA 693 various various 2,679 (lv)170 2,849
177 Puget Sound Energy various signatories various signatories SFP SA 694 various various 3,721 (lw)236 3,957
178 Rainbow Energy Marketing
Corporation various signatories various signatories NF SA 316 various various 111,491 111,491 1,232,411 (lx)77,582 1,309,993
179 Rainbow Energy Marketing
Corporation various signatories various signatories (dj)
AD SA 316 various various 4,354 4,354 (ly)106,215 106,215
180 Rainbow Energy Marketing
Corporation various signatories various signatories SFP SA 261 various various 33,034 33,034 316,822 (lz)35,825 352,647
181 Rainbow Energy Marketing
Corporation various signatories various signatories (dk)
AD SA 261 various various 5,948 5,948 (ma)40,391 40,391
182 Sacramento Municipal Utility
District
Sacramento Municipal Utility
District
Sacramento Municipal Utility
District
(dl)
LFP SA 863 Malin
Substation
Malin
Substation 20 120,063 120,063 674,252 (mb)42,461 716,713
183 Sacramento Municipal Utility
District
Sacramento Municipal Utility
District
Sacramento Municipal Utility
District
(dm)
AD SA 863 Malin
Substation
Malin
Substation 20 12,719 12,719 (mc)100,061 100,061
184 Salt River Project Agricultural
Improvement and Power District
Salt River Project Agricultural
Improvement and Power District
Salt River Project Agricultural
Improvement and Power District
(dn)
LFP SA 809 Enel Cove
Fort
Red Butte
Substation 26 139,331 139,331 887,175 (md)55,870 943,045
185 Salt River Project Agricultural
Improvement and Power District
Salt River Project Agricultural
Improvement and Power District
Salt River Project Agricultural
Improvement and Power District
(do)
AD SA 809 Enel Cove
Fort
Red Butte
Substation 26 14,534 14,534 (me)42,984 42,984
186 Salt River Project Agricultural
Improvement and Power District various signatories various signatories SFP SA 556 various various 334 334 4,142 (mf)258 4,400
187 Shell Energy North America (US),
L.P.NextEra Energy Resources, LLC Public Utility District No. 2 of
Grant County
(dp)
LFP SA 791 Wallula
Substation
Wala-MIDC
path 110 245,333 245,333 2,697,509 (mg)
1,314,708 4,012,217
188 Shell Energy North America (US),
L.P.NextEra Energy Resources, LLC Public Utility District No. 2 of
Grant County
(dq)
AD SA 791 Wallula
Substation
Wala-MIDC
path 25 5,415 5,415 (mh)42,984 42,984
189 Shell Energy North America (US),
L.P.various signatories various signatories NF SA 23 various various 50,836 50,836 685,646 (mi)136,413 822,059
190 Shell Energy North America (US),
L.P.various signatories various signatories (dr)
AD SA 23 various various 5,341 5,341 (mj)56,465 56,465
191 Shell Energy North America (US),
L.P.various signatories various signatories SFP SA 162 various various 99,441 99,441 1,100,752 (mk)69,214 1,169,966
192 Shell Energy North America (US),
L.P.various signatories various signatories (ds)
AD SA 162 various various 836 836 (ml)3,963 3,963
193 (b)
Sierra Pacific Power Company
Operation, maintenance or
facility lease services with no
receipt or delivery of energy.
Operation, maintenance or
facility lease services with no
receipt or delivery of energy.
(dt)
OS RS 674 Sigurd
Substation
Utah-Nevada
Border
(mm)33,147 33,147
194 Sierra Pacific Power Company
Operation, maintenance or
facility lease services with no
receipt or delivery of energy.
Operation, maintenance or
facility lease services with no
receipt or delivery of energy.
(du)
AD RS 674 Sigurd
Substation
Utah-Nevada
Border
(mn)3,013 3,013
195 Southern California Edison
Company various signatories various signatories NF SA 642 various various 263,600 263,600 2,662,023 (mo)
1,033,139 3,695,162
196 Southern California Edison
Company various signatories various signatories (dv)
AD SA 642 various various 44,058 44,058 (mp)420,299 420,299
197 Southern California Edison
Company various signatories various signatories SFP SA 643 various various 671 (mq)42 713
198 Southern California Edison
Company various signatories various signatories (dw)
AD SA 643 various various (mr)578 578
199 Southern California Public Power
Authority Powerex Corporation Southern California Public Power
Authority NF SA 629 Tieton
Substation various (ms)50,524 50,524
200 State of South Dakota Western Area Power
Administration Black Hills Corporation (dx)
LFP SA 779 Yellowtail Sub Wyodak
Substation 4 17,141 17,141 141,948 (mt)8,939 150,887
201 State of South Dakota Western Area Power
Administration Black Hills Corporation (dy)
AD SA 779 Yellowtail Sub Wyodak
Substation 4 1,524 1,524 (mu)6,877 6,877
202 TEC Energy Inc.various signatories various signatories NF SA 1001 various various 70 70 1,209 (mv)77 1,286
203 Tenaska Power Services Co.various signatories various signatories NF SA 125 various various 33,690 33,690 244,020 (mw)151,181 395,201
204 Tenaska Power Services Co.various signatories various signatories (dz)
AD SA 125 various various 4,396 4,396 (mx)45,120 45,120
205 Tenaska Power Services Co.various signatories various signatories SFP SA 126 various various 12,532 12,532 78,918 (my)4,988 83,906
206 Tenaska Power Services Co.various signatories various signatories (ea)
AD SA 126 various various 337 337 (mz)3,334 3,334
207 The Energy Authority, Inc.various signatories various signatories NF SA 310 various various 85,945 85,945 870,708 (na)54,675 925,383
208 The Energy Authority, Inc.various signatories various signatories (eb)
AD SA 310 various various 10,799 10,799 (nb)130,174 130,174
209 The Energy Authority, Inc.various signatories various signatories SFP SA 311 various various 18,467 18,467 142,452 (nc)8,996 151,448
210 The Energy Authority, Inc.various signatories various signatories (ec)
AD SA 311 various various 1,262 1,262 (nd)13,047 13,047
211 Thermo No. 1 BE-01, LLC Thermo Geothermal Project various signatories (ed)
LFP SA 568 South Milford
Sub
Mona
Substation 11 48,442 48,442 390,358 (ne)72,789 463,147
212 Thermo No. 1 BE-01, LLC Thermo Geothermal Project various signatories (ee)
AD SA 568 South Milford
Sub
Mona
Substation 11 5,290 5,290 (nf)23,554 23,554
213 TransAlta Energy Marketing
(U.S.) Inc.various signatories various signatories NF SA 127 various various 68,724 68,724 785,685 (ng)49,277 834,962
214 TransAlta Energy Marketing
(U.S.) Inc.various signatories various signatories (ef)
AD SA 127 various various 6,355 6,355 (nh)243,069 243,069
215 TransAlta Energy Marketing
(U.S.) Inc.various signatories various signatories SFP SA 128 various various 14,182 14,182 127,645 (ni)8,566 136,211
216 TransAlta Energy Marketing
(U.S.) Inc.various signatories various signatories (eg)
AD SA 128 various various 2,248 2,248 (nj)22,891 22,891
217 Tri-State Generation and
Transmission Association, Inc.various signatories Tri-State Generation and
Transmission Association, Inc.FNO SA 628 Dave
Johnston Sub
Thermopolis
Sub 16 112,178 112,178 555,068 (nk)93,285 648,353
218 Tri-State Generation and
Transmission Association, Inc.various signatories Tri-State Generation and
Transmission Association, Inc.
(eh)
AD SA 628 Dave
Johnston Sub
Thermopolis
Sub 19 11,920 11,920 (nl)26,546 26,546
219 Tri-State Generation and
Transmission Association, Inc.various signatories various signatories NF SA 33 various various 10,948 10,948 69,763 (nm)4,364 74,127
220 Tri-State Generation and
Transmission Association, Inc.various signatories various signatories (ei)
AD SA 33 various various 80 80 (nn)377 377
221 Uniper Global Commodoties various signatories various signatories NF SA 992 various various 1,388 1,388 58,441 (no)3,648 62,089
222 Uniper Global Commodoties various signatories various signatories (ej)
AD SA 992 various various 4,934 4,934 25,824 (np)27,587 53,411
223 Uniper Global Commodoties various signatories various signatories SFP SA 991 various various 26 26 223 (nq)14 237
224 U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation FNO SA 506 Walla Walla
Sub Burbank Pumps 1 2,244 2,244 9,141 (nr)10,405 19,546
225 U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation (ek)
AD SA 506 Walla Walla
Sub Burbank Pumps 1 (ns)(782)(782)
226 U.S. Bureau of Reclamation Western Area Power
Administration
Weber Basin Water Conservancy
District
(el)
OS RS 286 various various 10,008 10,008 (nt)21,871 21,871
227 U.S. Bureau of Reclamation Western Area Power
Administration
Weber Basin Water Conservancy
District
(em)
AD RS 286 various various 1,308 1,308 (nu)1,308 1,308
228 U.S. Bureau of Reclamation Bonneville Power Administration Crooked River Irrigation District (en)
OS RS 67 Redmond
Substation
Crooked River
Pumps 21,870 21,870 11,058 11,058
229 Utah Associated Municipal Power
Systems
Utah Associated Municipal Power
Systems
Utah Associated Municipal Power
Systems
(eo)
OS RS 297 various various 551 3,134,517 3,134,517 18,885,649 (nv)
3,354,818 22,240,467
230 Utah Associated Municipal Power
Systems
Utah Associated Municipal Power
Systems
Utah Associated Municipal Power
Systems
(ep)
AD RS 297 various various 436 262,336 262,336 (nw)844,868 844,868
231 Utah Associated Municipal Power
Systems various signatories various signatories NF SA 009 various various 50 50 2,697 (nx)171 2,868
232 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency (eq)
OS RS 637 various various 88 754,410 754,410 2,798,503 (ny)520,391 3,318,894
233 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency (er)
AD RS 637 various various 53 61,376 61,376 (nz)114,838 114,838
234 Utah Municipal Power Agency various signatories various signatories NF SA 20 various various 185,859 185,859 1,259,028 (oa)79,842 1,338,870
235 Utah Municipal Power Agency various signatories various signatories (es)
AD SA 20 various various 497 497 (ob)4,785 4,785
236 Utah Municipal Power Agency various signatories various signatories (et)
AD SA 135 various various 50 50 (oc)235 235
237 Vitol, Inc various signatories various signatories NF SA 1027 various various 105 105 28,353 (od)1,798 30,151
238 Vitol, Inc various signatories various signatories SFP SA 1026 various various 109,671 109,671 865,489 (oe)54,855 920,344
239 Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric (eu)
OS RS 591 Pelton
Reregulating
Round Butte
Sub 44,634 44,634 (of)109,725 109,725
240 Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric (ev)
AD RS 591 Pelton
Reregulating
Round Butte
Sub 5,907 5,907 (og)9,975 9,975
241 Western Area Power
Administration
Western Area Power
Administration
Various Western Area Power
Administration customers in
PacifiCorp's control area.
(ew)
OS RS 262 various various 330 1,333,469 1,253,461 2,160,895 (oh)550,000 2,710,895
242 Western Area Power
Administration
Western Area Power
Administration
Various Western Area Power
Administration customers in
PacifiCorp's control area.
(ex)
AD RS 262 various various 330 170,138 159,931 (oi)241,284 241,284
243 Western Area Power
Administration
Western Area Power
Administration
Various Western Area Power
Administration customers in
PacifiCorp's control area.
(ey)
OS RS 263 various various 33,776 31,747 22,148 (oj)7,251 29,399
244 Western Area Power
Administration
Western Area Power
Administration
Various Western Area Power
Administration customers in
PacifiCorp's control area.
(ez)
AD RS 263 various various 2,273 2,137 (ok)2,263 2,263
245 Western Area Power
Administration
Western Area Power
Administration various signatories (fa)
OS RS 684 Dave
Johnston Sub various
246 Western Area Power
Administration
Western Area Power
Administration
Western Area Power
Administration FNO SA 175 Wyoming
Distribution
Wyoming
Distribution 1 8,979 8,979 36,127 (ol)33,709 69,836
247 Western Area Power
Administration
Western Area Power
Administration Colorado River
Storage Project
Western Area Power
Administration
(fb)
AD SA 175 various Wyoming
Distribution 1 9 9 (om)(1,954)(1,954)
248 Western Area Power
Administration
Western Area Power
Administration Colorado River
Storage Project
various signatories NF SA 137 various various (on)5 5
249
Western Area Power
Administration Colorado River
Storage Project
Western Area Power
Administration Colorado River
Storage Project
various signatories NF SA 132 various various 247,007 (oo)15,396 262,403
250
Western Area Power
Administration Colorado River
Storage Project
Western Area Power
Administration Colorado River
Storage Project
various signatories (fc)
AD SA 132 various various 294 294 (op)2,074 2,074
251 Western Area Power
Administration Colorado Missouri
Western Area Power
Administration Colorado River
Storage Project
various signatories NF SA 724 various various 83,315 83,315 483,671 (oq)30,676 514,347
252 Accrual (487,088)(482,283)(or)
(403,627)(403,627)
35 TOTAL 7,473 17,818,492 17,730,917 105,219,225 33,483,118 31,504,457 170,206,800
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: PaymentByCompanyOrPublicAuthority
This footnote applies to all occurrences of "Nevada Power Company" on page 328. 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.
(b) Concept: PaymentByCompanyOrPublicAuthority
This footnote applies to all occurrences of "Sierra Pacific Power Company" on page 328. 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.
(c) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 965) terminating on December 31, 2024.
(d) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 965) terminating on December 31, 2024.
(e) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(f) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(g) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(h) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(i) Concept: StatisticalClassificationCode
Ancillary services under the Open Access Transmission Tariff (1st Revised Service Agreement 476) in effect until superseded.
(j) Concept: StatisticalClassificationCode
Ancillary services under the Open Access Transmission Tariff (1st Revised Service Agreement 476) in effect until superseded.
(k) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 895) terminating on April 30, 2024.
(l) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 895) terminating on April 30, 2024.
(m) Concept: StatisticalClassificationCode
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.
(n) Concept: StatisticalClassificationCode
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.
(o) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(p) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(q) Concept: StatisticalClassificationCode
Network transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 347) terminating on December 31, 2023.
(r) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 67) terminating on December 31, 2023.
(s) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 67) terminating on December 31, 2023.
(t) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(u) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(v) Concept: StatisticalClassificationCode
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 1.
(w) Concept: StatisticalClassificationCode
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.
(x) Concept: StatisticalClassificationCode
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.
(y) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 656) terminating on August 31, 2030.
(z) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 656) terminating on August 31, 2030.
(aa) Concept: StatisticalClassificationCode
Network transmission service and distribution delivery service under the Open Access Transmission Tariff (9th Revised Service Agreement 229) terminating on September 30, 2028.
(ab) Concept: StatisticalClassificationCode
Network transmission service and distribution delivery service under the Open Access Transmission Tariff (3rd Revised Service Agreement 539) terminating on September 30, 2028.
(ac) Concept: StatisticalClassificationCode
Network transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 538) terminating on September 30, 2028.
(ad) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (10th Revised Service Agreement 229) terminating on September 30, 2028.
(ae) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (10th Revised Service Agreement 229) terminating on September 30, 2028.
(af) Concept: StatisticalClassificationCode
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.
(ag) Concept: StatisticalClassificationCode
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.
(ah) Concept: StatisticalClassificationCode
Network transmission service and distribution delivery service under the Open Access Transmission Tariff (6th Revised Service Agreement 328) terminating on July 31, 2028.
(ai) Concept: StatisticalClassificationCode
Network transmission service under the Open Access Transmission Tariff (2nd Revised Service Agreement 827) terminating on September 30, 2028.
(aj) Concept: StatisticalClassificationCode
Network transmission service and distribution delivery service under the Open Access Transmission Tariff (3rd Revised Service Agreement 746) terminating on June 30, 2028.
(ak) Concept: StatisticalClassificationCode
Network transmission service and distribution delivery service under the Open Access Transmission Tariff (2nd Revised Service Agreement 747) terminating on June 30, 2028.
(al) Concept: StatisticalClassificationCode
Network transmission service under the Open Access Transmission Tariff (2nd Revised Service Agreement 735) terminating on September 30, 2028.
(am) Concept: StatisticalClassificationCode
Network transmission service and distribution delivery service under the Open Access Transmission Tariff (1st Revised Service Agreement 865) terminating on September 30, 2028.
(an) Concept: StatisticalClassificationCode
Network transmission service and distribution delivery service under the Open Access Transmission Tariff (1st Revised Service Agreement 975) terminating on September 30, 2028.
(ao) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ap) Concept: StatisticalClassificationCode
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.
(aq) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 881) terminating on February 29, 2028.
(ar) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 881) terminating on February 29, 2028.
(as) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 899) terminating on September 30, 2028.
(at) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 899) terminating on September 30, 2028.
(au) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 901) terminating on September 30, 2023.
(av) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 901) terminating on September 30, 2023.
(aw) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ax) Concept: StatisticalClassificationCode
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.
(ay) Concept: StatisticalClassificationCode
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.
(az) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ba) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bb) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bc) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 874) terminating on December 31, 2032.
(bd) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 874) terminating on December 31, 2032.
(be) Concept: StatisticalClassificationCode
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.
(bf) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bg) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bh) Concept: StatisticalClassificationCode
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.
(bi) Concept: StatisticalClassificationCode
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.
(bj) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 868) terminating on December 31, 2034.
(bk) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 868) terminating on December 31, 2034.
(bl) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 966) terminating on November 30, 2024.
(bm) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 966) terminating on November 30, 2024.
(bn) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bo) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bp) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 212) terminating on May 31, 2024.
(bq) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 212) terminating on May 31, 2024.
(br) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff Service Agreement 1023) terminating on December 31, 2027.
(bs) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bt) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bu) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bv) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bw) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bx) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(by) Concept: StatisticalClassificationCode
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 at any
time after October 14, 2016, by providing two years written notice.
(bz) Concept: StatisticalClassificationCode
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 at any
time after October 14, 2016, by providing two years written notice.
(ca) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(cb) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(cc) Concept: StatisticalClassificationCode
Network transmission service under the Open Access Transmission Tariff (Service Agreement 894) terminating on December 31, 2057.
(cd) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 733) terminating on November 30, 2027.
(ce) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 733) terminating on November 30, 2027.
(cf) Concept: StatisticalClassificationCode
Legacy contract (1st Revised Rate Schedule 137) executed between PacifiCorp and Portland General Electric Company for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge for the Dalreed Substation, which terminated December 2013.
(cg) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ch) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 169) terminating on October 31, 2025.
(ci) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 169) terminating on October 31, 2025.
(cj) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 1016) terminating on June 30, 2024.
(ck) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 1016) terminating on June 30, 2024.
(cl) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 1017) terminating on June 30, 2024.
(cm) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 1017) terminating on June 30, 2024.
(cn) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 1040) terminating on September 30, 2023.
(co) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 1040) terminating on September 30, 2023.
(cp) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 700) terminating on April 1, 2027.
(cq) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 700) terminating on April 1, 2027.
(cr) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 701) terminating on April 1, 2027.
(cs) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 701) terminating on April 1, 2027.
(ct) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 702) terminating on April 1, 2027.
(cu) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 702) terminating on April 1, 2027.
(cv) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 748) terminating on December 31, 2023.
(cw) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 748) terminating on December 31, 2023.
(cx) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 749) terminating on December 31, 2023.
(cy) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 749) terminating on December 31, 2023.
(cz) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 995) terminating on December 31, 2025.
(da) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 995) terminating on December 31, 2025.
(db) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 996) terminating on December 31, 2025.
(dc) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 996) terminating on December 31, 2025.
(dd) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(de) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(df) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dg) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dh) Concept: StatisticalClassificationCode
Legacy contract (Rate Schedule 234) providing for transmission and operation of Swift Hydroelectric plant No. 2 and for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Agreement may be terminated subsequent to the termination of the power
contract as defined in the agreement by the customer providing at least six-months written notice and specifying the date on which the customer will assume responsibility of operations and maintenance of Swift Hydroelectric plant No. 2.
(di) Concept: StatisticalClassificationCode
Legacy contract (Rate Schedule 234) providing for transmission and operation of Swift Hydroelectric plant No. 2 and for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Agreement may be terminated subsequent to the termination of the power
contract as defined in the agreement by the customer providing at least six-months written notice and specifying the date on which the customer will assume responsibility of operations and maintenance of Swift Hydroelectric plant No. 2.
(dj) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dk) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dl) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 863) terminating on June 30, 2027.
(dm) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 863) terminating on June 30, 2027.
(dn) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 809) terminating on October 31, 2025.
(do) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 809) terminating on October 31, 2025.
(dp) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 791) terminating upon written notification.
(dq) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 791) terminating upon written notification.
(dr) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ds) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dt) Concept: StatisticalClassificationCode
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.
(du) Concept: StatisticalClassificationCode
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.
(dv) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dw) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dx) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 779) terminating on August 31, 2024.
(dy) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 779) terminating on August 31, 2024.
(dz) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ea) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(eb) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ec) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ed) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 568) terminating on April 30, 2029.
(ee) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 568) terminating on April 30, 2029.
(ef) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(eg) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(eh) Concept: StatisticalClassificationCode
Network transmission service under the Open Access Transmission Tariff (10th Revised Service Agreement 628) terminating on June 30, 2031.
(ei) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ej) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ek) Concept: StatisticalClassificationCode
Network transmission service and distribution delivery service under the Open Access Transmission Tariff (2nd Revised Service Agreement 506) terminating upon written notification.
(el) Concept: StatisticalClassificationCode
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.
(em) Concept: StatisticalClassificationCode
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.
(en) Concept: StatisticalClassificationCode
Legacy contract (3rd Amended Rate Schedule 67) executed between PacifiCorp and United States Department of the Interior, Bureau of Reclamation Crooked River Irrigation District for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Agreement
termination with one year written notice.
(eo) Concept: StatisticalClassificationCode
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.
(ep) Concept: StatisticalClassificationCode
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.
(eq) Concept: StatisticalClassificationCode
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.
(er) Concept: StatisticalClassificationCode
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.
(es) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(et) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(eu) Concept: StatisticalClassificationCode
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.
(ev) Concept: StatisticalClassificationCode
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.
(ew) Concept: StatisticalClassificationCode
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.
(ex) Concept: StatisticalClassificationCode
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.
(ey) Concept: StatisticalClassificationCode
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.
(ez) Concept: StatisticalClassificationCode
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.
(fa) Concept: StatisticalClassificationCode
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.
(fb) Concept: StatisticalClassificationCode
Evergreen network transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 175).
(fc) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(fd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(fe) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ff) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(fk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(fo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(fs) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ft) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Distribution voltage service charge. Primary delivery service. Scheduling, system control and dispatch service. Reactive supply and voltage control service. Regulation and frequency response service.
(fv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ga) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(gb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(gc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Transmission resale - purchase of point-to-point transmission. Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(gd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ge) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(gf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(gh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(gj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(gl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
(gm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Reactive supply and voltage control service.
(go) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(gq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(gs) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(gu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Reactive supply and voltage control service.
(gw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(gy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(ha) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(hb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(hc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(hd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(he) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(hf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(hh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(hi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(hj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(hk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(hl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(hm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(hn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ho) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hs) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ht) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(hu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(hv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(hw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(hx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(hz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ia) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ib) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ic) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(id) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ie) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(if) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(ig) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ih) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ii) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ij) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ik) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(il) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(im) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(in) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(io) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Transmission resale, amount paid by seller. Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ip) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(iq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ir) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(is) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(it) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(iu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(iv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(iw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ix) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(iy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(iz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ja) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(jb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(jc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(jd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(je) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(jf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(jh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ji) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(jj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(jm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(jq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(js) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ju) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(jx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(jz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(ka) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(kb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(kd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ke) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(kf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(kg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(kh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ki) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(kk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(kl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(km) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ko) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
(kp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(kr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ks) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(kt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ku) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(kv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(kx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ky) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(la) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(lb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(lc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ld) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(le) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(lf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(lg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(lh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(li) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(lj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(lk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ll) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(lm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ln) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(lp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(lr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ls) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(lt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(lu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(lv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ly) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(lz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ma) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(mb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(md) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(me) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(mf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(mi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(mj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(mk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ml) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(mm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
(mn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(mo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(mp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(mq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ms) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Unauthorized use of transmission service. Generation regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(mt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(mv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(my) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(na) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(nb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(nc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(nd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ne) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(nf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ng) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(nh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ni) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(nj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(nk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(nl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(nm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(nn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(no) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(np) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(nq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(nr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(ns) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(nt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Energy consumption charge for deliveries at and below 138kV.
(nu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(nv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(nw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(nx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ny) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(nz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(oa) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ob) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(oc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(od) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(oe) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(of) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
(og) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(oh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Fixed termination fee associated with a contract cancellation applied for the duration of this agreement.
(oi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Fixed termination fee associated with a contract cancellation applied for the duration of this agreement. Prior Period Adjustment.
(oj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Charges for low-voltage transmission of power and energy.
(ok) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Charges for low-voltage transmission of power and energy. Prior period adjustment.
(ol) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Distribution voltage service charge. Primary delivery service. Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(om) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(on) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(oo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(op) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(oq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(or) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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.
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
TRANSMISSION OF ELECTRICITY BY ISO/RTOs
1. Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a).
3. In Column (b) 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.
4. In column (c) 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 (b) was provided.
5. In column (d) report the revenue amounts as shown on bills or vouchers.
6. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line
No.
Payment Received by (Transmission Owner Name)
(a)
Statistical
Classification
(b)
FERC Rate Schedule or Tariff
Number
(c)
Total Revenue by Rate Schedule
or Tariff
(d)
Total Revenue
(e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
40 TOTAL
FERC FORM NO. 1 (REV 03-07)
Page 331
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
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.
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line
No.(a)(b)(c)(d)(e)(f)
(g)(h)
1 Adams Solar Center, LLC (h)
AD (cf)39 39
2 Adams Solar Center, LLC (i)(j)
LFP (cg)(55,304)(55,304)
3 Adams Solar Center, LLC (k)
OS (ch)(10,704)(10,704)
4 American Gilsonite Company (l)(m)
LFP (ci)(61,758)(61,758)
5 American Gilsonite Company (n)
OS (cj)(462)(462)
6 Arizona Public Service Company (o)
AD (ck)66,652 66,652
7 Arizona Public Service Company NF 7,370 7,370 32,701 32,701
8 Arizona Public Service Company (p)
OS (cl)251,399 251,399
9 Arizona Public Service Company SFP 1,529,750 1,529,750 8,531,167 8,531,167
10 Ashland, City of FNS 2,666 2,666 26,663 26,663
11 Avista Corporation (q)
AD (cm)(1,772)(1,772)
12 Avista Corporation FNS 41,620 40,404 196,137 196,137
13 Avista Corporation NF 48,142 48,142 332,664 332,664
14 Avista Corporation (r)
OS (cn)8,060 8,060
15 Avista Corporation SFP 41,443 41,443 218,349 218,349
16 Basin Electric Power Cooperative, Inc.NF 324 324 483 483
17 Basin Electric Power Cooperative, Inc.(s)
OS (co)136 136
18 Big Horn Rural Electric Company (t)
AD (cp)156 156
19 Big Horn Rural Electric Company (u)(v)
OLF 30,845 30,845 (cq)140,405 140,405
20 Black Hills Power, Inc.(w)
AD (cr)(625)(625)
21 Black Hills Power, Inc.NF 1,138 1,138 1,138 1,138
22 Black Hills Power, Inc.(x)
OS (cs)1,143 1,143
23 Black Hills Power, Inc.SFP 288 288 2,572 2,572
24 Bonneville Power Administration (y)
AD (ct)233,076 233,076
25 Bonneville Power Administration FNS 4,148 4,311 8,326,258 8,326,258
26 Bonneville Power Administration (z)
LFP 5,120,827 5,321,699 68,730,715 68,730,715
27 Bonneville Power Administration NF 975,768 1,014,760 5,541,263 5,541,263
28 Bonneville Power Administration (aa)
OLF 2,450,747 2,546,869 2,654,400 2,654,400
29 Bonneville Power Administration (ab)(ac)(ad)
OS
(cu)(cv)
18,563,807 18,563,807
30 Bonneville Power Administration SFP 69,127 71,901 3,045,243 3,045,243
31 Caerus Uinta LLC (ae)(af)
LFP
(cw)
(231,594)(231,594)
32 Caerus Uinta LLC (ag)
OS (cx)(1,730)(1,730)
33 California Independent System Operator
Corporation
(ah)
AD (cy)(574)(574)
Name of Company or Public Authority
(Footnote Affiliations)
Statistical
Classification
MegaWatt Hours
Received
MegaWatt Hours
Delivered Demand Charges ($)Energy Charges ($)
Other
Charges
($)
Total Cost of
Transmission
($)
34 California Independent System Operator
Corporation
(ai)
OS
(cz)
11,344,062 11,344,062
35 California Independent System Operator
Corporation SFP 34,107 34,107
36 Chipeta Gas Processing LLC (aj)(ak)
LFP
(da)
(509,508)(509,508)
37 Chipeta Gas Processing LLC (al)
OS (db)(3,808)(3,808)
38 Deseret Generation & Transmission
Cooperative
(am)
LFP 674,520 674,520 2,377,701 2,377,701
39 Deseret Generation & Transmission
Cooperative NF 3,653 3,653 21,088 21,088
40 Elbe Solar Center, LLC (an)
AD (dc)194 194
41 Elbe Solar Center, LLC (ao)(ap)
LFP
(dd)
(253,272)(253,272)
42 Elbe Solar Center, LLC (aq)
OS (de)(50,698)(50,698)
43 Flathead Electric Cooperative, Inc.(ar)
OS (df)72,867 72,867
44 (a)
Hermiston Generating Company, L.P.
(as)
OS (dg)240,039 240,039
45 Idaho Power Company (at)
AD (dh)14,620 14,620
46 Idaho Power Company FNS 13,839 13,839
47 Idaho Power Company (au)
LFP 4,467,600 4,467,600 15,937,398 15,937,398
48 Idaho Power Company NF 83,421 83,421 422,272 422,272
49 Idaho Power Company (av)(aw)
OLF (di)29,760 29,760
50 Idaho Power Company (ax)
OS (dj)30,357 30,357
51 Idaho Power Company SFP 68,880 68,880 287,821 287,821
52 Los Angeles Department of Water and
Power
(ay)
AD (dk)1,645 1,645
53 Los Angeles Department of Water and
Power NF 10,548 10,548 83,471 83,471
54 Los Angeles Department of Water and
Power
(az)
OS (dl)8,380 8,380
55 Moon Lake Electric Association, Inc.(ba)
FNS 22 22 (dm)287,698 287,698
56 Morgan City Corporation (bb)
LFP 1,419 1,419
57 (b)
Nevada Power Company
(bc)
AD (dn)(13,939)(13,939)
58 (c)
Nevada Power Company NF 22,285 22,285 119,678 119,678
59 (d)
Nevada Power Company
(bd)
OS (do)27,015 27,015
60 (e)
Nevada Power Company SFP 210,312 210,312 768,720 768,720
61 NorthWestern Corporation (be)
AD (dp)1,982 1,982
62 NorthWestern Corporation NF 70,300 70,300 114,516 114,516
63 NorthWestern Corporation (bf)
OS (dq)258,027 258,027
64 NorthWestern Corporation SFP 9,216 35,565 49,920 49,920
65 Platte River Power Authority (bg)
LFP 219,000 219,000 998,065 998,065
66 Platte River Power Authority NF 159 159 906 906
67 Platte River Power Authority (bh)
OS (dr)40,931 40,931
68 Portland General Electric Company (bi)
AD (ds)(21,952)(21,952)
69 Portland General Electric Company (bj)
LFP 105,120 105,120 163,092 163,092
70 Portland General Electric Company NF 2,924 2,924 4,812 4,812
71 Portland General Electric Company (bk)(bl)
OLF (dt)705 705
72 Portland General Electric Company (bm)
OS 2,180 (du)16,171 16,171
73 Public Service Company of Colorado (bn)
AD
(dv)
(127,763)(127,763)
74 Public Service Company of Colorado (bo)
LFP 394,943 394,943 2,288,661 2,288,661
75 Public Service Company of Colorado NF 366,384 366,384 3,066,529 3,066,529
76 Public Service Company of Colorado (bp)
OS (dw)429,831 429,831
77 Public Service Company of New Mexico (bq)
AD (dx)(880)(880)
78 Salt River Project (br)
AD (dy)(735)(735)
79 (f)
Sierra Pacific Power Company NF 11,033 11,033 29,023 16,433 45,456
80 (g)
Sierra Pacific Power Company
(bs)
OS (dz)1,166 1,166
81 Surprise Valley Electrification Corp.(bt)(bu)
OLF (ea)7,524 7,524
82 Tri-State Generation and Transmission
Association, Inc.
(bv)
AD
(eb)
(180,484)(180,484)
83 Tri-State Generation and Transmission
Association, Inc.
(bw)
LFP 420,480 420,480 1,187,676 1,187,676
84 Tri-State Generation and Transmission
Association, Inc.NF 10,613 10,613 117,519 117,519
85 Tri-State Generation and Transmission
Association, Inc.
(bx)
OS (ec)21,462 21,462
86 Tri-State Generation and Transmission
Association, Inc.SFP 60 60 881 881
87 Tucson Electric Power Company (by)
OS (ed)933 933
88 Tucson Electric Power Company SFP 1,600 1,600 4,286 4,286
89 Western Area Power Administration (bz)
AD (ee)(192)(192)
90 Western Area Power Administration FNS 923,161 923,161 5,388,969 5,388,969
91 Western Area Power Administration NF 1,145,481 1,145,481 3,528,832 3,528,832
92 Western Area Power Administration (ca)(cb)(cc)
OS
(ef)(eg)
842,756 842,756
93 Western Area Power Administration SFP 4,384 4,384 10,496 10,496
94 Westport Field Services, LLC (cd)(ce)
LFP
(eh)
(802,860)(802,860)
95 Accrual (ei)
(148,363)(148,363)
TOTAL 19,550,302 19,916,538 134,599,261 78,622 30,464,021 165,141,904
FERC FORM NO. 1 (REV. 02-04)
Page 332
FOOTNOTE DATA
(a) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Hermiston Generating Company, L.P. operates the Hermiston Generating Plant, which is jointly owned. PacifiCorp owns 50% of the plant.
(b) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
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.
(c) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
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.
(d) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
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.
(e) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
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.
(f) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
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.
(g) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
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.
(h) Concept: StatisticalClassificationCode
Settlement adjustment.
(i) Concept: StatisticalClassificationCode
Adams Solar Center, LLC - contract termination date: October 30, 2036.
(j) Concept: StatisticalClassificationCode
Reimbursement for third-party services.
(k) Concept: StatisticalClassificationCode
Ancillary services.
(l) Concept: StatisticalClassificationCode
American Gilsonite Company - Contract Termination Date: February 28, 2029.
(m) Concept: StatisticalClassificationCode
Reimbursement for third-party services.
(n) Concept: StatisticalClassificationCode
Ancillary services.
(o) Concept: StatisticalClassificationCode
Settlement adjustment.
(p) Concept: StatisticalClassificationCode
Ancillary services.
(q) Concept: StatisticalClassificationCode
Settlement adjustment.
(r) Concept: StatisticalClassificationCode
Ancillary services.
(s) Concept: StatisticalClassificationCode
Ancillary services.
(t) Concept: StatisticalClassificationCode
Settlement adjustment.
(u) Concept: StatisticalClassificationCode
Big Horn Rural Electric Company - contract termination date: March 10, 2027.
(v) Concept: StatisticalClassificationCode
Use of facilities.
(w) Concept: StatisticalClassificationCode
Settlement adjustment.
(x) Concept: StatisticalClassificationCode
Ancillary services.
(y) Concept: StatisticalClassificationCode
Settlement adjustment.
(z) Concept: StatisticalClassificationCode
Bonneville Power Administration - Contract Termination Dates: February 2024, July 2024, September 2024, October 2024, November 2024, January 2025, October 2025, November 2025, January 2026, July 2026, September 2026,
November 2026, December 2026, January 2027, March 2027, April 2027, July 2027, November 2027, March 2028, July 2028, October 28, December 2028, January 2029, November 2033, December 2041, and evergreen.
(aa) Concept: StatisticalClassificationCode
Bonneville Power Administration - Contract Termination Dates: September 30, 2027, November 30, 2041, and evergreen.
(ab) Concept: StatisticalClassificationCode
Ancillary services.
(ac) Concept: StatisticalClassificationCode
Bonneville Power Administration - Legacy Contract executed between PacifiCorp and Bonneville Power Administration concerning the exchange of transmission services over agreed-upon facilities ("Midpoint-Meridian
Transmission Agreement", Rate Schedule 369). This agreement runs concurrently with the AC Intertie Agreement (Rate Schedule 368), which terminates when the facilities subject to that agreement are taken out of service.
See also page 328, Transmission of electricity for others, in this Form No. 1
(ad) Concept: StatisticalClassificationCode
Use of facilities.
(ae) Concept: StatisticalClassificationCode
Caerus Uinta LLC - Contract Termination Date: March 31, 2025.
(af) Concept: StatisticalClassificationCode
Reimbursement for third-party services.
(ag) Concept: StatisticalClassificationCode
Ancillary services.
(ah) Concept: StatisticalClassificationCode
Settlement adjustment.
(ai) Concept: StatisticalClassificationCode
Ancillary services.
(aj) Concept: StatisticalClassificationCode
Chipeta Gas Processing LLC - Contract Termination Date: December 31, 2028.
(ak) Concept: StatisticalClassificationCode
Reimbursement for third-party services.
(al) Concept: StatisticalClassificationCode
Ancillary services.
(am) Concept: StatisticalClassificationCode
Deseret Generation & Transmission Cooperative - contract termination date: November 1, 2034.
(an) Concept: StatisticalClassificationCode
Settlement adjustment.
(ao) Concept: StatisticalClassificationCode
Elbe Solar Center, LLC - contract termination date: October 30, 2036.
(ap) Concept: StatisticalClassificationCode
Reimbursement for third-party services.
(aq) Concept: StatisticalClassificationCode
Ancillary services.
(ar) Concept: StatisticalClassificationCode
Use of facilities.
(as) Concept: StatisticalClassificationCode
Use of facilities.
(at) Concept: StatisticalClassificationCode
Settlement adjustment.
(au) Concept: StatisticalClassificationCode
Idaho Power Company - contract termination dates: April 1, 2025 and July 1, 2025.
(av) Concept: StatisticalClassificationCode
Use of facilities.
(aw) Concept: StatisticalClassificationCode
Idaho Power Company - The contract termination date of August 31, 2022 shall automatically renew for each successive one-year period thereafter unless or until the earlier of (i) one year following Department of
Energy’s receipt of written notice by PacifiCorp if due to a re-configuration of its transmission system, PacifiCorp no longer needs use of the Department of Energy Scoville Facilities; or (ii) upon mutual agreement of
the parties.
(ax) Concept: StatisticalClassificationCode
Ancillary services.
(ay) Concept: StatisticalClassificationCode
Settlement adjustment.
(az) Concept: StatisticalClassificationCode
Ancillary services.
(ba) Concept: StatisticalClassificationCode
Use of facilities.
(bb) Concept: StatisticalClassificationCode
Morgan City Corporation - contract termination date: evergreen.
(bc) Concept: StatisticalClassificationCode
Settlement adjustment.
(bd) Concept: StatisticalClassificationCode
Ancillary services.
(be) Concept: StatisticalClassificationCode
Settlement adjustment.
(bf) Concept: StatisticalClassificationCode
Ancillary services.
(bg) Concept: StatisticalClassificationCode
Platte River Power Authority - contract termination date: October 31, 2027.
(bh) Concept: StatisticalClassificationCode
Ancillary services.
(bi) Concept: StatisticalClassificationCode
Settlement adjustment.
(bj) Concept: StatisticalClassificationCode
Portland General Electric Company - contract termination date: April 1, 2027.
(bk) Concept: StatisticalClassificationCode
Use of facilities.
(bl) Concept: StatisticalClassificationCode
Portland General Electric Company - contract termination date: Upon two years written notice.
(bm) Concept: StatisticalClassificationCode
Ancillary services.
(bn) Concept: StatisticalClassificationCode
Settlement adjustment.
(bo) Concept: StatisticalClassificationCode
Public Service Company of Colorado - contract termination dates: The date that all generating plants comprising PacifiCorp resources associated with this agreement have been retired from service or interests
transferred; and November 1, 2025.
(bp) Concept: StatisticalClassificationCode
Ancillary services.
(bq) Concept: StatisticalClassificationCode
Settlement adjustment.
(br) Concept: StatisticalClassificationCode
Settlement adjustment.
(bs) Concept: StatisticalClassificationCode
Ancillary services.
(bt) Concept: StatisticalClassificationCode
Use of facilities.
(bu) Concept: StatisticalClassificationCode
Surprise Valley Electrification Corp. - contract termination date: evergreen
(bv) Concept: StatisticalClassificationCode
Settlement adjustment.
(bw) Concept: StatisticalClassificationCode
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.
(bx) Concept: StatisticalClassificationCode
Ancillary services.
(by) Concept: StatisticalClassificationCode
Ancillary services.
(bz) Concept: StatisticalClassificationCode
Settlement adjustment.
(ca) Concept: StatisticalClassificationCode
Ancillary services.
(cb) Concept: StatisticalClassificationCode
Use of facilities.
(cc) Concept: StatisticalClassificationCode
Western Area Power Administration - Legacy contract (Rate Schedule 684) executed between PacifiCorp and Western Area Power Administration for transmission services over agreed-upon facilities. The contract is subject to
terminate upon the earlier of five years after written notice and mutual agreement or June 30, 2042.
(cd) Concept: StatisticalClassificationCode
Westport Field Services, LLC - contract termination date: evergreen.
(ce) Concept: StatisticalClassificationCode
Reimbursement for third-party services.
(cf) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cg) Concept: OtherChargesTransmissionOfElectricityByOthers
Reimbursement for third-party services.
(ch) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(ci) Concept: OtherChargesTransmissionOfElectricityByOthers
Reimbursement for third-party services.
(cj) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(ck) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cl) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cm) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cn) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(co) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cp) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cq) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(cr) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cs) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(ct) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cu) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cv) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(cw) Concept: OtherChargesTransmissionOfElectricityByOthers
Reimbursement for third-party services.
(cx) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cy) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cz) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(da) Concept: OtherChargesTransmissionOfElectricityByOthers
Reimbursement for third-party services.
(db) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(dc) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(dd) Concept: OtherChargesTransmissionOfElectricityByOthers
Reimbursement for third-party services.
(de) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(df) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(dg) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(dh) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(di) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(dj) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(dk) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(dl) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(dm) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(dn) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(do) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(dp) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(dq) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(dr) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(ds) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(dt) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(du) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(dv) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(dw) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(dx) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(dy) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(dz) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(ea) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(eb) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(ec) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(ed) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(ee) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(ef) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(eg) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(eh) Concept: OtherChargesTransmissionOfElectricityByOthers
Reimbursement for third-party services.
(ei) Concept: OtherChargesTransmissionOfElectricityByOthers
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.
FERC FORM NO. 1 (REV. 02-04)
Page 332
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.Description
(a)
Amount
(b)
1 1,878,799
2
3
4
5
6 Business & Economic Development and Corporate Memberships & Subscriptions:
7 American Fork Chamber of Commerce 5,000
8 Arlington Club 6,196
9 Carbon County Economic Development Corporation 5,000
10 ChamberWest 7,500
11 Clatsop Economic Development Resources 5,000
12 Economic Development for Central Oregon 10,000
13 Greater Portland, Inc.6,000
14 Greater Yakima Chamber of Commerce 5,000
15 Jordan River Commission 7,500
16 Klamath County Economic Development Association 5,000
17 Lander Chamber of Commerce 5,000
18 Ogden-Weber Chamber of Commerce 6,000
19 Oregon Business Council 38,708
20 Oregon Economic Development Association 5,000
21 Oregon State University, Utility Pole Research Cooperative 15,000
22 Portland Business Alliance 38,320
23 Portland Metro Chamber 35,245
24 Redmond Economic Development, Inc.5,000
25 Salt Lake Chamber 27,000
26 South Coast Development Council, Inc 5,000
27 South Valley Chamber 5,000
28 Sport Oregon 7,500
29 Stayton-Sublimity Chamber of Commerce 5,000
30 Utah Taxpayers Association 18,700
31 Utah Valley Chamber of Commerce 10,000
32 Walla Walla Valley Chamber of Commerce 10,000
33 Wyoming Construction Coalition, Inc.5,500
34 Yakima County Development Association 7,500
35 Other (Individually < $5,000)118,984
36 Rating Agency and Trustee Fees:
37 Computershare Shareowner Services, LLC 26,692
38 Moody's Investors Service 116,132
39 Standard and Poor's Financial Services, LLC 202,647
40 The Bank of New York Mellon 136,814
41 U.S. Bank National Association 13,858
46 2,805,595
FERC FORM NO. 1 (ED. 12-94)
Page 335
Industry Association Dues
Nuclear Power Research Expenses
Other Experimental and General Research Expenses
Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities
Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
TOTAL
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
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 B 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 of 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.
A. Summary of Depreciation and Amortization Charges
Line
No.(a)(b)(c)(d)(e)(f)
1 Intangible Plant 61,586,054 61,586,054
2 Steam Production Plant 370,620,694 370,620,694
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 31,053,848 313,878 31,367,726
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 213,540,550 75,825 213,616,375
7 Transmission Plant 139,702,687 139,702,687
8 Distribution Plant 216,914,160 216,914,160
9 Regional Transmission and Market Operation
10 General Plant 51,650,631 674,030 52,324,661
11 Common Plant-Electric
12 TOTAL (a)1,023,482,570 (b)0 62,649,787 1,086,132,357
B. Basis for Amortization Charges
The Amortization of Limited-Term Electric Plant is based on straight-line amortization over the life of the asset.
C. Factors Used in Estimating Depreciation Charges
Line
No.(a)(b)(c)(d)(e)(f)(g)
12
OTHER
PRODUCTION
PLANT: FOOTE
CREEK III-IV /
Common - WIND:
340.20
4.048 3.35%
13
OTHER
PRODUCTION
PLANT: FOOTE
CREEK III-IV /
Common - WIND:
341.00
2.148 3.35%
14
OTHER
PRODUCTION
PLANT: FOOTE
CREEK III-IV /
Common - WIND:
343.00
62.122 3.35%
15
OTHER
PRODUCTION
PLANT: FOOTE
CREEK III-IV /
Common - WIND:
344.00
3.695 3.35%
16
OTHER
PRODUCTION
PLANT: FOOTE
CREEK III-IV /
Common - WIND:
345.00
3.037 3.35%
17
OTHER
PRODUCTION
PLANT: FOOTE
CREEK III-IV /
Common - WIND:
346.00
1.022 3.35%
Functional Classification Depreciation Expense
(Account 403)
Depreciation Expense for
Asset Retirement Costs
(Account 403.1)
Amortization of Limited
Term Electric Plant
(Account 404)
Amortization of Other
Electric Plant (Acc 405)Total
Account No.Depreciable Plant Base (in
Thousands)Estimated Avg. Service Life Net Salvage
(Percent)
Applied Depr.
Rates (Percent)Mortality Curve Type Average Remaining Life
18
DISTRIBUTION
PLANT:
CALIFORNIA -
DISTRIBUTION:
360.20
1.204 65 years 1.25%R4 33 years, 2 months, 12 days
19
DISTRIBUTION
PLANT:
CALIFORNIA -
DISTRIBUTION:
361.00
8.816 55 years (10)%1.94%R2.5 41 years, 2 months, 12 days
20
DISTRIBUTION
PLANT:
CALIFORNIA -
DISTRIBUTION:
362.00
46.267 50 years (25)%2.41%R1 39 years, 1 month, 6 days
21
DISTRIBUTION
PLANT:
CALIFORNIA -
DISTRIBUTION:
364.00
122.291 55 years (100)%3.49%R1.5 40 years, 2 months, 12 days
22
DISTRIBUTION
PLANT:
CALIFORNIA -
DISTRIBUTION:
365.00
88.636 65 years (60)%2.34%R1 44 years, 10 months, 24 days
23
DISTRIBUTION
PLANT:
CALIFORNIA -
DISTRIBUTION:
366.00
21.042 60 years (45)%2.26%R4 37 years, 8 months, 12 days
24
DISTRIBUTION
PLANT:
CALIFORNIA -
DISTRIBUTION:
367.00
22.769 55 years (40)%2.38%R3 35 years
25
DISTRIBUTION
PLANT:
CALIFORNIA -
DISTRIBUTION:
368.00
61.493 55 years (40)%2.42%R2 37 years, 3 months, 18 days
26
DISTRIBUTION
PLANT:
CALIFORNIA -
DISTRIBUTION:
369.10
12.275 55 years (50)%2.65%R1.5 40 years, 2 months, 12 days
27
DISTRIBUTION
PLANT:
CALIFORNIA -
DISTRIBUTION:
369.20
18.603 60 years (50)%2.4%R4 41 years, 1 month, 6 days
28
DISTRIBUTION
PLANT:
CALIFORNIA -
DISTRIBUTION:
370.00
9.396 20 years (3)%4.7%S3 12 years, 9 months, 18 days
29
DISTRIBUTION
PLANT:
CALIFORNIA -
DISTRIBUTION:
371.00
0.287 26 years (50)%5.09%L0 13 years, 8 months, 12 days
30
DISTRIBUTION
PLANT:
CALIFORNIA -
DISTRIBUTION:
373.00
0.807 35 years (45)%3.9%O1 23 years, 7 months, 6 days
31
(c)
STEAM
PRODUCTION
PLANT
32
(d)
FERC Sub-
Accounts
33
(e)
Account 403 -
Provisions
FERC FORM NO. 1 (REV. 12-03)
Page 336-337
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments
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, 2023, depreciation expense
associated with transportation equipment was $24,646,729.
(b) Concept: DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as a regulatory asset or liability.
(c) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges
The Oregon Public Utility Commission required modifications related to the depreciable lives of coal-fired generating facilities. Below are the affected facilities and the lives and rates required by Oregon.
Account No.
Depreciable Plant Base (In
Thousands)Estimated Avg. Service Life Net Salvage (Percent)Applied Depr. Rate (Percent)Mortality Curve Type Average Remaining Life
(a)(b)(c)(d)(e)(f)(g)
STEAM PRODUCTION PLANT
JIM BRIDGER GENERATING STATION
JIM BRIDGER UNIT 1
311.00 15,467 0.49
312.00 177,837 1.82
314.00 47,478 1.75
315.00 10,822 0.46
316.00 298 (0.21)
JIM BRIDGER UNIT 2
311.00 13,100 1.89
312.00 176,578 3.37
314.00 60,989 3.45
315.00 9,429 2.17
316.00 198 0.87
JIM BRIDGER COMMON
310.20 281 4.46
311.00 109,156 3.94
312.00 95,200 2.97
314.00 9,683 3.94
315.00 17,095 3.76
316.00 4,422 11.14
(d) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges
FERC Sub Acct Description
310.20 Land Rights
340.20 Land Rights
360.20 Land Rights
369.10 Overhead Services
369.20 Underground Services
(e) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges
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.
FERC FORM NO. 1 (REV. 12-03)
Page 336-337
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
REGULATORY COMMISSION EXPENSES
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.
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 columns (f), (g), and (h), expenses incurred during the year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO
Line
No.
(a)
(b)(c)(d)(e)
(f)(g)(h)
(i)
(j)(k)
(l)
1 Utah Public Service
Commission: Annual Fee 6,841,260 6,841,260 Electric 928 6,841,260
2
Utah Public Service
Commission: Rate Cases
and Proceedings
165,040 165,040 Electric 928 165,040
3 Oregon Public Utility
Commission: Annual Fee 6,951,566 6,951,566 Electric 928 6,951,566
4
Oregon Public Utility
Commission: Rate Cases
and Proceedings
1,389,856 1,389,856 Electric 928 1,389,856
5
Oregon Public Utility
Commission: Deferred
Intervenor Funding Grants
3,028,580 778,515 928 1,118,762 2,688,333
6 Wyoming Public Service
Commission: Annual Fee 1,809,484 1,809,484 Electric 928 1,809,484
7
Wyoming Public Service
Commission: Rate Cases
and Proceedings
1,019,685 1,019,685 Electric 928 1,019,685
8
Washington Utilities and
Transportation Commission:
Annual Fee
1,609,062 1,609,062 Electric 928 1,609,062
9
Washington Utilities and
Transportation Commission:
Rate Cases and
Proceedings
461,457 461,457 Electric 928 461,457
10
Washington Utilities and
Transportation Commission:
Deferred Intervenor
Funding Grants
300,000 300,000
11 Idaho Public Utilities
Commission: Annual Fee 606,061 606,061 Electric 928 606,061
12
Idaho Public Utilities
Commission: Rate Cases
and Proceedings
25,463 25,463 Electric 928 25,463
13
Idaho Public Utilities
Commission: Deferred
Intervenor Funding Grants
40,000 40,000
14 California Public Utilities
Commission: Annual Fee 6,537 6,537 Electric 928 6,537
15
California Public Utilities
Commission: Rate Cases
and Proceedings
849,972 849,972 Electric 928 849,972
16
California Public Utilities
Commission: Deferred
Intervenor Funding Grants
404,712 146,829 551,541
17
California Environmental
Protection Agency: Industry
Compliance Fee
132,879 46,777 179,656 Electric 928 179,656
18 Multi-State: Rate Cases
and Proceedings 32,961 32,961 Electric 928 32,961
19 Multi-State: Other
Regulatory 254,670 254,670 Electric 928 254,670
20 Federal Energy Regulatory
Commission: Annual Fee 3,396,191 3,396,191 Electric 928 3,396,191
21
Federal Energy Regulatory
Commission: Annual Fee -
Hydroelectric Plants
4,046,608 4,046,608 Electric 928 4,046,608
22
Federal Energy Regulatory
Commission: Transmission
Rate Cases
251,125 251,125 Electric 928 251,125
Description (Furnish
name of regulatory
commission or body the
docket or case number
and a description of the
case)
Assessed by
Regulatory
Commission
Expenses of
Utility
Total Expenses
for Current Year
(b) + (c)
Deferred in
Account 182.3 at
Beginning of
Year
Department Account
No.Amount
Deferred
to
Account
182.3
Contra
Account Amount
Deferred
in
Account
182.3
End of
Year
23
Federal Energy Regulatory
Commission: Other
Regulatory
1,133,246 1,133,246 Electric 928 1,133,246
46 TOTAL 25,399,648 5,630,252 31,029,900 3,473,292 31,029,900 1,225,344 1,118,762 3,579,874
FERC FORM NO. 1 (ED. 12-96)
Page 350-351
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and 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 and 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:
Electric R, D and D Performed Internally:
Generation
hydroelectric
Recreation fish and wildlife
Other hydroelectric
Fossil-fuel steam
Internal combustion or gas turbine
Nuclear
Unconventional generation
Siting and heat rejection
Transmission
Overhead
Underground
Distribution
Regional Transmission and Market Operation
Environment (other than equipment)
Other (Classify and include items in excess of $50,000.)
Total Cost Incurred
Electric, R, D and D Performed Externally:
Research Support to the electrical Research Council or the Electric Power Research Institute
Research Support to Edison Electric Institute
Research Support to Nuclear Power Groups
Research Support to Others (Classify)
Total Cost Incurred
3. Include in column (c) all R, D and 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 and 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 and 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 and 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.
AMOUNTS CHARGED IN
CURRENT YEAR
Line
No.(a)(b)(c)(d)
(e)(f)
(g)
1 A. Electric R, D & D Performed Internally:
FERC FORM NO. 1 (ED. 12-87)
Page 352-353
A.
1.
a.
i.
ii.
b.
c.
d.
e.
f.
2.
a.
b.
3.
4.
5.
6.
7.
B.
1.
2.
3.
4.
5.
Classification Description Costs Incurred Internally
Current Year
Costs Incurred
Externally Current Year
Amounts
Charged In
Current Year:
Account
Amounts
Charged In
Current
Year:
Amount
Unamortized
Accumulation
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
DISTRIBUTION OF SALARIES AND WAGES
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.
Line
No.
Classification
(a)
Direct Payroll Distribution
(b)
Allocation of Payroll Charged for
Clearing Accounts
(c)
Total
(d)
1
2
3 101,070,250
4 19,918,542
5
6 47,998,132
7 29,892,118
8 8,580,394
9
10 38,419,021
11 245,878,457
12
13 42,331,535
14 13,251,987
15
16 83,215,928
17 1,739,480
18 140,538,930
19
20 143,401,785
21 33,170,529
22
23 131,214,060
24 29,892,118
25 8,580,394
26
27 40,158,501
28 386,417,387 386,417,387
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
Electric
Operation
Production
Transmission
Regional Market
Distribution
Customer Accounts
Customer Service and Informational
Sales
Administrative and General
TOTAL Operation (Enter Total of lines 3 thru 10)
Maintenance
Production
Transmission
Regional Market
Distribution
Administrative and General
TOTAL Maintenance (Total of lines 13 thru 17)
Total Operation and Maintenance
Production (Enter Total of lines 3 and 13)
Transmission (Enter Total of lines 4 and 14)
Regional Market (Enter Total of Lines 5 and 15)
Distribution (Enter Total of lines 6 and 16)
Customer Accounts (Transcribe from line 7)
Customer Service and Informational (Transcribe from line 8)
Sales (Transcribe from line 9)
Administrative and General (Enter Total of lines 10 and 17)
TOTAL Oper. and Maint. (Total of lines 20 thru 27)
Gas
Operation
Production - Manufactured Gas
Production-Nat. Gas (Including Expl. And Dev.)
Other Gas Supply
Storage, LNG Terminaling and Processing
Transmission
Distribution
Customer Accounts
Customer Service and Informational
Sales
Administrative and General
TOTAL Operation (Enter Total of lines 31 thru 40)
Maintenance
Production - Manufactured Gas
Production-Natural Gas (Including Exploration and Development)
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65 386,417,387 386,417,387
66
67
68 191,951,205 191,951,205
69
70
71 191,951,205 191,951,205
72
73 13,892,487 13,892,487
74
75
76 13,892,487 13,892,487
77
78
79 6,425,571 6,425,571
80 907,078 907,078
81 1,632,172 1,632,172
82 19,511,317 19,511,317
83
84
85
86
87
88
89
90
91
92
93
94
95 28,476,138 28,476,138
96 620,737,217 620,737,217
Other Gas Supply
Storage, LNG Terminaling and Processing
Transmission
Distribution
Administrative and General
TOTAL Maint. (Enter Total of lines 43 thru 49)
Total Operation and Maintenance
Production-Manufactured Gas (Enter Total of lines 31 and 43)
Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
Other Gas Supply (Enter Total of lines 33 and 45)
Storage, LNG Terminaling and Processing (Total of lines 31 thru
Transmission (Lines 35 and 47)
Distribution (Lines 36 and 48)
Customer Accounts (Line 37)
Customer Service and Informational (Line 38)
Sales (Line 39)
Administrative and General (Lines 40 and 49)
TOTAL Operation and Maint. (Total of lines 52 thru 61)
Other Utility Departments
Operation and Maintenance
TOTAL All Utility Dept. (Total of lines 28, 62, and 64)
Utility Plant
Construction (By Utility Departments)
Electric Plant
Gas Plant
Other (provide details in footnote):
TOTAL Construction (Total of lines 68 thru 70)
Plant Removal (By Utility Departments)
Electric Plant
Gas Plant
Other (provide details in footnote):
TOTAL Plant Removal (Total of lines 73 thru 75)
Other Accounts (Specify, provide details in footnote):
Other Accounts (Specify, provide details in footnote):
Fuel Stock
Miscellaneous Other Income Deductions
Miscellaneous Non-Operating and Non-Utility
Charges to Affiliates
TOTAL Other Accounts
TOTAL SALARIES AND WAGES
FERC FORM NO. 1 (ED. 12-88)
Page 354-355
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
COMMON UTILITY PLANT AND EXPENSES
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Electric Plant Instruction 13, Common Utility
Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation
factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the
common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation
of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to the order of the Commission or other authorization.
FERC FORM NO. 1 (ED. 12-87)
Page 356
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
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.
Line
No.
Description of Item(s)
(a)
Balance at End of Quarter 1
(b)
Balance at End of Quarter 2
(c)
Balance at End of Quarter 3
(d)
Balance at End of Year
(e)
1 Energy
2 Net Purchases (Account 555)137,995 158,284 166,032 166,051
2.1 Net Purchases (Account 555.1)
3 Net Sales (Account 447)
4 Transmission Rights
5 Ancillary Services
6 Other Items (list separately)
7 Energy Imbalance Market (Account 555)1,268,941 14,809,624 (15,607,470)(34,967,355)
46 TOTAL 1,406,936 14,967,908 (15,441,438)(34,801,304)
FERC FORM NO. 1 (NEW. 12-05)
Page 397
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
PURCHASES AND SALES OF ANCILLARY SERVICES
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), and (e) report the amount of ancillary services purchased and sold during the year.
2. On Line 2 columns (b), (c), (d), and (e) report the amount of reactive supply and voltage control services purchased and sold during the year.
3. On Line 3 columns (b), (c), (d), and (e) report the amount of regulation and frequency response services purchased and sold during the year.
4. On Line 4 columns (b), (c), (d), and (e) report the amount of energy imbalance services purchased and sold during the year.
5. On Lines 5 and 6, columns (b), (c), (d), and (e) report the amount of operating reserve spinning and supplement services purchased and sold during the period.
6. On Line 7 columns (b), (c), (d), and (e) 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.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant
Line
No.
Type of Ancillary Service
(a)
Number of Units
(b)
Unit of Measure
(c)
Dollar
(d)
Number of Units
(e)
Unit of Measure
(f)
Dollars
(g)
1 Scheduling, System Control and Dispatch 148,746,225 MWh 13,101,849
2 Reactive Supply and Voltage 114,912,448 MWh 22,075,829 137,378,521 MWh 26,337,794
3 Regulation and Frequency Response 112,771,457 MWh 27,501,221 132,917,761 MWh 34,368,103
4 Energy Imbalance 3,454,077 MWh 36,164,027
5 Operating Reserve - Spinning 106,643,050 MWh 17,916,032 121,240,039 MWh 20,363,947
6 Operating Reserve - Supplement 106,643,050 MWh 17,916,032 121,788,908 MWh 20,455,993
7 Other
8 Total (Lines 1 thru 7)440,970,005 MWh 85,409,114 665,525,531 MWh 150,791,713
FERC FORM NO. 1 (New 2-04)
Page 398
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
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.
Line
No.
Month
(a)
Monthly Peak MW -
Total
(b)
Day of Monthly
Peak
(c)
Hour of Monthly
Peak
(d)
Firm Network
Service for Self
(e)
Firm Network
Service for
Others
(f)
Long-Term
Firm Point-
to-point
Reservations
(g)
Other
Long-
Term
Firm
Service
(h)
Short-Term
Firm Point-
to-point
Reservation
(i)
Other
Service
(j)
NAME OF SYSTEM: 0
1 January 18,183 30 8 9,137 713 3,589 3,365 1,379
2 February 16,933 2 8 8,878 648 3,589 2,463 1,355
3 March 15,584 27 9 8,304 545 3,589 1,872 1,274
4 Total for Quarter 1 26,319 1,906 10,767 7,700 4,008
5 April 15,166 4 9 8,006 501 3,589 1,797 1,273
6 May 15,069 19 17 8,065 329 3,589 1,719 1,367
7 June 17,336 30 18 9,386 420 3,720 2,201 1,609
8 Total for Quarter 2 25,457 1,250 10,898 5,717 4,249
9 July 18,873 21 17 10,578 500 3,716 2,078 2,001
10 August 20,707 16 17 10,909 470 3,716 3,685 1,927
11 September 16,975 8 17 8,784 367 3,718 2,541 1,565
12 Total for Quarter 3 30,271 1,337 11,150 8,304 5,493
13 October 15,716 30 8 8,120 527 3,614 2,229 1,226
14 November 16,357 28 8 8,590 563 3,483 2,408 1,313
15 December 15,642 18 18 8,421 546 3,483 1,934 1,258
16 Total for Quarter 4 25,131 1,636 10,580 6,571 3,797
17 Total (a)107,178 (b)6,129 (c)43,395 (d)28,292 (e)
17,547
FERC FORM NO. 1 (NEW. 07-04)
Page 400
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: FirmNetworkServiceForSelf
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.
(b) Concept: FirmNetworkServiceForOther
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.
(c) Concept: LongTermFirmPointToPointReservations
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.
(d) Concept: ShortTermFirmPointToPointReservations
For the year being reported, the Net System Load information was compiled using reservations in OASIS at time of Transmission System Peak.
(e) Concept: OtherService
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.
FERC FORM NO. 1 (NEW. 07-04)
Page 400
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
Monthly ISO/RTO Transmission System Peak Load
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 Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
4. Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in
Columns (e) and (f).
5. Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line
No.
Month
(a)
Monthly Peak MW -
Total
(b)
Day of Monthly Peak
(c)
Hour of Monthly
Peak
(d)
Import into ISO/RTO
(e)
Exports from
ISO/RTO
(f)
Through
and Out
Service
(g)
Network
Service
Usage
(h)
Point-
to-
Point
Service
Usage
(i)
Total
Usage
(j)
NAME OF SYSTEM: 0
1 January
2 February
3 March
4 Total for Quarter 1 0 0 0 0 0 0
5 April
6 May
7 June
8 Total for Quarter 2 0 0 0 0 0 0
9 July
10 August
11 September
12 Total for Quarter 3 0 0 0 0 0 0
13 October
14 November
15 December
16 Total for Quarter 4 0 0 0 0 0 0
17 Total Year to Date/Year 0 0 0 0 0 0
FERC FORM NO. 1 (NEW. 07-04)
Page 400a
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
2024-04-11
Year/Period of Report
End of: 2023/ Q4
ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line
No.
Item
(a)
MegaWatt Hours
(b)
Line
No.
Item
(a)
MegaWatt Hours
(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use):22 Sales to Ultimate Consumers (Including Interdepartmental
Sales)56,696,328
3 Steam 27,215,264 23 Requirements Sales for Resale (See instruction 4, page
311.)307,999
4 Nuclear 24 Non-Requirements Sales for Resale (See instruction 4, page
311.)2,602,670
5 Hydro-Conventional 3,001,321 25 Energy Furnished Without Charge
6 Hydro-Pumped Storage 26 Energy Used by the Company (Electric Dept Only, Excluding
Station Use)(a)163,312
7 Other 15,537,064 27 Total Energy Losses 4,456,877
8 Less Energy for Pumping 922 27.1 Total Energy Stored
9 Net Generation (Enter Total of lines 3 through 8)45,752,727 28 TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL
LINE 20 UNDER SOURCES 64,227,186
10 Purchases (other than for Energy Storage)17,677,912
10.1 Purchases for Energy Storage
11 Power Exchanges:
12 Received 7,394,886
13 Delivered 6,319,678
14 Net Exchanges (Line 12 minus line 13)1,075,208
15 Transmission For Other (Wheeling)
16 Received 17,818,492
17 Delivered 17,730,917
18 Net Transmission for Other (Line 16 minus line 17)87,575
19 Transmission By Others Losses (366,236)
20 TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)64,227,186
FERC FORM NO. 1 (ED. 12-90)
Page 401a
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
2024-04-11
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: InternalUseEnergy
For metered locations only.
FERC FORM NO. 1 (ED. 12-90)
Page 401a
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
MONTHLY PEAKS AND OUTPUT
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).
Line
No.(a)(b)
(c)
(d)(e)(f)
NAME OF SYSTEM: 0
29 January 5,933,563 407,208 8,998 30 9
30 February 5,180,000 175,822 8,695 2 8
31 March 5,396,602 168,346 8,142 6 8
32 April 4,807,284 227,089 7,856 3 9
33 May 4,889,265 147,079 7,933 19 17
34 June 5,020,848 149,693 9,222 30 18
35 July 6,193,851 162,670 10,539 21 18
36 August 5,982,404 251,402 10,802 15 17
37 September 5,135,045 419,226 8,628 8 17
38 October 4,912,568 137,921 7,948 30 8
39 November 5,152,049 182,601 8,400 28 8
40 December 5,623,707 173,613 8,209 18 18
41 Total 64,227,186 2,602,670
FERC FORM NO. 1 (ED. 12-90)
Page 401b
Month Total Monthly Energy
Monthly Non-Requirement
Sales for Resale &
Associated Losses
Monthly Peak - Megawatts Monthly Peak - Day of
Month Monthly Peak - Hour
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
Steam Electric Generating Plant Statistics
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 Mcf.
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.
9. Items under Cost of Plant are based on USofA 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.
Line
No.
Item
(a)
Plant Name:
(a)
Blundell
Plant Name:
Chehalis
Plant Name:
(b)
Colstrip
Plant Name:
(c)
Craig
Plant Name:
Currant Creek
Plant Name:
Dave
Johnston
Plant
Name:
Gadsby
Peakers
Plant
Name:
Gadsby
Steam
Plant
Name:
(d)Hayden
Plant Name:
(e)
Hermiston
Plant Name:
(f)
Hunter -
Total Plant
Plant Name:
(g)
Hunter Unit
No. 1
Plant
Name:
(h)
Hunter Unit
No. 2
Plant Name:
Hunter Unit
No. 3
Plant Name:
Huntington
Plant Name:
(i)
Jim Bridger
Plant Name:
Lake Side
Plant Name:
Lake Side 2
Plant Name:
Naughton
Plant Name:
(j)
Wyodak
1 Steam - Geothermal Combined Cycle Steam Steam Combined Cycle Steam Gas
Turbine Steam Steam Combined
Cycle Steam Steam Steam Steam Steam Steam Combined
Cycle
Combined
Cycle Steam Steam
2 Indoor Outdoor Conventional Outdoor Boiler Outdoor Semi-Outdoor Outdoor Outdoor Outdoor
Boiler Outdoor Outdoor
Boiler
Outdoor
Boiler
Outdoor
Boiler
Outdoor
Boiler
Outdoor
Boiler
Outdoor
Boiler Outdoor Outdoor Outdoor
Boiler Conventional
3 1984 2003 1984 1979 2005 1959 2002 1951 1965 1996 1978 1978 1980 1983 1974 1974 2007 2014 1963 1978
4 2007 2003 1986 1980 2006 1972 2002 1955 1976 1996 1983 1978 1980 1983 1977 1979 2007 2014 1971 1978
5 38.10 593.30 155.61 172.13 566.90 816.77 181.05 251.64 81.25 279.56 1,247.78 457.73 294.46 495.59 1,015.50 1,550.65 591.30 655.20 707.20 289.66
6 35 507 160 161 552 695 113 202 78 234 1,080 422 269 473 910 1,425 520 624 643 270
7 8,605 7,870 8,738 8,162 8,446 8,760 343 3,307 8,717 7,238 8,626 7,271 7,062 6,451 8,760 8,760 8,635 7,750 8,663 7,738
8 33 518 148 161 550 755 120 238 77 237 1,158 418 269 471 909 1,413 558 645 604 268
9 34 506 148 161 556 755 122 238 77 240 1,158 418 269 471 909 1,413 562 656 604 268
10 32 477 148 161 524 745 119 238 77 231 1,158 418 269 471 909 1,413 546 631 604 266
11 18 15 (k)0 (l)0 17 164 (m)0 29 (n)0 (o)0 183 (p)0 (q)0 (r)0 138 257 31 (s)0 98 52
12 248,201,000 2,239,007,000 1,048,989,000 797,835,000 2,879,945,000 3,537,397,000 1,788,000 235,157,000 509,913,000 1,357,915,000 3,411,330,000 1,475,590,000 803,001,000 1,132,739,000 3,400,881,000 6,075,458,000 3,106,023,000 3,350,476,000 2,766,703,000 1,282,117,000
13 41,195,596 3,730,527 1,788,644 137,086 3,403,277 10,448,598 1,252,090 683,069 796,929 29,626,009 9,679,900 9,679,900 10,266,209 2,377,564 1,193,761 14,532,275 16,794,626 1,440,822 210,526
14 8,575,917 24,669,889 70,301,953 38,846,211 44,449,150 169,587,277 4,273,000 15,681,197 18,024,330 12,921,287 215,702,533 65,864,701 55,213,535 94,624,297 130,020,819 191,625,740 35,808,970 53,403,807 133,832,020 54,522,939
15 107,144,082 335,533,558 180,821,823 186,771,082 313,969,454 924,536,453 84,598,057 74,004,087 98,492,527 173,277,443 1,136,864,459 410,714,588 262,341,330 463,808,541 801,159,213 1,234,028,884 335,378,177 589,471,126 660,393,224 429,992,538
16 5,715,415 1,355,802 6,949,363 3,180,430 77,461 28,295,791 1,372,866 2,330,719 618,012 13,704,723 4,568,241 4,568,241 4,568,241 8,457,784 72,224,339 61,008,907 677,254
17 162,631,010 365,289,776 259,861,783 228,934,809 361,899,342 1,132,868,119 88,871,057 92,310,240 119,530,645 187,613,671 1,395,897,724 490,827,430 331,803,006 573,267,288 942,015,380 1,499,072,724 385,719,422 659,669,559 856,674,973 485,403,257
18 4,268.530 615.692 1,669.956 1,330.011 638.383 1,387.010 490.865 366.835 1,471.146 671.103 1,118.705 1,072.308 1,126.819 1,156.737 927.637 966.738 652.324 1,006.822 1,211.362 1,675.769
19 6,020 253,045 36,143 318,900 133,300 10,224 122,786 99,452 11,117 4,014 2,582 4,521 8,174 14,933,440 88,510 102,310 434,585 25,875
20 123,866,584 (t)23,217,547 27,914,521 99,903,977 51,079,810 583,133 17,853,995 12,683,463 34,955,391 100,261,721 42,285,654 23,962,941 34,013,126 85,562,122 (u)226,851,425 111,416,135 115,780,157 103,923,343 22,443,731
21
22 (80,179)896,337 2,049,382 3,819,861 241,993 1,307,868 19,050,814 6,784,454 5,305,198 6,961,162 13,101,694 19,414,188 8,777,734 5,389,935
23 10,794,276
24
25 2,431,989 (96,376)549,499 2,339,214 927,062 321,912 6,921,024 (40,757)(84,684)85,654 (41,727)7,553 2,951,536 4,846,192 4,050
26 (882,937)813,248 4,398,230 994,951 651,686 19,297,082 4,801,203 248,871 4,605,373 4,939,484 (4,182,632)3,848,521 13,061,988 (22,175,858)447,900 519,534 8,178,876 2,977,007
27 6,247 96,199 800 289 186 325 2,169 233,874 232 268 14,350 19,690
28
29 187,084 501,482 164,503 248,682 89,780 57,763 101,139 1,399,525 518,352 1,951,034
30 770,390 36,613 497,327 369,107 564,282 2,466,025 112,407 169,735 365,036 4,910,912 1,141,254 2,475,393 1,294,265 2,934,154 10,463,442 1,023,486 2,981,915 1,593,988 103,216
31 214,965 3,322,658 5,260,739 15,224,937 1,169,796 1,016,750 16,618,522 2,762,849 8,790,583 5,065,090 14,157,825 21,321,738 6,495,185 3,067,185
32 421,684 4,416,787 377,900 1,597,219 1,624,274 9,179,569 332,209 1,280,574 596,802 4,059,667 1,111,933 2,251,943 695,791 6,488,009 10,292,174 602,637 4,604,321 1,745,858 1,623,862
33 104,303 687,593 786,294 77,010 2,097,903 114,877 162,364 217,031 2,951,743 1,051,711 679,143 1,220,889 880,160 2,980,400 32,423 33,239 2,388,538 218,163
Kind of Plant (Internal Comb,
Gas Turb, Nuclear)
Type of Constr
(Conventional, Outdoor,
Boiler, etc)
Year Originally Constructed
Year Last Unit was Installed
Total Installed Cap (Max Gen
Name Plate Ratings-MW)
Net Peak Demand on Plant -
MW (60 minutes)
Plant Hours Connected to
Load
Net Continuous Plant
Capability (Megawatts)
When Not Limited by
Condenser Water
When Limited by Condenser
Water
Average Number of
Employees
Net Generation, Exclusive of
Plant Use - kWh
Cost of Plant: Land and Land
Rights
Structures and
Improvements
Equipment Costs
Asset Retirement Costs
Total cost (total 13 thru 20)
Cost per KW of Installed
Capacity (line 17/5) Including
Production Expenses: Oper,
Supv, & Engr
Fuel
Coolants and Water (Nuclear
Plants Only)
Steam Expenses
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses
Misc Steam (or Nuclear)
Power Expenses
Rents
Allowances
Maintenance Supervision
and Engineering
Maintenance of Structures
Maintenance of Boiler (or
reactor) Plant
Maintenance of Electric Plant
Maintenance of Misc Steam
(or Nuclear) Plant
34 11,354,769 131,818,266 33,524,443 40,342,094 105,293,743 103,271,610 2,069,688 25,802,446 17,021,688 41,876,415 152,678,594 60,086,738 39,428,754 53,163,102 137,595,820 284,840,728 116,562,859 128,867,936 135,507,541 35,868,664
35 0.0457 0.0589 0.0320 0.0506 0.0366 0.0292 1.1575 0.1097 0.0334 0.0308 0.0448 0.0407 0.0491 0.0469 0.0405 0.0469 0.0375 0.0385 0.0490 0.0280
35 Chehalis Colstrip Colstrip Craig Craig Currant
Creek
Dave
Johnston
Dave
Johnston
Gadsby
Peakers
Gadsby
Steam Hayden Hayden Hermiston Hunter -
Total Plant
Hunter -
Total
Plant
Hunter
Unit No. 1
Hunter
Unit No.
1
Hunter
Unit No. 2
Hunter
Unit No.
2
Hunter
Unit No. 3
Hunter
Unit No.
3
Huntington Huntington Jim
Bridger
Jim
Bridger Lake Side Lake Side
2 Naughton Naughton Wyodak
36 Gas Coal (v)
Oil Coal (w)
Oil Gas Coal (x)
Oil Gas Gas Coal (y)
Oil Gas Coal (z)
Oil Coal (aa)
Oil Coal (ab)
Oil Coal (ac)
Oil Coal (ad)
Oil Coal (ae)
Oil Gas Gas Coal Gas Coal
37 Mcf T Boe T Boe Mcf T Boe Mcf Mcf T Boe Mcf T Boe T Boe T Boe T Boe T Boe T Boe Mcf Mcf T Mcf T
38 15,322,179 653,341 1,757 455,031 20,224,000 2,510,818 14,581 90,059 3,604,842 236,371 658 9,655,677 1,736,980 16,831 750,191 2,619 413,783 2,210 573,006 12,002 1,579,566 4,175 3,618,921 13,572 21,778,111 22,848,760 1,032,090 10,792,072 1,012,32
39 1,100 8,596 140,000 9,716 133,825 1,054 8,430 138,000 1,040 1,040 11,143 136,827 1,058 11,237 138,000 11,282 138,000 11,279 138,000 11,149 138,000 11,342 138,000 9,164 138,000 1,050 1,050 10,065 1,051 7,92
40 8.084 32.710 145.281 52.550 4.940 19.540 150.884 6.475 4.953 47.740 141.755 3.620 60.250 141.943 52.210 140.408 51.440 138.972 5.116 5.067 49.470 4.871 21.54
41 8.084 35.146 145.281 60.862 4.940 19.468 150.884 6.475 4.953 53.214 141.755 3.620 56.346 141.943 55.879 57.173 56.361 53.797 140.408 62.120 138.972 5.116 5.067 49.763 4.871 21.59
42 7.352 2.044 24.707 3.132 4.686 1.155 26.032 6.222 4.763 2.388 24.664 3.420 2.507 24.490 2.476 24.075 2.535 23.877 2.528 24.693 2.372 24.225 3.389 23.977 4.874 4.828 2.472 4.633 1.36
43 0.055 0.022 0.035 0.035 0.014 0.001 0.326 0.076 0.025 0.026 0.029 0.001 0.028 0.029 0.029 0.002 0.025 0.037 0.036 0.035 0.019 0.019 0.01
44 7,524.513 10,707.231 9.848 11,082.536 7,402.263 11,967.339 23.890 52,417.226 15,941.511 10,330.783 7.414 7,527.845 11,443.795 28.596 11,471.498 10.289 11,623.746 15.950 11,280.139 61.410 10,535.555 7.116 10,916.864 12.947 7,359.463 7,157.966 7,509.125 4,100.337 12,513.25
FERC FORM NO. 1 (REV. 12-03)
Page 402-403
Total Production Expenses
Expenses per Net kWh
Plant Name
Fuel Kind
Fuel Unit
Quantity
(Units) of
Fuel Burned
Avg Heat
Cont - Fuel
Burned
(btu/indicate
if nuclear)
Avg Cost of
Fuel/unit, as
Delvd f.o.b.
during year
Average
Cost of Fuel
per Unit
Burned
Average
Cost of Fuel
Burned per
Million BTU
Average
Cost of Fuel
Burned per
kWh Net
Gen
Average
BTU per
kWh Net
Generation
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: PlantName
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.
(b) Concept: PlantName
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.
(c) Concept: PlantName
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.
(d) Concept: PlantName
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.
(e) Concept: PlantName
The Hermiston Plant is operated by Hermiston Generating Company, L.P. and is jointly owned. PacifiCorp owns a 50.0% share of the Hermiston Plant. Data reported represents PacifiCorp's share.
(f) Concept: PlantName
Refer to Hunter Unit Nos. 1, 2 and 3 for each unit's plant statistics.
(g) Concept: PlantName
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 2023 were $1.2 million and were primarily credited to Account
506, Miscellaneous steam power expenses.
(h) Concept: PlantName
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
2023 were $11.1 million and were primarily credited to Account 506, Miscellaneous steam power expenses.
(i) Concept: PlantName
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 2023 were $29.3 million and were primarily credited to Account 506,
Miscellaneous steam power expenses.
(j) Concept: PlantName
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 2023 were $4.3 million and were primarily credited to Account 506,
Miscellaneous steam power expenses.
(k) Concept: PlantAverageNumberOfEmployees
PacifiCorp does not have employees at this plant.
(l) Concept: PlantAverageNumberOfEmployees
PacifiCorp does not have employees at this plant.
(m) Concept: PlantAverageNumberOfEmployees
Refer to the Gadsby Steam Plant for the average number of employees.
(n) Concept: PlantAverageNumberOfEmployees
PacifiCorp does not have employees at this plant.
(o) Concept: PlantAverageNumberOfEmployees
PacifiCorp does not have employees at this plant.
(p) Concept: PlantAverageNumberOfEmployees
Refer to Hunter - Total Plant for the average number of employees.
(q) Concept: PlantAverageNumberOfEmployees
Refer to Hunter - Total Plant for the average number of employees.
(r) Concept: PlantAverageNumberOfEmployees
Refer to Hunter - Total Plant for the average number of employees.
(s) Concept: PlantAverageNumberOfEmployees
Refer to Lake Side Plant for the average number of employees.
(t) Concept: FuelSteamPowerGeneration
Amount includes intercompany profits.
(u) Concept: FuelSteamPowerGeneration
Amount includes intercompany profits.
(v) Concept: FuelKind
Fuel oil is used for start-up purposes.
(w) Concept: FuelKind
Fuel oil is used for start-up purposes.
(x) Concept: FuelKind
Fuel oil is used for start-up purposes.
(y) Concept: FuelKind
Fuel oil is used for start-up purposes.
(z) Concept: FuelKind
Fuel oil is used for start-up purposes.
(aa) Concept: FuelKind
Fuel oil is used for start-up purposes.
(ab) Concept: FuelKind
Fuel oil is used for start-up purposes.
(ac) Concept: FuelKind
Fuel oil is used for start-up purposes.
(ad) Concept: FuelKind
Fuel oil is used for start-up purposes.
(ae) Concept: FuelKind
Fuel oil is used for start-up purposes.
(af) Concept: FuelKind
Fuel oil is used for start-up purposes.
FERC FORM NO. 1 (REV. 12-03)
Page 402-403
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
Hydroelectric Generating Plant Statistics
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.
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.
Line
No.
Item
(a)
FERC Licensed
Project No.
14803
Plant Name:
(a)(b)
Copco No. 1
FERC Licensed
Project No.
14803
Plant Name:
(c)
Copco No. 2
FERC Licensed
Project No.
14803
Plant Name:
(d)
Iron Gate
FERC Licensed
Project No.
14803
Plant Name:
(e)
JC Boyle
FERC Licensed
Project No.
1927
Plant Name:
Clearwater No. 1
FERC
Licensed
Project
No.
1927
Plant
Name:
Clearwater
No. 2
FERC
Licensed
Project
No.
1927
Plant
Name:
Fish
Creek
FERC
Licensed
Project
No.
1927
Plant
Name:
Lemolo
No. 1
FERC
Licensed
Project No.
1927
Plant
Name:
Lemolo No.
2
FERC
Licensed
Project
No.
1927
Plant
Name:
Slide
Creek
FERC
Licensed
Project No.
1927
Plant
Name:
Soda
Springs
FERC
Licensed
Project No.
1927
Plant Name:
Toketee
FERC
Licensed
Project No.
20
Plant Name:
Grace
FERC
Licensed
Project No.
20
Plant Name:
Oneida
FERC
Licensed
Project No.
20
Plant Name:
Soda
FERC
Licensed
Project No.
2071
Plant Name:
Yale
FERC
Licensed
Project No.
2111
Plant Name:
Swift No. 1
FERC
Licensed
Project No.
2420
Plant Name:
Cutler
FERC
Licensed
Project No.
2630
Plant Name:
Prospect
No. 2
FERC
Licensed
Project No.
935
Plant Name:
Merwin
1 (f)Storage Run-of-River (g)Storage (h)Storage (i)Run-of-River
(j)
Run-of-
River
(k)
Run-of-
River
(l)Storage
(m)
Run-of-
River
Run-of-
River
Storage
(Re-Reg)
(n)Storage Storage Storage Storage Storage Storage Storage (o)Run-of-River Storage (Re-
Reg)
2 Conventional Conventional Outdoor Outdoor Outdoor Outdoor Outdoor Outdoor Outdoor Outdoor Outdoor Conventional Conventional Conventional Conventional Conventional Conventional Conventional Conventional Conventional
3 1918 1925 1962 1958 1953 1953 1952 1955 1956 1951 1952 1949 1908 1915 1924 1953 1958 1927 1928 1931
4 1922 1925 1962 1958 1953 1953 1952 1955 1956 1951 1952 1950 1923 1920 1924 1953 1958 1927 1928 1958
5 20 27 18 97.98 15 26 11 31.99 38.50 18 11 42.50 33 30 14.45 134 240 30 32 136
6 26 32 20 77 8 14 11 23 29 16 12 36 23 27 11 163 250 31 36 141
7 5,535 1,947 8,731 5,205 8,254 8,586 2,618 7,985 8,748 8,261 8,304 8,565 8,460 8,550 6,356 5,937 4,972 7,830 8,626 8,754
8
9 28 34 19 83 18 31 10 32 39 18 12 45 33 28 14 164 264 29 36 151
10 28 34 19 83 18 31 10 32 39 18 12 45 33 28 14 164 264 29 36 151
11 1 1 1 1 1 1 2 1 3 2 3 3 1
12 71,412,000 42,481,000 81,505,000 192,002,000 25,303,000 26,295,000 18,294,000 88,532,000 118,483,000 48,057,000 39,506,000 166,485,000 72,869,000 42,411,000 16,486,000 516,895,000 580,317,000 96,245,000 163,295,000 471,579,000
13
14 74,674 309,259 511,083 8,363,013 20,287,495 3,507,754 105,168 1,955,029
15 1,699,743 2,503,320 1,764,935 3,116,937 6,700,263 2,412,805 4,335,356 5,703,795 4,654,241 3,052,733 1,404,232 19,211,930 76,211,601 4,920,889 4,887,009 115,348,564
16 5,232,135 15,039,994 12,465,242 15,815,119 33,474,602 15,208,417 91,714,759 14,361,701 16,612,610 9,173,129 11,267,298 35,480,044 50,920,974 12,380,399 37,417,092 41,669,983
17 1,576,999 2,212,552 3,039,487 6,918,822 11,964,413 9,105,890 2,927,983 6,670,549 6,605,218 15,930,300 6,516,351 18,987,590 26,100,836 15,260,625 7,439,800 20,687,599
18 50,817 250,151 533,015 531,800 1,820,580 582,653 2,089,011 1,127,893 948,522 984,865 2,712,984 1,215,512 1,086,176 686,471 5,923,253
19
20 8,559,694 20,006,017 17,802,679 26,382,678 53,959,858 27,309,765 101,067,109 27,863,938 28,895,265 29,450,286 19,698,964 84,755,561 174,736,418 37,155,843 50,535,540 185,584,428
21 570.646 769.462 1,618.425 824.716 1,401.555 1,517.209 9,187.919 655.622 875.614 981.676 1,363.250 632.504 728.068 1,238.528 1,579.236 1,364.591
22
23 66,015 89,120 1,727,374 342,622 144,961 88,942 37,645 224,365 131,702 158,645 92,438 196,978 213,117 192,133 100,453 1,979,162 3,548,580 234,234 511,276 1,999,315
24 568 985 417 1,212 1,459 5,302 417 1,610 78,314 140,263 9,033 79,482
25 1,111 1,500 1,000 5,444 34,563 59,910 25,346 73,712 88,713 41,476 160,889 97,932 49,632 45,120 21,056 1,066,758 2,108,237 127,379 1,778 1,082,680
26
27 1,842,373 2,393,787 1,624,986 636,603 322,995 460,570 143,640 720,446 638,818 359,985 1,961,587 773,561 1,507,703 642,912 449,084 537,099 436,278 1,337,832 696,828 591,043
28 128,637 173,660 115,773 2,373 73,930 120,405 50,941 148,144 178,292 92,107 50,941 196,820 22,165 20,150 9,500 131,971 236,366 108,159 66,866 133,941
29 19,302
30 2,899 42,131 49,817 19,639 65,238 70,192 33,156 19,639 89,641 26,556 71 2,129 32,082 41,460 1,245 61,479 100,257
31 824 2,948 8,695 11,368 28,878 57,404 24,284 31,462 39,000 18,316 156,675 134,710 10,123 35,831 58,551 8,303 124,126 38,969
32 5,625 1,557 1,038 5,628 9,177 9,206 10,394 6,790 27,463 46,938 49,746 43,921 58,673 53,611 136,164 166,808 9,418 55,008 128,778
33 26,759 36,124 24,083 98,108 47,961 85,378 35,348 102,284 123,099 57,759 41,495 135,892 135,932 113,717 53,068 689,874 1,211,828 480,097 338,760 684,481
34 2,070,520 2,695,748 3,495,078 1,090,997 681,432 886,552 351,060 1,403,199 1,263,349 807,355 2,413,344 1,560,496 2,155,701 1,207,486 699,024 4,687,255 7,948,371 2,306,667 1,884,456 4,838,946
35 0.029 0.063 0.043 0.006 0.027 0.034 0.019 0.016 0.011 0.017 0.061 0.009 0.030 0.028 0.042 0.009 0.014 0.024 0.012 0.010
FERC FORM NO. 1 (REV. 12-03)
Page 406-407
Kind of Plant (Run-of-River or
Storage)
Plant Construction type
(Conventional or Outdoor)
Year Originally Constructed
Year Last Unit was Installed
Total installed cap (Gen name plate
Rating in MW)
Net Peak Demand on Plant-
Megawatts (60 minutes)
Plant Hours Connect to Load
Net Plant Capability (in
megawatts)
(a) Under Most Favorable Oper
Conditions
(b) Under the Most Adverse Oper
Conditions
Average Number of Employees
Net Generation, Exclusive of Plant
Use - kWh
Cost of Plant
Land and Land Rights
Structures and Improvements
Reservoirs, Dams, and Waterways
Equipment Costs
Roads, Railroads, and Bridges
Asset Retirement Costs
Total cost (total 13 thru 20)
Cost per KW of Installed Capacity
(line 20 / 5)
Production Expenses
Operation Supervision and
Engineering
Water for Power
Hydraulic Expenses
Electric Expenses
Misc Hydraulic Power Generation
Expenses
Rents
Maintenance Supervision and
Engineering
Maintenance of Structures
Maintenance of Reservoirs, Dams,
and Waterways
Maintenance of Electric Plant
Maintenance of Misc Hydraulic
Plant
Total Production Expenses (total 23
thru 33)
Expenses per net kWh
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: PlantName
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.
(b) Concept: PlantName
Refer to Note 14 of Notes to Financial Statements in this Form No. 1 and Docket No. AC23-26-000 filed with the FERC for further discussion on the Lower Klamath Hydroelectric Project.
(c) Concept: PlantName
Refer to Note 14 of Notes to Financial Statements in this Form No. 1 and Docket No. AC23-26-000 filed with the FERC for further discussion on the Lower Klamath Hydroelectric Project.
(d) Concept: PlantName
Refer to Note 14 of Notes to Financial Statements in this Form No. 1 and Docket No. AC23-26-000 filed with the FERC for further discussion on the Lower Klamath Hydroelectric Project.
(e) Concept: PlantName
Refer to Note 14 of Notes to Financial Statements in this Form No. 1 and Docket No. AC23-26-000 filed with the FERC for further discussion on the Lower Klamath Hydroelectric Project.
(f) Concept: PlantKind
Copco No. 1 - Pondage for peaking - storage, Upper Klamath Lake
(g) Concept: PlantKind
Iron Gate - Storage for regulation
(h) Concept: PlantKind
JC Boyle - Pondage for peaking - storage, Upper Klamath Lake
(i) Concept: PlantKind
Clearwater No. 1 - Forebay for peaking
(j) Concept: PlantKind
Clearwater No. 2 - Forebay for peaking
(k) Concept: PlantKind
Fish Creek - Forebay for peaking
(l) Concept: PlantKind
Lemolo No. 1 - Storage, Lemolo Lake
(m) Concept: PlantKind
Lemolo No. 2 - Storage, Lemolo Lake
(n) Concept: PlantKind
Toketee - Pondage for peaking - storage, Lemolo Lake
(o) Concept: PlantKind
Prospect No. 2 - Forebay for peaking
FERC FORM NO. 1 (REV. 12-03)
Page 406-407
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
Pumped Storage Generating Plant Statistics
1. Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings).
2. If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. 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 8 the approximate average number of employees assignable to each plant.
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. Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes.
7. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the
company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and
production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts
are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
Line No.Item
(a)
FERC Licensed Project No.
0
Plant Name:
0
1
2
3
4
5 0
6 0
7 0
8
9 0
10
11 0
12
13
14 0
15 0
16 0
17 0
18 0
19 0
20 0
21
22
23
24 0
25 0
26 0
27 0
28 0
29 0
30 0
31 0
32 0
33 0
34 0
35
36
37
38
39 0
FERC FORM NO. 1 (REV. 12-03)
Page 408-409
Type of Plant Construction (Conventional or Outdoor)
Year Originally Constructed
Year Last Unit was Installed
Total installed cap (Gen name plate Rating in MW)
Net Peak Demaind on Plant-Megawatts (60 minutes)
Plant Hours Connect to Load While Generating
Net Plant Capability (in megawatts)
Average Number of Employees
Generation, Exclusive of Plant Use - kWh
Energy Used for Pumping
Net Output for Load (line 9 - line 10) - Kwh
Cost of Plant
Land and Land Rights
Structures and Improvements
Reservoirs, Dams, and Waterways
Water Wheels, Turbines, and Generators
Accessory Electric Equipment
Miscellaneous Powerplant Equipment
Roads, Railroads, and Bridges
Asset Retirement Costs
Total cost (total 13 thru 20)
Cost per KW of installed cap (line 21 / 4)
Production Expenses
Operation Supervision and Engineering
Water for Power
Pumped Storage Expenses
Electric Expenses
Misc Pumped Storage Power generation Expenses
Rents
Maintenance Supervision and Engineering
Maintenance of Structures
Maintenance of Reservoirs, Dams, and Waterways
Maintenance of Electric Plant
Maintenance of Misc Pumped Storage Plant
Production Exp Before Pumping Exp (24 thru 34)
Pumping Expenses
Total Production Exp (total 35 and 36)
Expenses per kWh (line 37 / 9)
Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
GENERATING PLANT STATISTICS (Small Plants)
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.
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 402.
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.
Production Expenses
Line
No.(a)(b)
(c)(d)(e)
(f)
(g)
(h)(i)(j)(k)
(l)
(m)
1 Ashton (Licensed
Project No. 2381)1917 6.85 7.0 30,187,000 34,910,236 5,096,385 523,829 169,085 Water (i)
Hydro
2 Bend 1913 1.11 1.0 83,000 5,208,260 4,692,126 114,153 63,317 Water Hydro
3 Big Fork (Licensed
Project No. 2652)1910 4.15 5.0 25,104,000 13,942,832 3,359,719 647,265 11,227 Water Hydro
4 Eagle Point 1957 2.81 3.0 14,660,000 4,006,491 1,425,798 353,622 77,316 Water Hydro
5
(a)
East Side (Licensed
Project No. 2082)1924 3.20 0.0 1,738,589 543,309 33,563 3,827 Water Hydro
6 Fall Creek (Licensed
Project No. 2082)1903 2.20 2.0 6,668,000 2,878,265 1,308,302 281,758 37,098 Water Hydro
7 Granite 1896 2.00 1.2 2,935,428 5,431,384 2,715,692 273,003 12,883 Water Hydro
8 Gunlock 1917 0.75 0.4 2,138,730 690,253 920,337 60,769 58,219 Water Hydro
9 Last Chance 1983 1.73 1.3 3,415,390 3,225,657 1,864,542 173,662 42,994 Water Hydro
10 Paris (Licensed
Project No. 703)1910 0.72 0.4 1,171,774 766,477 1,064,551 77,303 33,534 Water Hydro
11 Pioneer (Licensed
Project No. 2722)1897 5.00 4.1 18,722,247 12,838,666 2,567,733 592,955 147,791 Water Hydro
12
Prospect No. 1
(Licensed Project No.
2630)
1912 3.76 0.0 5,561,598 1,479,148 130,676 65,612 Water Hydro
13
Prospect No. 3
(Licensed Project No.
2337)
1932 7.20 1.0 (174,000)11,553,486 1,604,651 312,008 116,165 Water Hydro
14
Prospect No. 4
(Licensed Project No.
2630)
1944 1.00 0.0 (60,000)2,551,528 2,551,528 36,552 16,912 Water Hydro
15 Sand Cove 1926 0.80 0.4 1,859,246 1,176,961 1,471,201 65,579 49,287 Water Hydro
16 Stairs (Licensed
Project No. 597)1895 1.00 1.3 4,187,840 3,069,520 3,069,520 314,176 6,412 Water Hydro
17 Veyo 1920 0.50 0.2 596,484 940,897 1,881,794 74,697 266,993 Water Hydro
18 Viva Naughton 1986 0.74 0.1 450,697 1,232,115 1,665,020 87,086 38,245 Water Hydro
19
Wallowa Falls
(Licensed Project No.
308)
1921 1.10 2.0 1,432,000 5,839,650 5,308,773 303,050 21,565 Water Hydro
20 Weber (Licensed
Project No. 1744)1911 3.85 3.0 9,498,278 4,051,414 1,052,315 435,698 27,433 Water Hydro
21
(b)
West Side (Licensed
Project No. 2082)1908 0.60 0.0 (7,000)577,606 962,677 (35,170)601 Water Hydro
22
(c)
Keno Regulating Dam
(Licensed Project No.
2082)
7,998,759 13,340 3,897 Hydro
23
(d)
Upper Klamath Lake
(Licensed Project No.
2082)
3,836,001 118,223 101,729 Hydro
24
(e)
North Umpqua
(Licensed Project No.
1927)
20,358,278 Hydro
25 (f)(g)
Lifton Pumping Plant 1917 21,980,448 (7,850,160)290,256 41,076 Water Hydro
26 Cedar Springs II 2020 198.88 244.0 580,916,000 255,938,718 1,286,900 1,934,875 2,219,341 Wind (j)
Wind
27 Dunlap Ranch 1 2010 136.90 111.0 432,029,000 218,641,544 1,597,089 243,677 1,484,575 Wind Wind
Name of Plant Year Orig.
Const.
Installed
Capacity
Name Plate
Rating (MW)
Net Peak
Demand MW
(60 min)
Net Generation
Excluding Plant
Use
Cost of Plant
Plant Cost
(Incl Asset
Retire.
Costs) Per
MW
Operation
Exc'l.
Fuel
Fuel
Production
Expenses
Maintenance
Production
Expenses
Kind
of
Fuel
Fuel
Costs
(in
cents
(per
Million
Btu)
Generation
Type
28 Ekola Flats 2020 250.90 189.0 753,554,000 319,255,325 1,272,441 1,402,044 1,887,232 Wind Wind
29 Foote Creek I 1999 48.00 42.0 215,530,000 82,422,588 1,717,137 828,702 250,269 Wind Wind
30 Foote Creek III 2023 25.20 25.0 14,560,139 41,808,323 1,659,060 44,245 13,715 Wind Wind
31 Foote Creek IV 2023 21.00 18.0 11,625,078 33,992,214 1,618,677 30,032 9,310 Wind Wind
32 Glenrock 2008 119.30 105.0 229,375,000 193,150,606 1,619,033 1,981,212 2,008,781 Wind Wind
33 Glenrock III 2009 46.00 44.0 84,690,000 81,577,963 1,773,434 175,268 574,594 Wind Wind
34 Goodnoe Hills 2008 103.40 94.0 223,909,000 155,700,092 1,505,804 1,569,034 108,817 Wind Wind
35 High Plains 2009 122.10 102.0 342,139,000 190,502,873 1,560,220 1,459,637 1,435,686 Wind Wind
36 Leaning Juniper 1 2006 110.38 102.0 254,658,000 177,876,957 1,611,496 1,948,711 133,102 Wind Wind
37 Marengo 2007 156.00 154.0 369,925,000 213,550,991 1,368,917 1,085,815 1,573,392 Wind Wind
38 Marengo II 2008 78.00 77.0 190,643,000 111,016,021 1,423,282 587,375 786,697 Wind Wind
39 McFadden Ridge I 2009 35.15 33.0 104,346,000 52,781,371 1,501,604 418,266 426,748 Wind Wind
40 Pryor Mountain 2020 239.80 186.0 723,768,000 399,514,684 1,666,033 1,112,265 2,879,362 Wind Wind
41 Rolling Hills 2009 115.80 106.0 187,786,000 197,323,037 1,703,999 139,304 61,506 Wind Wind
42 Seven Mile Hill 2008 122.10 108.0 381,599,000 188,743,730 1,545,813 479,121 248,196 Wind Wind
43 Seven Mile Hill II 2008 24.05 23.0 81,561,000 38,548,110 1,602,832 94,162 53,299 Wind Wind
44 TB Flats 2020 503.20 474.0 1,316,768,000 598,264,668 1,188,920 2,942,484 3,898,631 Wind Wind
45 (h)
Black Cap 2012 2.00 1.9 3,812,089 578,966 289,483 421,397 Solar Solar
FERC FORM NO. 1 (REV. 12-03)
Page 410-411
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: PlantName
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.
(b) Concept: PlantName
The West Side plant generation supplies station use and was significantly curtailed pursuant to Section 6.2 of the Klamath Hydroelectric Settlement Agreement in FERC Docket No. P-2082-000.
(c) Concept: PlantName
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.
(d) Concept: PlantName
Storage reservoir for six plants on the Klamath River (Copco No. 1, Copco No. 2, East Side, West Side, JC Boyle and Iron Gate). Also refer to Note 14 of Notes to Financial Statements in this Form No. 1 and Docket No.
AC23-26-000 filed with the FERC for further discussion on the Lower Klamath Hydroelectric Project.
(e) Concept: PlantName
Represents facilities that support the North Umpqua River system projects. All common roads, employee houses, control equipment, etc. are included in this account.
(f) Concept: PlantName
Installed Capacity Name Plate Rating
(In MW)
Net Peak Demand
MW (60 min.)Net Generation Excluding Plant Use
(c)(d)(e)
(2.80)0.0 (922,000)
(g) Concept: PlantName
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.
(h) Concept: PlantName
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.
(i) Concept: GenerationType
This footnote applies to all hydroelectric generating facilities with current generation. Common river system costs for the operation of these facilities are allocated to each plant based upon the unit’s name plate
rating. 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.
(j) Concept: GenerationType
This footnote applies to all wind-powered generating facilities with current generation. Common costs for the operation of these facilities are allocated to each plant based upon the unit’s name plate rating. 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.
FERC FORM NO. 1 (REV. 12-03)
Page 410-411
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
ENERGY STORAGE OPERATIONS (Large Plants)
1. Large Plants are plants of 10,000 Kw or more.
2. In columns (a) (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location.
3. In column (d), report Megawatt hours (MWH) purchased, generated, or received in exchange transactions for storage.
4. In columns (e), (f) and (g) report MWHs delivered to the grid to support production, transmission and distribution. The amount reported in column (d) should include MWHs delivered/provided to a generator’s own load
5. In columns (h), (i), and (j) report MWHs lost during conversion, storage and discharge of energy.
6. In column (k) report the MWHs sold.
7. In column (l), report revenues from energy storage operations. In a footnote, disclose the revenue accounts and revenue amounts related to the income generating activity.
8. In column (m), report the cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost
fuel costs for storage operations associated with self-generated power included in Account 501 and other costs associated with self-generated power.
9. In columns (q), (r) and (s) report the total project plant costs including but not exclusive of land and land rights, structures and improvements, energy storage equipment, turbines, compressors, generators, switching an
purpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property accounts listed.
Line
No.
Name
of the
Energy
Storage
Project
(a)
Functional
Classification
(b)
Location
of the
Project
(c)
MWHs
(d)
MWHs
delivered
to the grid
to support
Production
(e)
MWHs
delivered to
the grid to
support
Transmission
(f)
MWHs
delivered
to the grid
to support
Distribution
(g)
MWHs Lost
During
Conversion,
Storage and
Discharge
of Energy
Production
(h)
MWHs Lost
During
Conversion,
Storage and
Discharge of
Energy
Transmission
(i)
MWHs Lost
During
Conversion,
Storage and
Discharge
of Energy
Distribution
(j)
MWHs
Sold
(k)
Revenues
from
Energy
Storage
Operations
(l)
Power
Purchased
for
Storage
Operations
(555.1)
(Dollars)
(m)
Fuel Costs
from
associated
fuel
accounts
for Storage
Operations
Associated
with Self-
Generated
Power
(Dollars)
(n)
Other
Costs
Associate
with Self
Generate
Power
(Dollars)
(o)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35 TOTAL 0 0 0 0 0 0 0 0 0 0 0
FERC FORM NO. 1 ((NEW 12-12))
Page 414
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
ENERGY STORAGE OPERATIONS (Small Plants)
1. Small Plants are plants less than 10,000 Kw.
2. In columns (a), (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location.
3. In column (d), report project plant cost including but not exclusive of land and land rights, structures and improvements, energy storage equipment and any other costs associated with the energy storage project.
4. In column (e), report operation expenses excluding fuel, (f), maintenance expenses, (g) fuel costs for storage operations and (h) cost of power purchased for storage operations and reported in Account 555.1,
Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined.
5. If any other expenses, report in column (i) and footnote the nature of the item(s).
BALANCE AT BEGINNING OF YEAR
Line
No.
Name of the Energy Storage
Project
(a)
Functional
Classification
(b)
Location of the Project
(c)
Project Cost
(d)
Operations (Excluding
Fuel used in Storage
Operations)
(e)
Maintenance
(f)
Cost of
fuel used
in storage
operations
(g)
Account
No. 555.1,
Power
Purchased
for
Storage
Operations
(h)
Other
Expenses
(i)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36 TOTAL 0 0 0 0 0 0
FERC FORM NO. 1 (NEW 12-12)
Page 419
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
TRANSMISSION LINE STATISTICS
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 gr
voltage. If required by a State commission to report individual lines for all voltages, do so but do not group totals for each voltage under 132 kilovolts.
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. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
4. 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
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
5. 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
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
the expenses reported for the line designated.
6. 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 tw
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).
7. 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
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 g
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. Specif
other party is an associated company.
8. 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.
9. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
DESIGNATION
VOLTAGE (KV) -
(Indicate where other
than 60 cycle, 3 phase)
LENGTH (Pole miles) -
(In the case of
underground lines
report circuit miles)
COST OF LINE (Include in column (j) Land,
Land rights, and clearing right-of-way)EXPENSES, EXCEPT
Line
No.
(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)(l)(m)(n)
1 (a)
See footnote
2 AEOLUS, WY ANTICLINE, WY 500.00 500.00 Steel Tower 138.00 1 3-1272
ACSR 45/7
3 (b)
ALVEY, OR DIXONVILLE
500KV, OR 500.00 500.00 Steel Tower 58.00 1
1272
ACSR
54/19
4
(c)
BROADVIEW,
MT
COLSTRIP A,
MT 500.00 500.00 Steel Tower 113.00 1 795 ACSR
26/7
5
(d)
BROADVIEW,
MT
COLSTRIP B,
MT 500.00 500.00 Steel Tower 116.00 1 795 ACSR
26/7
6
(e)
BROADVIEW,
MT
TOWNSEND A,
MT 500.00 500.00 Steel Tower 133.00 1 795 ACSR
26/7
7
(f)
BROADVIEW,
MT
TOWNSEND B,
MT 500.00 500.00 Steel Tower 133.00 1 795 ACSR
26/7
8 CAPTAIN JACK,
OR MALIN, OR 500.00 500.00 Steel Tower 7.00 1 3-1272
ACSR 36/1
9
(g)
DIXONVILLE
500KV, OR MERIDIAN, OR 500.00 500.00 Steel Tower 74.00 1
1272
ACSR
54/19
10 (h)
HEMINGWAY, ID SUMMER LAKE,
OR 500.00 500.00 Steel Tower 242.00 1 3-1272
ACSR 36/1
11 KLAMATH
COGEN, OR
SNOW GOOSE,
OR 500.00 500.00 Steel Tower 2.00 1 1272
ACSR 36/1
12 MALIN, OR INDIAN
SPRINGS, CA 500.00 500.00 Steel Tower 47.00 1
3-1852
ACSR
51/27
13 MERIDIAN, OR KLAMATH
COGEN, OR 500.00 500.00 Steel Tower 58.00 1 1272
ACSR 36/1
14 (i)
MIDPOINT, ID HEMINGWAY, ID 500.00 500.00 Steel Tower 130.00 1 3-1272
ACSR 36/1
15 SNOW GOOSE,
OR
CAPTAIN JACK,
OR 500.00 500.00 Steel Tower 24.00 1 1272
ACSR 36/1
16 SUMMER LAKE,
OR MALIN, OR 500.00 500.00 Steel Tower 75.00 1 3-1272
ACSR 36/1
17 500kV Costs and
Expenses 31,912,852 562,611,691 594,524,543 93,641 1,949
18 90TH SOUTH,
UT
CAMP
WILLIAMS #3,
UT
345.00 345.00 Steel - SP 11 1
1557.4
ACSR/TW
36/7
19 90TH SOUTH,
UT
CAMP
WILLIAMS #4,
UT
345.00 345.00 Steel - SP 11 1
1557.4
ACSR/TW
36/7
20 90TH SOUTH,
UT
CAMP
WILLIAMS #1,
UT
345.00 345.00 Steel - SP 11.00 1 1272
ACSR 45/7
21 90TH SOUTH,
UT TERMINAL, UT 345.00 345.00 Steel - SP 16 1 1272
ACSR 45/7
From To Operating Designated
Type of
Supporting
Structure
On
Structure
of Line
Designated
On
Structures
of
Another
Line
Number
of
Circuits
Size of
Conductor
and
Material
Land Construction
Costs Total Costs Operation
Expenses
Maintena
Expens
22 ANTICLINE, WY JIM BRIDGER,
WY 345.00 345.00 Steel - H 5.00 1 3-1272
ACSR 45/7
23 BEN LOMOND,
UT POPULUS #1, ID 345.00 345.00 Steel - SP 82 1 1272
ACSR 45/7
24 BEN LOMOND,
UT POPULUS #2, ID 345.00 345.00 Steel - SP 86.00 1 1272
ACSR 45/7
25 BEN LOMOND,
UT
CAMP
WILLIAMS, UT 345.00 345.00 Steel - SP 69.00 1 1272
ACSR 45/7
26 BEN LOMOND,
UT
TERMINAL #2,
UT 345.00 345.00 Steel - SP 47.00 1 1272
ACSR 45/7
27 BEN LOMOND,
UT
TERMINAL #1,
UT 345.00 345.00 Steel - SP 47 1 1272
ACSR 45/7
28 (j)
BORAH, ID MIDPOINT #1, ID 345.00 345.00 Wood - H 83.00 1 1272
ACSR 45/7
29 (k)
BORAH, ID MIDPOINT #2, ID 345.00 345.00 Wood - H 78.00 1 1272
ACSR 45/7
30 CAMP
WILLIAMS, UT CLOVER, UT 345.00 345.00 Wood - H 50.00 1 954 ACSR
45/7
31 CAMP
WILLIAMS, UT MONA #1, UT 345.00 345.00 Wood - H 47.00 1 1272
ACSR 45/7
32 CAMP
WILLIAMS, UT MONA #2, UT 345.00 345.00 Steel Tower 48.00 1 954 ACSR
54/7
33 CAMP
WILLIAMS, UT MONA #4 UT 345.00 345.00 Steel Tower 5.00 43 1 954 ACSR
45/7
34 CLOVER, UT OQUIRRH, UT 345.00 345.00 Steel Tower 100.00 1 1949
ACSR 45/7
35 CURRANT
CREEK, UT MONA, UT 345.00 345.00 Steel - SP 1.00 1 954 ACSR
54/7
36 EMERY, UT CAMP
WILLIAMS, UT 345.00 345.00 Steel Tower 121.00 1 954 ACSR
54/7
37 EMERY, UT HUNTINGTON,
UT 345.00 345.00 Wood - H 20.00 1 954 ACSR
45/7
38 EMERY, UT SIGURD #1, UT 345.00 345.00 Steel - H 74.00 1 954 ACSR
45/7
39 EMERY, UT SIGURD #2, UT 345.00 345.00 Steel - H 75.00 1 954 ACSR
54/7
40 FOUR
CORNERS, NM PINTO, UT 345.00 345.00 Wood - H 101.00 1 795 ACSR
45/7
41 (l)
GOSHEN, ID KINPORT, ID 345.00 345.00 Wood - H 41.00 1
795
ACSR/SD
22/7
42 HUNTINGTON,
UT
HUNT PLANT 1,
UT 345.00 345.00 Steel Tower 1.00 1
2156
ACSR
8419
43 HUNTINGTON,
UT
HUNT PLANT 2,
UT 345.00 345.00 Steel Tower 1.00 1
2156
ACSR
8419
44 HUNTINGTON,
UT PINTO, UT 345.00 345.00 Steel - SP 159.00 1 795 ACSR
45/7
45 HUNTINGTON,
UT
SPANISH FORK,
UT 345.00 345.00 Steel Tower 78.00 1 954 ACSR
54/7
46
(m)
JIM BRIDGER,
WY GOSHEN, ID 345.00 345.00 Steel Tower 227.00 1 1272
ACSR 36/1
47
(n)
JIM BRIDGER,
WY BORAH, ID 345.00 345.00 Steel Tower 241.00 1 1272
ACSR 36/1
48
(o)
JIM BRIDGER,
WY KINPORT, ID 345.00 345.00 Steel - SP 235.00 1 1272
ACSR 36/1
49 (p)
KINPORT, ID MIDPOINT, ID 345.00 345.00 Steel - SP 113.00 1 1272
ACSR 45/7
50 MONA, UT SIGURD #1, UT 345.00 345.00 Wood - H 69.00 1 795 ACSR
45/7
51 MONA, UT SIGURD #2, UT 345.00 345.00 Steel - SP 69 1 954 ACSR
45/7
52 CLOVER, UT HUNTINGTON,
UT 345.00 345.00 Steel - SP 58.00 1 954 ACSR
45/7
53 RED BUTTE, UT SIGURD, UT 345.00 345.00 Steel - H 171.00 1 954 ACSR
54/7
54 SIGURD, UT UT/NV STATE
LINE 345.00 345.00 Steel Tower 190.00 1
954
ACSR/SD
13/8/7
55 SPANISH FORK,
UT
CAMP
WILLIAMS, UT 345.00 345.00 Steel - SP 35 1 1272
ACSR 45/7
56 TERMINAL, UT BORAH, ID 345.00 345.00 Wood - H 138.00 1 2-954
ACSR 45/7
57 TERMINAL, UT BORAH, ID 345.00 345.00 Steel - SP 47 1 2-1272
ACSR 45/7
58 TERMINAL, UT
CAMP
WILLIAMS #2,
UT
345.00 345.00 Steel - SP 16.00 10 1 1272
ACSR 45/7
59 TERMINAL, UT CAMP
WILLIAMS, UT 345.00 345.00 Steel Tower 23 1 1272
ACSR 45/7
60 345 kV Costs
and Expenses 162,119,068 1,695,379,068 1,857,498,136 169,834 1,823
61 AEOLUS, WY EKOLA FLATS,
WY 230.00 230.00 Steel - H 1.00 1 795 ACSR
26/7
62 AEOLUS, WY FREEZEOUT,
WY 230.00 230.00 Steel - H 4.00 1 1272
ACSR 45/7
63 AEOLUS, WY SHIRLEY BASIN
#1, WY 230.00 230.00 Steel - H 16.00 1 1158.4
ACSS 25/7
64 AEOLUS, WY SHIRLEY BASIN
#2, WY 230.00 230.00 Steel - H 16.00 1 1158.4
ACSS 25/7
65 ALVEY, OR DIXONVILLE,
OR 230.00 230.00 Wood - H 59.00 1 1272
ACSR 36/1
66 ANTELOPE, ID ANACONDA, MT 230.00 230.00 Wood - H 76.00 1 1272
ACSR 45/7
67 ANTELOPE, ID LOST RIVER, ID 230.00 230.00 Wood - H 20.00 1 795 ACSR
45/7
68 ARROWHEAD,
WY FIREHOLE, WY 230.00 230.00 Wood - H 9.00 1 795 ACSR
26/7
69 ATLANTIC CITY,
WY
COLUMBIA
GENEVA, WY 230.00 230.00 Wood - H 1.00 1 1272
ACSR 36/1
70 BEN LOMOND,
UT
NAUGHTON #1,
WY 230.00 230.00 Wood - H 88.00 1 795 ACSR
26/7
71 BEN LOMOND,
UT
NAUGHTON #2,
WY 230.00 230.00 Wood - H 88.00 1 795 ACSR
26/7
72 BIRCH CREEK,
UT RAILROAD, WY 230.00 230.00 Wood - H 19.00 1 954 ACSR
54/7
73 BITTER CREEK,
WY MONELL, WY 230.00 230.00 Wood - H 3.00 1 795 ACSR
26/7
74 BRIDGER
PUMP, WY
MANS FACE,
WY 230.00 230.00 Wood - H 1.00 1 1272
ACSR 36/1
75 BUFFALO, WY CASPER, WY 230.00 230.00 Wood - H 107.00 1 795 ACSR
26/7
76 (q)
CASPER, WY DAVE
JOHNSTON, WY 230.00 230.00 Wood - H 36.00 1
1557.4
ACSR/TW
45/7
77 CASPER, WY RIVERTON, WY 230.00 230.00 Wood - H 110.00 1 1272
ACSR 36/1
78 CHAPPEL
CREEK, WY
CRAVEN
CREEK, WY 230.00 230.00 Steel - SP 30.00 1 954 ACSR
54/7
79 CHAPPEL
CREEK, WY
JONAH GAS,
WY 230.00 230.00 Wood - H 32.00 1 1272
ACSR 45/7
80 CHAPPEL
CREEK, WY
RILEY RIDGE,
WY 230.00 230.00 Wood - H 29.00 6 1 1272
ACSR 45/7
81 CORRAL, OR OCHOCO #1,
OR 230.00 230.00 Wood - H 9.00 1
1557.4
ACSR/TW
36/7
82 CORRAL, OR OCHOCO #2,
OR 230.00 230.00 Wood - H 10.00 1
1557.4
ACSR/TW
36/7
83 CRAVEN
CREEK, WY PIONEER, WY 230.00 230.00 Wood - H 2.00 1 1272
ACSR 45/7
84 DAVE
JOHNSTON, WY SPENCE, WY 230.00 230.00 Wood - H 31.00 1
1557
ACSS/TW
45/7
85 DAVE
JOHNSTON, WY WYODAK, WY 230.00 230.00 Wood - H 69.00 1 1272
ACSR 36/1
86 DIXONVILLE
500kV, OR
DIXONVILLE
230kV, OR 230.00 230.00 Wood - H 1.00 1 1158
ACSS /25
87 DIXONVILLE,
OR
RESTON (BPA),
OR 230.00 230.00 Wood - H 17.00 1 795 ACSR
26/7
88 FAIRVIEW
(BPA), OR ISTHMUS, OR 230.00 230.00 Wood - H 12.00 1 1272
ACSR 36/1
89 FIREHOLE, WY MONUMENT,
WY 230.00 230.00 Wood - H 49.00 1 1272
ACSR 45/7
90 FRIEND, OR OCHOCO #1,
OR 230.00 230.00 Steel - SP 1.00 2
1557.4
ACSR/TW
36/7
91 FRIEND, OR OCHOCO #2,
OR 230.00 230.00 Steel - SP 0.00 1 2
1557.4
ACSR/TW
36/7
92 FRY, OR BETHEL, OR 230.00 230.00 Wood - H 26.00 1 1272
ACSR 36/1
93 FRY, OR ALVEY, OR 230.00 230.00 Wood - H 45.00 1 1272
ACSR 36/1
94 GLEN CANYON,
AZ SIGURD, UT 230.00 230.00 Wood - H 159.00 1 954 ACSR
45/7
95 GONDER, UT -
NV STATE PAVANT, UT 230.00 230.00 Wood - H 98.00 1 795 ACSR
45/7
96 DIXONVILLE,
OR
GRANTS PASS,
OR 230.00 230.00 Wood - H 62.00 1 1272
ACSR 36/1
97 HIGH PLAINS,
WY STANDPIPE, WY 230.00 230.00 Wood - H 39.00 1 1272
ACSR 45/7
98
(r)
HURRICANE,
OR
WALLA WALLA,
WA 230.00 230.00 Wood - H 78.00 1 1272
ACSR 45/7
99 JIM BRIDGER,
WY
ROCK
SPRINGS, WY 230.00 230.00 Wood - H 35.00 1 1272
ACSR 45/7
100 JIM BRIDGER,
WY SPENCE, WY 230.00 230.00 Wood - H 149.00 1 1272
ACSR 36/1
101 KLAMATH
FALLS, OR MALIN, OR 230.00 230.00 Wood - H 35.00 1 1272
ACSR 36/1
102 KLAMATH
FALLS, OR
SNOW GOOSE,
OR 230.00 230.00 Steel - SP 4.00 1
1511
ACCC
36/1
103 LIMA, WY ROBERSON,
WY 230.00 230.00 Wood - H 2.00 1 1272
ACSR 45/7
104 LONE PINE, OR KLAMATH
FALLS, OR 230.00 230.00 Wood - H 76.00 1 795 ACSR
26/7
105 LONE PINE, OR MERIDIAN #1,
OR 230.00 230.00 Steel - SP 5.00 1
1272
ACSR
54/19
106 LONE PINE, OR MERIDIAN #2,
OR 230.00 230.00 Steel - SP 5.00 1
1272
ACSR
54/19
107 MCNARY (BPA),
OR
WALLA WALLA,
WA 230.00 230.00 Wood - H 56.00 1 1272
ACSR 36/1
108 MCNARY (BPA),
OR WALLULA, WA 230.00 230.00 Wood - H 29.00 1
1158.4
ACSS/TW
25/7
109 MERIDIAN, OR GRANTS PASS,
OR 230.00 230.00 Wood - H 35.00 1 1272
ACSR 36/1
110 MONUMENT,
WY EXXON, WY 230.00 230.00 Wood - H 13.00 1 1272
ACSR 36/1
111 MONUMENT,
WY
CRAVEN
CREEK, WY 230.00 230.00 Wood - H 20.00 1 1272
ACSR 45/7
112 NAUGHTON,
WY
TREASURETON,
ID 230.00 230.00 Wood - H 80.00 1 1272
ACSR 45/7
113 NAUGHTON,
WY
MONUMENT,
WY 230.00 230.00 Wood - H 30.00 1 1272
ACSR 36/1
114 NAUGHTON,
WY
CRAVEN
CREEK, WY 230.00 230.00 Wood - H 16.00 1 954 ACSR
54/7
115 PALISADES SS,
WY BLUE RIM, WY 230.00 230.00 Wood - H 4.00 1 1272
ACSR 36/1
116 PAROWAN
VALLEY, UT SIGURD, UT 230.00 230.00 Wood - H 94.00 1 795 ACSR
45/7
117 PAROWAN
VALLEY, UT
WEST CEDAR,
UT 230.00 230.00 Wood - H 26.00 1 795 ACSR
45/7
118 PAVANT, UT SIGURD, UT 230.00 230.00 Wood - H 43.00 1 795 ACSR
45/7
119 POINT OF
ROCKS, WY
DAVE
JOHNSTON, WY 230.00 230.00 Wood - H 210.00 1 1272
ACSR 36/1
120 POMONA, WA VANTAGE, WA 230.00 230.00 Wood - H 40.00 1 1272
ACSR 45/7
121 PONDEROSA
(BPA), OR CORRAL, OR 230.00 230.00 Steel Tower 1.00 1 1 1272
ACSR 45/7
122 POMONA, WA UNION GAP, WA 230.00 230.00 Wood - H 7.00 1 1272
ACSR 36/1
123 RIVERTON, WY ROCK
SPRINGS, WY 230.00 230.00 Wood - H 118.00 1 1272
ACSR 36/1
124 RIVERTON, WY THERMOPOLIS,
WY 230.00 230.00 Wood - H 51.00 1 1272
ACSR 36/1
125 ROCK
SPRINGS, WY
FLAMING
GORGE, UT 230.00 230.00 Wood - H 55.00 1 1272
ACSR 36/1
126 ROCK
SPRINGS, WY
JIM BRIDGER,
WY 230.00 230.00 Wood - H 35.00 1 1272
ACSR 36/1
127 ROCK
SPRINGS, WY
MONUMENT,
WY 230.00 230.00 Wood - H 41.00 1 1272
ACSR 36/1
128 SHERIDAN
(MDU), WY BUFFALO, WY 230.00 230.00 Wood - H 40.00 1 795 ACSR
26/7
129 SHERIDAN
(MDU), WY
YELLOWTAIL,
MT 230.00 230.00 Wood - H 62.00 1 795 ACSR
26/7
130 SHIRLEY
BASIN, WY
DUNLAP
RANCH, WY 230.00 230.00 Wood - H 12.00 1 795 ACSR
26/7
131 SWIFT No. 1,
WA
SWIFT No. 2,
WA 230.00 230.00 Wood - H 2.00 1 954 ACSR
45/7
132 SWIFT No. 2,
WA
WOODLAND
(BPA) SS, WA 230.00 230.00 Wood - H 23.00 1 954 ACSR
45/7
133 TALBOT, WA MARENGO II,
WA 230.00 230.00 Wood - H 7.00 1 795 ACSR
26/7
134 TAP TO HANNA,
OR
NICKEL
MOUNTAIN, OR 230.00 230.00 Wood - H 9.00 1 795 ACSR
26/7
135 THERMOPOLIS,
WY
YELLOWTAIL,
MT 230.00 230.00 Wood - H 176.00 1 1272
ACSR 36/1
136 TREASURETON,
ID BRADY, ID 230.00 230.00 Wood - H 66.00 1 795 ACSR
26/7
137 TROUTDALE
(BPA), OR
GRESHAM
(PGE), OR 230.00 230.00 Steel Tower 6.00 1 954 ACSR
45/7
138 TROUTDALE
(BPA), OR
LINNEMAN
(PGE), OR 230.00 230.00 Steel Tower 0.00 6 1 900 ACSR
54/7
139 UNION GAP, WA MIDWAY (BPA),
WA 230.00 230.00 Wood - H 39.00 1 954 ACSR
45/7
140 WALLA WALLA,
WA
LEWISTON
(AVISTA), ID 230.00 230.00 Wood - H 45.00 1 1272
ACSR 36/1
141 WALLA WALLA,
WA
WANAPUM
(GPUD), WA 230.00 230.00 Wood - H 33.00 1 1272
ACSR 36/1
142 WANAPUM
(GPUD), WA POMONA, WA 230.00 230.00 Wood - H 37.00 1 1272
ACSR 36/1
143 WINDSTAR, WY GLENROCK, WY 230.00 230.00 Wood - H 13.00 1 1272
ACSR 45/7
144 WYODAK, WY BUFFALO, WY 230.00 230.00 Wood - H 69.00 1 1272
ACSR 36/1
145 YAMSAY (BPA),
OR
KLAMATH
FALLS, OR 230.00 230.00 Wood - H 63.00 1 795 ACSR
26/7
146 230kV Costs and
Expenses 40,854,068 642,872,623 683,726,691 364,287 5,636
147 (s)
ANTELOPE, ID GOSHEN, ID 161.00 161.00 Wood - H 45.00 1 397.5
ACSR 26/7
148 (t)
BIG GRASSY, ID JEFFERSON, ID 161.00 161.00 Wood - H 21 1 250HH CU
/7
149 BONNEVILLE,
ID EAGLEROCK, ID 161.00 161.00 Wood - SP 9.00 1 954 ACSR
45/7
150 EAGLEROCK, ID GOSHEN, ID 161.00 161.00 Wood - H 15.00 1 1272
ACSR 45/7
151 GOSHEN, ID GRACE, ID 161.00 161.00 Wood - H 57.00 1 250HH CU
/7
152 (u)
GOSHEN, ID JEFFERSON, ID 161.00 161.00 Wood - H 29 1 795 ACSR
26/7
153 GOSHEN, ID RIGBY, ID 161.00 161.00 Wood - H 32.00 1 397.5
ACSR 26/7
154 GOSHEN, ID SUGARMILL, ID 161.00 161.00 Wood - SP 17.00 1 477 ACSS
26/7
155 GOSHEN, ID SUGARMILL, ID 161.00 161.00 Wood - SP 26.00 1
1557.4
ACSR/TW
36/7
156 RIGBY, ID REXBURG, ID 161.00 161.00 Wood - SP 12.00 1 1272
ACSR
157 RIGBY, ID JEFFERSON, ID 161.00 161.00 Wood - SP 18.00 1 397.5
ACSR 26/7
158 RIGBY, ID SUGARMILL, ID 161.00 161.00 Wood - SP 21.00 1 1557.4
ACSR/TW
159 SUGARMILL, ID RIGBY, ID 161.00 161.00 Wood - SP 17.00 1 397.5
ACSR 26/7
160 TAP TO PAYNE,
ID PAYNE, ID 161.00 161.00 Wood - SP 3.00 1 1557.4
ACSR/TW
161 YELLOWTAIL,
MT RIMROCK, MT 161.00 161.00 Wood - H 46.00 1 556.5
ACSR 26/7
162 161 kV Costs
and Expenses 5,226,750 88,509,745 93,736,495 14,946 120
163 90TH SOUTH,
UT DUMAS #1, UT 138.00 138.00 Wood - H 12.00 1 795 AAC
/37
164 90TH SOUTH,
UT DUMAS #2, UT 138.00 138.00 Wood - H 6.00 1 1272
ACSR 45/7
165 90TH SOUTH,
UT OQUIRRH, UT 138.00 138.00 Wood - SP 12.00 1
1020
ACCC/TW
BARE
166 90TH SOUTH,
UT SANDY, UT 138.00 138.00 Steel - SP 1.00 1 795 AAC
/37
167 ABAJO, UT PINTO, UT 138.00 138.00 Wood - H 44.00 1 397.5
ACSR 26/7
168 ABAJO, UT SAN JUAN, UT 138.00 138.00 Wood - SP 10.00 1 795 ACSR
26/7
169 AGRIUM, UT THREEMILE
KNOLL, ID 138.00 138.00 Wood - H 4.00 1 397.5
ACSR 26/7
170 ANSCHTZ CO-
GEN, WY EVANSTON, WY 138.00 138.00 Wood - H 22.00 1 795 ACSR
26/7
171 (v)
ANTELOPE, ID SCOVILLE #1,
ID 138.00 138.00 Wood - H 1.00 1 397.5
ACSR 26/7
172 (w)
ANTELOPE, ID SCOVILLE #2,
ID 138.00 138.00 Wood - H 1.00 1 397.5
ACSR 26/7
173 ASHGROVE, UT CLOVER, UT 138.00 138.00 Wood - H 26.00 1 397.5
ACSR 26/7
174 ASHLEY, UT CARBON, UT 138.00 138.00 Wood - H 102.00 1 397.5
ACSR 26/7
175 ASHLEY, UT VERNAL, UT 138.00 138.00 Wood - H 12.00 1 397.5
ACSR 26/7
176 BEN LOMOND,
UT ANGEL, UT 138.00 138.00 Steel - SP 28.00 1 250 CUHD
/12
177 BEN LOMOND,
UT
BRIGHAM CITY,
UT 138.00 138.00 Wood - H 14.00 1 250 CUHD
/12
178 BEN LOMOND
#1, UT EL MONTE, UT 138.00 138.00 Steel - SP 14.00 1 795 ACSR
26/7
179 BEN LOMOND
#2, UT EL MONTE, UT 138.00 138.00 Wood - H 13 1 795 ACSR
26/7
180 BEN LOMOND,
UT
HONEYVILLE,
UT 138.00 138.00 Steel Tower 22.00 1 250 CUHD
/12
181 BEN LOMOND,
UT
SYRACUSE #2,
UT 138.00 230.00 Steel Tower 7.00 13 1 250 CUHD
/12
182 BEN LOMOND,
UT SYRACUSE, UT 138.00 138.00 Steel Tower 58.00 1 1272
ACSR 45/7
183 BEN LOMOND,
UT
W ZIRCONIUM,
UT 138.00 138.00 Wood - SP 14.00 1 795 AAC
/37
184 BEN LOMOND,
UT WHEELON, UT 138.00 138.00 Steel Tower 42.00 1 250 CUHD
/12
185 BONANZA, UT CHAPITA, UT 138.00 138.00 Wood - H 9.00 1 795 ACSR
26/7
186 BRIDGERLAND,
UT
GREEN
CANYON, UT 138.00 138.00 Wood - SP 16.00 1 1272
ACSR 45/7
187 BRIGHAM CITY,
UT WHEELON, UT 138.00 138.00 Wood - H 24.00 1 250 CUHD
/12
188 BUTLERVILLE,
UT
90TH SOUTH,
UT 138.00 138.00 Steel - SP 9.00 1 795 AAC
/37
189 CAMERON, UT MILFORD, UT 138.00 138.00 Wood - SP 25.00 1 795 ACSR
26/7
190 CAMERON, UT PAROWAN, UT 138.00 138.00 Wood - H 35.00 1 397.5
ACSR 26/7
191 CAMERON, UT SIGURD, UT 138.00 138.00 Wood - H 65.00 1 397.5
ACSR 26/7
192 CANYON COMP,
WY STR 204, WY 138.00 138.00 Wood - H 12.00 1 795 ACSR
26/7
193 CARBON, UT HELPER #2, UT 138.00 138.00 Wood - H 2.00 1 556.5
ACSR 26/7
194 CARBON, UT MOAB, UT 138.00 138.00 Wood - H 121.00 1 397.5
ACSR 26/7
195 CARBON, UT SPANISH FORK
#1, UT 138.00 138.00 Steel Tower 54.00 1 4/0 COMP
/19
196 CARBON, UT SPANISH FORK
#2, UT 138.00 138.00 Steel Tower 52.00 1 795 ACSR
26/7
197
(x)
CENTRAL
(UAMPS) #2, UT
SAINT
GEORGE, UT 138.00 138.00 Steel - SP 20.00 1 1272
ACSR 45/7
198
(y)
CENTRAL
(UAMPS) #3, UT
SAINT
GEORGE, UT 138.00 138.00 Steel - SP 20 1 1272
ACSR 45/7
199 CLEAR CREEK,
WY PAINTER, UT 138.00 138.00 Wood - SP 5.00 1 795 ACSR
26/7
200 CLOVER, UT BURRASTON
PONDS 138.00 138.00 Wood - SP 2.00 1 397.5
ACSR 26/7
201 CLOVER, UT NEBO, UT 138.00 138.00 Wood - SP 8.00 1 397.5
ACSR 26/7
202 COLUMBIA, UT SUNNYSIDE, UT 138.00 138.00 Wood - H 2.00 1 397.5
ACSR 26/7
203 COTTONWOOD,
UT HAMMER, UT 138.00 138.00 Wood - SP 5.00 1 795 AAC
/37
204 COTTONWOOD,
UT
MCCLELLAND,
UT 138.00 138.00 Steel - SP 6.00 1 795 AAC
/37
205 COTTONWOOD,
UT
SILVER CREEK,
UT 138.00 138.00 Wood - SP 30.00 1 397.5
ACSR 26/7
206 CUTLER, UT WHEELON, UT 138.00 138.00 Wood - SP 1.00 1 397.5
ACSR 26/7
207 DANIEL, UT MIDWAY, UT 138.00 138.00 Wood - SP 4.00 1 1272
ACSR 45/7
208 DRY CREEK, UT SPANISH FORK,
UT 138.00 138.00 Steel - SP 5.00 1 1272
ACSR 45/7
209 DUMAS, UT WESTFIELD, UT 138.00 138.00 Wood - SP 19.00 1 1272
ACSR 45/7
210 DYNAMO, UT TRI-CITY #1, UT 138.00 138.00 Steel - SP 2.00 1 795 ACSR
26/7
211 DYNAMO, UT TRI-CITY #2, UT 138.00 138.00 Steel - SP 3 1 795 ACSR
26/7
212 EAGLE
MOUNTAIN, UT
PONY
EXPRESS, UT 138.00 138.00 Wood - SP 10.00 1 795 ACSR
26/7
213 EAST LAYTON,
UT 105 TAP, UT 138.00 138.00 Steel - SP 15.00 1 795 ACSR
26/7
214 EBAY TAP, UT OQUIRRH, UT 138.00 138.00 Wood - SP 1.00 1 795 ACSR
26/7
215 EL MONTE, UT PIONEER, UT 138.00 138.00 Steel - SP 1.00 1 1272
ACSR 45/7
216 EL MONTE, UT STR30B, UT 138.00 138.00 Steel - SP 9.00 1 1272
ACSR 45/7
217 EMERY, UT CLAWSON, UT 138.00 138.00 Wood - SP 4 2 397.5
ACSR 26/7
218 EVANSTON, WY RAILROAD, UT 138.00 138.00 Wood - SP 3.00 1 795 ACSR
45/7
219 FORT
DOUGLAS, UT
MCCLELLAND,
UT 138.00 138.00 Wood - SP 3.00 1
1557.4
ACSR/TW
36/7
220 FRANKLIN, ID GREEN
CANYON, UT 138.00 138.00 Wood - SP 25.00 1 397.5
ACSR 26/7
221 FRANKLIN, ID TREASURETON,
ID 138.00 138.00 Wood - SP 10.00 1 795 ACSR
45/7
222 GADSBY, UT JORDAN, UT 138.00 138.00 Wood - SP 1.00 1 1272 AAC
/61
223 GADSBY, UT TERMINAL, UT 138.00 138.00 Wood - SP 6.00 1 1272
ACSR 45/7
224 GADSBY, UT THIRD WEST,
UT 138.00 138.00 Wood - SP 2.00 1 1272 AAC
/61
225 GRAPHITE, UT MOUNTAIN
VIEW, UT 138.00 138.00 Wood - SP 1.00 1 397.5
ACSR 26/7
226 GREEN
CANYON, UT NIBLEY, UT 138.00 138.00 Wood - SP 7.00 1 1272
ACSR 45/7
227 GREEN
CANYON, UT WHEELON, UT 138.00 138.00 Wood - SP 19.00 1 397.5
ACSR 26/7
228 GRINDING, UT OQUIRRH, UT 138.00 138.00 Wood - SP 7.00 1 795 ACSR
45/7
229 GRINDING, UT TOOELE, UT 138.00 138.00 Wood - SP 14.00 1 795 ACSR
45/7
230 HALE, UT MIDWAY, UT 138.00 138.00 Wood - H 19.00 1 397.5
ACSR 26/7
231 HALE, UT SPANISH FORK,
UT 138.00 138.00 Wood - H 18.00 1 1272
ACSR 45/7
232 HALE, UT TANNER, UT 138.00 138.00 Wood - H 7.00 1 1272
ACSR 45/7
233 HAMMER, UT BUTLERVILLE,
UT 138.00 138.00 Wood - SP 2 1 795 ACSR
26/7
234 HIGHLAND, UT BULL RIVER
(LEHI #5), UT 138.00 138.00 Wood - SP 8.00 1 1272
ACSR 45/7
235 HONEYVILLE,
UT LAMPO, UT 138.00 138.00 Wood - H 25.00 1 397.5
ACSR 26/7
236 HONEYVILLE,
UT WHEELON, UT 138.00 138.00 Steel Tower 14 1 250 CUHD
/12
237 HUNTINGTON,
UT MCFADDEN, UT 138.00 138.00 Wood - H 7.00 1 397.5
ACSR 26/7
238 JERUSALEM,
UT NEBO, UT 138.00 138.00 Wood - H 26.00 1 397.5
ACSR 26/7
239 JORDAN, UT MCCLELLAND,
UT 138.00 138.00 Wood - SP 5.00 1 795 AAC
/37
240 JORDAN, UT TERMINAL, UT 138.00 138.00 Wood - SP 6.00 1 1272
ACSR 45/7
241 JORDAN, UT THIRD WEST,
UT 138.00 138.00 Wood - SP 4.00 1 1272
ACSR 45/7
242 KEARNS, UT TAYLORSVILLE,
UT 138.00 138.00 Wood - SP 3.00 1 795 ACSR
26/7
243 KEARNS, UT WEST VALLEY,
UT 138.00 138.00 Wood - SP 2.00 1
1557.4
ACSR/TW
36/7
244 LONE PEAK, UT CAMP
WILLIAMS, UT 138.00 138.00 Steel - SP 8 1 795 ACSR
26/7
245 MCCLELLAND,
UT MIDVALLEY, UT 138.00 138.00 Wood - SP 6.00 1 795 ACSR
26/7
246 MCFADDEN, UT BLACKHAWK,
UT 138.00 138.00 Wood - H 11.00 1 795 ACSR
26/7
247 MID VALLEY, UT 90TH SOUTH,
UT 138.00 138.00 Wood - H 9.00 1 1272
ACSR 45/7
248 MID VALLEY #2,
UT
COTTONWOOD,
UT 138.00 138.00 Wood - SP 5.00 1
1557.4
ACSR/TW
36/7
249 MID VALLEY #1,
UT
COTTONWOOD,
UT 138.00 138.00 Wood - SP 5.00 1
1557.4
ACSR/TW
36/7
250 MID VALLEY, UT TAYLORSVILLE,
UT 138.00 138.00 Wood - SP 4.00 2 1 1272 AAC
/61
251 MIDDLETON, UT ST. GEORGE,
UT 138.00 138.00 Wood - H 1.00 1 397.5
ACSR 26/7
252 MOAB, UT PINTO, UT 138.00 138.00 Wood - H 68.00 1 397.5
ACSR 26/7
253 NAUGHTON,
WY
CANYON COMP,
WY 138.00 138.00 Wood - H 35.00 1 795 ACSR
26/7
254 NAUGHTON,
WY PAINTER, WY 138.00 138.00 Wood - H 44.00 1 795 ACSR
26/7
255 NEBO, UT DRY CREEK, UT 138.00 138.00 Wood - H 33.00 1 397.5
ACSR 26/7
256 NUCOR STEEL,
UT WHEELON, UT 138.00 138.00 Wood - H 11.00 1 795 AAC
/37
257 ONEIDA, ID OVID, UT 138.00 138.00 Wood - H 23.00 1 336.4
ACSR 26/7
258 ONIEDA, ID GRACE, ID 138.00 138.00 Wood - H 19.00 1 250 CUHD
/12
259 OQUIRRH, UT BARNEY, UT 138.00 138.00 Wood - H 5.00 1 795 ACSR
26/7
260 OQUIRRH, UT BINGHAM
CANYON, UT 138.00 138.00 Wood - H 9.00 1
1557.4
ACSR/TW
36/7
261 OQUIRRH, UT TOOELE, UT 138.00 138.00 Steel - SP 23.00 1 1272
ACSR 45/7
262 OQUIRRH, UT WILDFLOWER
TAP, UT 138.00 138.00 Wood - H 1 1
1557.4
ACSR/TW
36/7
263 WILDFLOWER
TAP, UT
WILDFLOWER,
UT 138.00 138.00 Wood - H 1.00 1 397.5
ACSR 26/7
264 PAINTER, UT RAILROAD, UT 138.00 138.00 Wood - H 7.00 1 1272
ACSR 45/7
265 PARRISH #105,
UT TERMINAL, UT 138.00 138.00 Steel - SP 24.00 1 795 ACSR
26/7
266 PAROWAN, UT WEST CEDAR,
UT 138.00 138.00 Wood - H 21.00 1 397.5
ACSR 26/7
267 PAINTER, UT TAP TO N. SALT
LAKE, UT 138.00 138.00 Steel - SP 1.00 11 1 954 ACSR
54/7
268 PARRISH, UT TERMINAL #1,
UT 138.00 138.00 Steel - SP 16.00 1 250 CUHD
/12
269 PARRISH, UT TERMINAL #2,
UT 138.00 138.00 Steel - SP 14 1 250 CUHD
/12
270 RAILROAD, UT CANYON COMP,
WY 138.00 138.00 Wood - H 17.00 1 795 ACSR
26/7
271 ST GEORGE, UT PURGATORY
FLAT, UT 138.00 138.00 Wood - SP 10.00 2 1272
ACSR 45/7
272 RED BUTTE, UT WEST CEDAR,
UT 138.00 138.00 Wood - H 49.00 1 397.5
ACSR 26/7
273 RIVERDALE, UT EAST LAYTON,
UT 138.00 138.00 Steel - SP 1.00 6 1 795 ACSR
26/7
274 SHICK, UT PARRISH, UT 138.00 138.00 Wood - H 10 1 250 CUHD
/12
275 SILVER CREEK,
UT DANIEL, UT 138.00 138.00 Wood - SP 17.00 1 795 ACSR
26/7
276 SILVER CREEK,
UT RAILROAD, UT 138.00 138.00 Wood - SP 72.00 1 1272
ACSR 45/7
277 SPANISH FORK,
UT TANNER, UT 138.00 138.00 Wood - H 10.00 1 959.6
ACSS/TW
278 SUNRISE, UT OQUIRRH, UT 138.00 138.00 Wood - SP 2 1
1557.4
ACSR/TW
36/7
279 SYRACUSE, UT ANGEL #1, UT 138.00 138.00 Wood - SP 7 1 250 CUHD
/12
280 SYRACUSE, UT CLEARFIELD
SOUTH, UT 138.00 138.00 Steel - SP 5.00 1 959.6
ACSS/TW
281 SYRACUSE, UT PARRISH, UT 138.00 138.00 Steel Tower 15.00 1 1272
ACSR 45/7
282 TAP TO ANGEL
NORTH, UT
TAP TO
PARRISH, UT 138.00 138.00 Wood - H 13.00 1 250 CUHD
/12
283 TAYLORSVILLE,
UT
90TH SOUTH,
UT 138.00 138.00 Wood - SP 6.00 2 1
1557.4
ACSR/TW
36/7
284 TERMINAL, UT KENNECOTT,
UT 138.00 138.00 Steel - SP 15.00 1 795 ACSR
26/7
285 TERMINAL, UT MIDVALLEY #1,
UT 138.00 138.00 Wood - H 7.00 1 1272 AAC
/61
286 TERMINAL, UT MIDVALLEY #2,
UT 138.00 138.00 Wood - H 7.00 1 1272
ACSR 45/7
287 TERMINAL, UT ROWLEY, UT 138.00 138.00 Wood - H 53.00 1 795 AAC
/37
288 TERMINAL, UT TOOELE, UT 138.00 138.00 Wood - H 26.00 8 1 397.5
ACSR 26/7
289 TERMINAL, UT WEST VALLEY,
UT 138.00 138.00 Wood - SP 7.00 1
1557.4
ACSR/TW
36/7
290 THREEMILE
KNOLL, ID GRACE #1, ID 138.00 138.00 Wood - H 17.00 1 250 CUHD
/12
291 THREEMILE
KNOLL, ID GRACE #2, ID 138.00 138.00 Wood - H 17.00 1 1272
ACSR 45/7
292 THREEMILE
KNOLL, ID
MONSANTO #1,
ID 138.00 138.00 Wood - H 2.00 1 1272
ACSR 45/7
293 THREEMILE
KNOLL, ID
MONSANTO #2,
ID 138.00 138.00 Steel - SP 2.00 1 1272
ACSR 45/7
294 TIMP #1, UT DYNAMO, UT 138.00 138.00 Steel - SP 2.00 1
1557.4
ACSR/TW
36/7
295 TIMP #2, UT DYNAMO, UT 138.00 138.00 Steel - SP 2 1
1557.4
ACSR/TW
36/7
296 TIMP, UT HALE, UT 138.00 138.00 Steel - SP 4.00 1
1557.4
ACSR/TW
36/7
297 TIMP, UT SPANISH FORK,
UT 138.00 138.00 Wood - H 23.00 1 1272
ACSR 45/7
298 TIMP, UT VINEYARD, UT 138.00 138.00 Wood - SP 2.00 1 1272
ACSR 45/7
299 TREASURETON,
ID GRACE, ID 138.00 138.00 Steel Tower 25.00 1 250 CUHD
/12
300 TREASURETON,
ID GRACE #2, ID 138.00 138.00 Steel Tower 25 1 250 CUHD
/12
301 TREASURETON,
ID ONEIDA, ID 138.00 138.00 Wood - H 6.00 1 250 CUHD
/12
302 TRI-CITY, UT OQUIRRH, UT 138.00 138.00 Wood - SP 3.00 19 1
1557.4
ACSR/TW
36/7
303 TRI-CITY, UT SUNRISE, ID 138.00 138.00 Wood - SP 23.00 1
1557.4
ACSR/TW
36/7
304 TRI-CITY, UT WESTFIELD, UT 138.00 138.00 Wood - H 15.00 1 1272
ACSR 45/7
305 VERNAL
(WAPA), UT NAPLES, UT 138.00 138.00 Wood - SP 1.00 1
1557.4
ACSR/TW
36/7
306 WEST CEDAR,
UT
THREE PEAKS,
UT 138.00 138.00 Wood - SP 20.00 1 795 ACSR
45/7
307 WEST VALLEY,
UT OQUIRRH, UT 138.00 138.00 Wood - H 9.00 1
1557.4
ACSR/TW
36/7
308 WESTFIELD, UT HALE, UT 138.00 138.00 Wood - H 13.00 1 795 ACSR
26/7
309 (z)
WHEELON, UT AMERICAN
FALLS, ID 138.00 138.00 Wood - H 87.00 1 250 CUHD
/12
310 WHEELON #1,
UT
TREASURETON,
ID 138.00 138.00 Steel Tower 29.00 1 250 CUHD
/12
311 WHEELON #2,
UT
TREASURETON,
ID 138.00 138.00 Steel Tower 29 1 250 CUHD
/12
312 WHEELON #3,
UT
TREASURETON,
ID 138.00 138.00 Wood - H 29.00 1 250 CUHD
/12
313 138 kV Costs
and Expenses 43,254,597 463,014,693 506,269,290 657,690 1,523
314 All 115kV Lines 1,689.00 8,375,318 337,693,805 346,069,123 73,285 5,558
315 All 69kV Lines 2,895.00 9,958,772 410,712,216 420,670,988 114,899 10,269
316 All 57kV Lines 104.00 141,468 16,119,540 16,261,008 35,984 163
317 All 46kV Lines 2,529.00 12,681,141 332,482,040 345,163,181 422,811 2,109
36 TOTAL 17,414.00 662.00 311 314,524,034 4,549,395,421 4,863,919,455 1,947,377 29,154
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: TransmissionLineStartPoint
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.
(b) Concept: TransmissionLineStartPoint
The Alvey - Dixonville 500kV line is jointly owned by PacifiCorp and Bonneville Power Administration, 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 sharedbetween the two parties and responsibility is as follows: PacifiCorp 58.0% and the Bonneville Power Administration 42.0%.
(c) Concept: TransmissionLineStartPoint
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.
(d) Concept: TransmissionLineStartPoint
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.
(e) Concept: TransmissionLineStartPoint
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.
(f) Concept: TransmissionLineStartPoint
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.
(g) Concept: TransmissionLineStartPoint
The Dixonville - Meridian 500kV line is jointly owned by PacifiCorp and Bonneville Power Administration,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 Bonneville Power Administration 42.0%.
(h) Concept: TransmissionLineStartPoint
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.
(i) Concept: TransmissionLineStartPoint
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.
(j) Concept: TransmissionLineStartPoint
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.
(k) Concept: TransmissionLineStartPoint
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.
(l) Concept: TransmissionLineStartPoint
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.
(m) Concept: TransmissionLineStartPoint
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.
(n) Concept: TransmissionLineStartPoint
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 71.0%29.0%
Populus - Borah #1 71.0%29.0%
Plant cost and operations and maintenance costs reported for this line represents PacifiCorp’s share.
(o) Concept: TransmissionLineStartPoint
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 71.0%29.0%
Populus - Kinport 71.0%29.0%
Plant cost and operations and maintenance costs reported for this line represents PacifiCorp’s share.
(p) Concept: TransmissionLineStartPoint
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.
(q) Concept: TransmissionLineStartPoint
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.
(r) Concept: TransmissionLineStartPoint
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.
(s) Concept: TransmissionLineStartPoint
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.
(t) Concept: TransmissionLineStartPoint
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.
(u) Concept: TransmissionLineStartPoint
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.
(v) Concept: TransmissionLineStartPoint
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.
(w) Concept: TransmissionLineStartPoint
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.
(x) Concept: TransmissionLineStartPoint
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.
(y) Concept: TransmissionLineStartPoint
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.
(z) Concept: TransmissionLineStartPoint
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.
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
TRANSMISSION LINES ADDED DURING YEAR
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)
permissible to report in these columns the 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
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.
LINE DESIGNATION SUPPORTING
STRUCTURE
CIRCUITS PER
STRUCTURE CONDUCTORS LINE COST
Line
No.
(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)(l)(m)(n)(o)(p)
1
PUNKIN
CENTER,
WA
FLINT,
WA 10 Wood - SP 10 1 1 795 ACSR 26/7 Vertical 10'115 691,274 5,363,227 3,883,716 (a)
9,938,217 Ove
2
KLAMATH
FALLS,
OR
SNOW
GOOSE
#2, OR
4 Steel/Wood
- SP 8 1 1 1511 ACCC 36/1 Vertical 18'230 493,584 5,185,841 6,810,090 (b)
12,489,515 Ove
44 TOTAL 14 18 2 2 1,184,858 10,549,068 10,693,806 22,427,732
FERC FORM NO. 1 (REV. 12-03)
Page 424-425
From To
Line
Length
in
Miles
Type
Average
Number
per
Miles
Present Ultimate Size Specification Configuration
and Spacing
Voltage KV
(Operating)
Land and
Land
Rights
Poles,
Towers
and
Fixtures
Conductors
and
Devices
Asset
Retire.
Costs
Total Con
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: CostOfTransmissionLinesAdded
Costs are estimated between Poles, Towers and Fixtures in column (m) and Conductors and Devices in column (n).
(b) Concept: CostOfTransmissionLinesAdded
Costs are estimated between Poles, Towers and Fixtures in column (m) and Conductors and Devices in column (n).
FERC FORM NO. 1 (REV. 12-03)
Page 424-425
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
SUBSTATIONS
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).
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.
Character of Substation VOLTAGE (In MVa)Conversion Apparatus and
Special Equipment
Line
No.(a)(b)(b-1)(c)(d)(e)
(f)
(g)(h)(i)(j)(k)
1 BELMONT, CA Distribution Unattended 69.00 12.47 25 1
2 BIG SPRINGS, CA Distribution Unattended 69.00 12.47 6 1
3 CASTELLA, CA Distribution Unattended 69.00 2.40 2 3
4 CLEAR LAKE, CA Distribution Unattended 69.00 12.47 6 4
5 DOG CREEK, CA Distribution Unattended 69.00 2.40 0 1
6 DORRIS, CA Distribution Unattended 69.00 12.47 8 3
7 FORT JONES, CA Distribution Unattended 69.00 12.47 6 1
8 GASQUET, CA Distribution Unattended 115.00 12.47 9 1
9 GREENHORN, CA Distribution Unattended 69.00 12.47 13 1
10 HAMBURG, CA Distribution Unattended 69.00 2.40 1 1
11 HAPPY CAMP, CA Distribution Unattended 69.00 12.47 8 3
12 HORNBROOK, CA Distribution Unattended 69.00 12.47 4 3
13 INTERNATIONAL PAPER, CA Distribution Unattended 69.00 2.40 9 3
14 LAKE EARL, CA Distribution Unattended 69.00 12.47 13 1
15 LASSEN, CA Distribution Unattended 115.00 12.47 25 1
16 LITTLE SHASTA, CA Distribution Unattended 69.00 7.20 2.40 2 3
17 LUCERNE, CA Distribution Unattended 115.00 12.47 9 1
18 MACDOEL, CA Distribution Unattended 69.00 20.80 37 2
19 MCCLOUD, CA Distribution Unattended 69.00 12.47 6 1
20 MILLER REDWOOD, CA Distribution Unattended 69.00 12.47 4 3
21 MONTAGUE, CA Distribution Unattended 69.00 12.47 6 1
22 MORRISON CREEK, CA Distribution Unattended 69.00 12.47 14 1
23 MOUNT SHASTA, CA Distribution Unattended 69.00 12.47 29 5
24 NEWELL, CA Distribution Unattended 69.00 12.47 13 1
25 NORTH DUNSMUIR, CA Distribution Unattended 69.00 12.47 6 6
26 NORTHCREST, CA Distribution Unattended 69.00 12.47 20 4
27 NUTGLADE, CA Distribution Unattended 69.00 2.40 2 3
28 PATRICKS CREEK, CA Distribution Unattended 115.00 7.20 1 1
29 PEREZ, CA Distribution Unattended 69.00 12.47 2 3
30 REDWOOD, CA Distribution Unattended 69.00 12.47 14 1
31 SCOTT BAR, CA Distribution Unattended 69.00 12.47 2 3
32 SEIAD, CA Distribution Unattended 69.00 12.47 2 3
33 SHASTINA, CA Distribution Unattended 69.00 20.80 18 3
34 SHOTGUN CREEK, CA Distribution Unattended 69.00 12.47 1 1
35 SMITH RIVER, CA Distribution Unattended 69.00 12.47 6 3
36 SNOW BRUSH, CA Distribution Unattended 69.00 7.20 1 3
37 SOUTH DUNSMUIR, CA Distribution Unattended 69.00 4.16 2 3
38 TULELAKE, CA Distribution Unattended 69.00 12.47 20 1
39 TUNNEL, CA Distribution Unattended 69.00 12.47 2.40 6 6
Name and Location of Substation Transmission
or Distribution
Attended or
Unattended
Primary
Voltage
(In MVa)
Secondary
Voltage (In
MVa)
Tertiary
Voltage
(In
MVa)
Capacity
of
Substation
(In
Service)
(In MVa)
Number of
Transformers
In Service
Number of
Spare
Transformers
Type of
Equipment
Number
of Units
Total
Capacity
(In MVa)
40 WALKER BRYAN, CA Distribution Unattended 69.00 12.47 9 3
41 WEED, CA Distribution Unattended 115.00 69.00 75 2
42 YUBA, CA Distribution Unattended 69.00 12.47 4 3
43 YUROK, CA Distribution Unattended 69.00 12.47 4 3
44 COPCO #2, CA Transmission Attended 115.00 69.00 12.47 52 4
45 COPCO #2 230KV, CA Transmission Attended 230.00 115.00 12.47 66 5
46 AGER, CA Transmission Unattended 115.00 69.00 12.47 5 3
47 ALTURAS, CA Transmission Unattended 115.00 69.00 12.47 35 4
48 CRAG VIEW, CA Transmission Unattended 115.00 69.00 12.47 19 3
49 DEL NORTE, CA Transmission Unattended 115.00 69.00 13.20 150 2
50 YREKA, CA Transmission Unattended 115.00 69.00 12.47 145 3
51 ASHTON, ID Distribution Attended 46.00 12.47 2.40 15 2
52 TANNER, ID Distribution Attended 46.00 12.47 4 1
53 ALEXANDER, ID Distribution Unattended 46.00 12.47 4 1
54 AMMON, ID Distribution Unattended 161.00 13.20 30 1
55 AMPS, ID Distribution Unattended 230.00 69.00 12.47 75 1
56 ANDERSON, ID Distribution Unattended 69.00 12.47 20 1
57 ARCO, ID Distribution Unattended 69.00 12.47 6 1
58 ARIMO, ID Distribution Unattended 46.00 12.47 8 1
59 BANCROFT, ID Distribution Unattended 46.00 12.47 4 1
60 BELSON, ID Distribution Unattended 69.00 12.47 14 1
61 BERENICE, ID Distribution Unattended 69.00 12.47 11 1
62 CAMAS, ID Distribution Unattended 69.00 12.47 14 1
63 CANYON CREEK, ID Distribution Unattended 69.00 24.90 20 1
64 CHESTERFIELD, ID Distribution Unattended 46.00 12.47 5 1
65 CINDER BUTTE, ID Distribution Unattended 161.00 12.47 30 1
66 CLEMENTS, ID Distribution Unattended 69.00 12.47 13 1
67 CLIFTON, ID Distribution Unattended 46.00 12.47 11 1
68 COVE, ID Distribution Unattended 46.00 12.47 6 1
69 DOWNEY, ID Distribution Unattended 46.00 12.47 5 1
70 DUBOIS, ID Distribution Unattended 69.00 12.47 13 1
71 EASTMONT, ID Distribution Unattended 69.00 12.47 14 1
72 EGIN, ID Distribution Unattended 69.00 12.47 14 1
73 EIGHT MILE, ID Distribution Unattended 46.00 12.47 4 1
74 FRANKLIN, ID Distribution Unattended 138.00 69.00 13.80 75 1
75 GEORGETOWN, ID Distribution Unattended 69.00 12.47 6 1
76 GRACE CITY, ID Distribution Unattended 46.00 12.47 14 1
77 HAMER, ID Distribution Unattended 69.00 12.47 14 1
78 HAYES, ID Distribution Unattended 69.00 12.47 9 1
79 HENRY, ID Distribution Unattended 46.00 7.20 1 1
80 HOLBROOK, ID Distribution Unattended 69.00 12.47 6 1
81 HOOPES, ID Distribution Unattended 69.00 12.47 14 1 1
82 HORSLEY, ID Distribution Unattended 46.00 12.47 4 1
83 IDAHO FALLS, ID Distribution Unattended 46.00 12.47 20 1
84 INDIAN CREEK, ID Distribution Unattended 69.00 7.20 3 1
85 JEFFCO, ID Distribution Unattended 69.00 24.90 22 1
86 KETTLE, ID Distribution Unattended 69.00 24.90 14 1
87 LAVA, ID Distribution Unattended 46.00 12.47 6 1
88 LUND, ID Distribution Unattended 46.00 12.47 5 1
89 MCCAMMON, ID Distribution Unattended 46.00 12.47 4 1
90 MENAN, ID Distribution Unattended 69.00 12.47 11 1
91 MERRILL, ID Distribution Unattended 69.00 12.47 20 1
92 MILLER, ID Distribution Unattended 69.00 12.47 5 1
93 MONTPELIER, ID Distribution Unattended 69.00 12.47 11 1
94 MOODY, ID Distribution Unattended 69.00 24.90 14 1
95 MUD LAKE, ID Distribution Unattended 69.00 12.47 14 1
96 NEWDALE, ID Distribution Unattended 69.00 12.47 20 1
97 OSGOOD, ID Distribution Unattended 69.00 12.47 20 1
98 PRESTON, ID Distribution Unattended 46.00 12.47 13 1
99 RAYMOND, ID Distribution Unattended 69.00 12.47 6 1
100 RENO, ID Distribution Unattended 69.00 12.47 20 1
101 REXBURG, ID Distribution Unattended 161.00 69.00 12.47 210 3 1
102 ROBERTS, ID Distribution Unattended 69.00 12.47 8 1
103 RUBY, ID Distribution Unattended 69.00 12.47 7 1
104 SAINT ANTHONY, ID Distribution Unattended 69.00 46.00 2.40 33 2
105 SAND CREEK, ID Distribution Unattended 69.00 12.47 40 2
106 SANDUNE, ID Distribution Unattended 69.00 24.90 30 1
107 SHELLEY, ID Distribution Unattended 46.00 12.47 20 1
108 SMITH, ID Distribution Unattended 69.00 12.47 20 1
109 SOUTH FORK, ID Distribution Unattended 69.00 12.47 14 1
110 SPUD, ID Distribution Unattended 46.00 12.47 8 1
111 ST CHARLES, ID Distribution Unattended 69.00 12.47 5 1
112 SUGAR CITY, ID Distribution Unattended 69.00 12.47 13 1
113 SUNNYDELL, ID Distribution Unattended 69.00 12.47 13 1
114 TARGHEE, ID Distribution Unattended 46.00 12.47 4 1
115 THORNTON, ID Distribution Unattended 69.00 12.47 7 1
116 TREASURETON, ID Distribution Unattended 230.00 138.00 13.80 534 2 1
117 UCON, ID Distribution Unattended 69.00 12.47 7 1
118 WATKINS, ID Distribution Unattended 69.00 24.90 14 1
119 WEBSTER, ID Distribution Unattended 69.00 12.47 20 1
120 WESTON, ID Distribution Unattended 46.00 12.47 4 1
121 WESTWOOD, ID Distribution Unattended 161.00 13.20 30 1
122 WINSPER, ID Distribution Unattended 69.00 24.90 22 1
123 GRACE, ID Transmission Attended 161.00 138.00 12.47 217 2
124 (a)
ANTELOPE, ID Transmission Unattended 230.00 161.00 13.80 419 3 1
125 (b)
BIG GRASSY, ID Transmission Unattended 161.00 69.00 12.47 67 1
126 BONNEVILLE, ID Transmission Unattended 161.00 69.00 6.60 67 1
127 CONDA, ID Transmission Unattended 138.00 46.00 12.47 67 1
128 FISHCREEK, ID Transmission Unattended 161.00 46.00 6.60 25 3 1
129 (c)
GOSHEN, ID Transmission Unattended 345.00 161.00 13.80 1608 5
130 (d)
JEFFERSON, ID Transmission Unattended 161.00 69.00 6.60 133 (s)2
131 MALAD, ID Transmission Unattended 138.00 69.00 6.60 39 4 1
132 (e)
MIDPOINT, ID Transmission Unattended 500.00 345.00 34.50 1500 3
133 OVID, ID Transmission Unattended 138.00 69.00 12.47 105 2
134 RIGBY, ID Transmission Unattended 161.00 69.00 13.80 229 4 1
135 SCOVILLE, ID Transmission Unattended 138.00 69.00 13.80 67 1
136 SUGARMILL, ID Transmission Unattended 161.00 69.00 12.47 268 4
137 (f)
THREEMILE KNOLL, ID Transmission Unattended 345.00 138.00 13.20 775 2
138 (g)
COLSTRIP, MT Transmission Attended 500.00 230.00 68 2
139 (h)
BROADVIEW, MT Transmission Unattended 500.00 230.00 32 2
140 YELLOWTAIL, MT Transmission Unattended 230.00 161.00 13.20 100 1
141 BEND, OR Distribution Attended 69.00 12.47 31 3
142 WESTSIDE, OR Distribution Attended 69.00 12.47 23 9
143 26TH STREET, OR Distribution Unattended 20.80 4.16 5 1
144 35TH STREET, OR Distribution Unattended 20.80 2.40 15 3
145 AGNESS AVE, OR Distribution Unattended 115.00 12.47 25 1
146 ALBINA, OR Distribution Unattended 115.00 12.47 120 2
147 ALDERWOOD, OR Distribution Unattended 69.00 12.47 45 2
148 ARLINGTON, OR Distribution Unattended 69.00 12.47 5 1
149 ASHLAND, OR Distribution Unattended 115.00 12.47 20 1
150 ATHENA, OR Distribution Unattended 69.00 12.47 9 1
151 BANDON TIE, OR Distribution Unattended 20.80 12.47 8 3 1
152 BEACON, OR Distribution Unattended 69.00 12.47 11 3
153 BEALL LANE, OR Distribution Unattended 115.00 12.47 25 1
154 BEATTY, OR Distribution Unattended 69.00 12.47 6 1
155 BELKNAP, OR Distribution Unattended 115.00 69.00 13.20 65 3
156 BLALOCK, OR Distribution Unattended 69.00 12.47 2 3
157 BLOSS, OR Distribution Unattended 115.00 12.47 32 2
158 BLY, OR Distribution Unattended 69.00 12.47 8 3
159 BOISE CASCADE, OR Distribution Unattended 69.00 12.47 4.16 3 1
160 BONANZA, OR Distribution Unattended 69.00 12.47 9 3
161 BOND, OR Distribution Unattended 69.00 12.47 25 1
162 BROOKHURST, OR Distribution Unattended 115.00 12.47 50 2
163 BROWNSVILLE, OR Distribution Unattended 69.00 20.80 13 1
164 BRYANT, OR Distribution Unattended 69.00 12.47 40 2
165 BUCHANAN, OR Distribution Unattended 115.00 20.80 45 2
166 BUCKAROO, OR Distribution Unattended 69.00 12.47 34 2
167 CAMPBELL, OR Distribution Unattended 115.00 12.47 45 2
168 CANNON BEACH, OR Distribution Unattended 115.00 12.47 13 1
169 CANYONVILLE, OR Distribution Unattended 115.00 12.47 25 1
170 CARNES, OR Distribution Unattended 69.00 12.47 9 3
171 CASEBEER, OR Distribution Unattended 69.00 20.80 20 1
172 CAVEMAN, OR Distribution Unattended 115.00 12.47 45 2
173 CHERRY LANE, OR Distribution Unattended 69.00 12.47 25 1
174 CHILOQUIN MARKET, OR Distribution Unattended 69.00 12.47 9 3
175 CHINA HAT, OR Distribution Unattended 69.00 12.47 25 1
176 CIRCLE BLVD, OR Distribution Unattended 115.00 20.80 80 2
177 CLEVELAND AVE, OR Distribution Unattended 69.00 12.47 45 2
178 CLOAKE, OR Distribution Unattended 69.00 20.80 20 1
179 COBURG, OR Distribution Unattended 69.00 20.80 2.40 10 3
180 COLISEUM, OR Distribution Unattended 20.80 4.16 12 2
181 COLUMBIA, OR Distribution Unattended 115.00 69.00 7.20 128 3 1
182 CONSER ROAD, OR Distribution Unattended 115.00 20.80 30 1 1
183 COOS RIVER, OR Distribution Unattended 115.00 20.80 20 1
184 COQUILLE, OR Distribution Unattended 115.00 20.80 40 2
185 CREEK, OR Distribution Unattended 69.00 34.50 5 1
186 CROOKED RIVER RANCH, OR Distribution Unattended 69.00 20.80 25 2
187 CROWFOOT, OR Distribution Unattended 115.00 20.80 20 1
188 CULLY, OR Distribution Unattended 115.00 12.47 25 1
189 CULVER, OR Distribution Unattended 69.00 12.47 7.20 13 1
190 DAIRY, OR Distribution Unattended 69.00 12.47 25 1
191 DALLAS, OR Distribution Unattended 115.00 20.80 50 2
192 DALREED, OR Distribution Unattended 230.00 34.50 13.20 95 4 1
193 DEVILS LAKE, OR Distribution Unattended 115.00 20.80 50 2
194 DIXON, OR Distribution Unattended 115.00 4.16 7.20 7 1
195 DODGE BRIDGE, OR Distribution Unattended 69.00 20.80 25 2
196 DOWELL, OR Distribution Unattended 115.00 12.47 25 1
197 EASY VALLEY, OR Distribution Unattended 115.00 12.47 45 2
198 EMPIRE, OR Distribution Unattended 115.00 20.80 20 1
199 ENTERPRISE, OR Distribution Unattended 69.00 20.80 19 2
200 FERN HILL, OR Distribution Unattended 115.00 12.47 7.20 13 1
201 FIELDER CREEK, OR Distribution Unattended 115.00 20.80 20 1
202 FISH HOLE, OR Distribution Unattended 115.00 69.00 12.47 19 3
203 FOOTHILLS, OR Distribution Unattended 69.00 12.47 21 4
204 FRALEY, OR Distribution Unattended 69.00 12.47 5 3
205 GARDEN VALLEY, OR Distribution Unattended 69.00 20.80 20 1
206 GLENDALE, OR Distribution Unattended 230.00 12.47 25 2
207 GLENEDEN, OR Distribution Unattended 20.80 4.16 6 1
208 GLIDE, OR Distribution Unattended 115.00 12.47 13 1
209 GOLD HILL, OR Distribution Unattended 69.00 12.47 11 3
210 GORDON HOLLOW, OR Distribution Unattended 69.00 20.80 6 1
211 GOSHEN, OR Distribution Unattended 115.00 20.80 20 1
212 GRANT STREET, OR Distribution Unattended 115.00 20.80 45 2
213 GREEN, OR Distribution Unattended 69.00 12.47 25 1
214 GRIFFIN CREEK, OR Distribution Unattended 115.00 12.47 20 1
215 HAMAKER, OR Distribution Unattended 69.00 12.47 8 3
216 HARRISBURG, OR Distribution Unattended 69.00 20.80 13 1
217 HENLEY, OR Distribution Unattended 69.00 12.47 6 3
218 HERMISTON, OR Distribution Unattended 69.00 12.47 20 1
219 HILLVIEW, OR Distribution Unattended 115.00 20.80 45 2
220 HINKLE, OR Distribution Unattended 69.00 12.47 20 1
221 HOLLADAY, OR Distribution Unattended 115.00 12.47 75 3
222 HOLLYWOOD, OR Distribution Unattended 115.00 12.47 50 2
223 HOOD RIVER, OR Distribution Unattended 69.00 12.47 40 2
224 HORNET, OR Distribution Unattended 69.00 12.47 20 1
225 HUMBUG, OR Distribution Unattended 69.00 12.47 9 1
226 HUNTERS CIRCLE, OR Distribution Unattended 69.00 12.47 13 1
227 ILLAHEE FLATS, OR Distribution Unattended 115.00 7.20 2 1
228 INDEPENDENCE, OR Distribution Unattended 69.00 20.80 25 1
229 JACKSONVILLE, OR Distribution Unattended 115.00 69.00 13.20 75 2
230 JEFFERSON, OR Distribution Unattended 69.00 20.80 25 1
231 JEROME PRAIRIE, OR Distribution Unattended 115.00 12.47 25 1
232 JORDAN POINT, OR Distribution Unattended 115.00 12.47 20 1
233 JOSEPH, OR Distribution Unattended 20.80 12.47 6 1 1
234 JUNCTION CITY, OR Distribution Unattended 69.00 20.80 22 2
235 KENNEDY, OR Distribution Unattended 115.00 13.20 30 1
236 KENWOOD, OR Distribution Unattended 69.00 12.47 3 3
237 KILLINGSWORTH, OR Distribution Unattended 69.00 12.47 40 2
238 KNAPPA SVENSEN, OR Distribution Unattended 115.00 12.47 4.16 6 1
239 KNOTT, OR Distribution Unattended 115.00 57.00 12.47 172 5
240 LAKEPORT, OR Distribution Unattended 69.00 12.47 50 2
241 LANCASTER, OR Distribution Unattended 69.00 20.80 13 3
242 LEBANON, OR Distribution Unattended 115.00 20.80 45 2
243 LINCOLN, OR Distribution Unattended 115.00 12.47 105 3
244 LOCKHART STREET, OR Distribution Unattended 115.00 20.80 40 2
245 LYONS, OR Distribution Unattended 69.00 20.80 25 2
246 MADRAS, OR Distribution Unattended 69.00 12.47 7.20 25 2
247 MALLORY, OR Distribution Unattended 115.00 12.47 25 1
248 MARYS RIVER, OR Distribution Unattended 115.00 20.80 20 1
249 MCKAY SW, OR Distribution Unattended 69.00 12.47 2.40 25 1
250 MEDCO, OR Distribution Unattended 115.00 12.47 20 1
251 MEDFORD, OR Distribution Unattended 115.00 12.47 67 8
252 MERLIN, OR Distribution Unattended 115.00 12.47 45 2
253 MERRILL, OR Distribution Unattended 69.00 12.47 17 6
254 MINAM, OR Distribution Unattended 69.00 12.47 0 1
255 MODOC, OR Distribution Unattended 69.00 12.47 6 3
256 MONPAC, OR Distribution Unattended 115.00 69.00 13.20 50 1
257 MURDER CREEK, OR Distribution Unattended 115.00 20.80 100 4
258 MYRTLE CREEK, OR Distribution Unattended 69.00 12.47 14 1
259 MYRTLE POINT, OR Distribution Unattended 115.00 20.80 9 1
260 NEW DESCHUTES, OR Distribution Unattended 69.00 12.47 25 1
261 NEW O'BRIEN, OR Distribution Unattended 115.00 12.47 9 1
262 OAK KNOLL, OR Distribution Unattended 115.00 12.47 45 2
263 OAKLAND, OR Distribution Unattended 115.00 12.47 8 1
264 OREMET, OR Distribution Unattended 115.00 20.80 75 3
265 OVERPASS, OR Distribution Unattended 69.00 12.47 7.20 45 2
266 PALLETTE, OR Distribution Unattended 69.00 20.80 1 1 1
267 PARK STREET, OR Distribution Unattended 115.00 12.47 40 2
268 PARKROSE, OR Distribution Unattended 115.00 12.47 37 2
269 PENDLETON, OR Distribution Unattended 69.00 12.47 43 6 1
270 PILOT ROCK, OR Distribution Unattended 69.00 12.47 22 2
271 POWELL BUTTE, OR Distribution Unattended 115.00 12.47 13 1
272 PRINEVILLE, OR Distribution Unattended 115.00 12.47 75 3
273 PROVOLT, OR Distribution Unattended 69.00 12.47 11 3
274 QUEEN AVE, OR Distribution Unattended 69.00 20.80 50 2
275 RED BLANKET, OR Distribution Unattended 69.00 4.16 2 3
276 REDMOND, OR Distribution Unattended 115.00 12.47 50 2
277 RIDDLE, OR Distribution Unattended 115.00 69.00 75 2
278 RIDDLE VENEER, OR Distribution Unattended 115.00 12.47 7.20 25 1
279 ROBERTS CREEK, OR Distribution Unattended 115.00 69.00 13.20 50 1
280 ROGUE RIVER, OR Distribution Unattended 69.00 12.47 13 1
281 ROSEBURG, OR Distribution Unattended 115.00 20.80 50 2
282 ROSS AVENUE, OR Distribution Unattended 69.00 12.47 9 3
283 ROXY ANN, OR Distribution Unattended 115.00 12.47 25 1
284 RUCH, OR Distribution Unattended 115.00 12.47 9 1
285 RUNNING Y, OR Distribution Unattended 69.00 20.80 9 1
286 RUSSELLVILLE, OR Distribution Unattended 115.00 12.47 45 2
287 SAGE ROAD, OR Distribution Unattended 115.00 12.47 40 2
288 SCENIC, OR Distribution Unattended 115.00 69.00 13.20 70 3
289 SCIO, OR Distribution Unattended 69.00 12.47 8 1
290 SEASIDE, OR Distribution Unattended 115.00 12.47 40 2
291 SELMA, OR Distribution Unattended 115.00 12.47 9 1
292 SHASTA WAY, OR Distribution Unattended 12.47 4.16 2 3
293 SHEVLIN PARK, OR Distribution Unattended 69.00 12.47 7.20 50 2
294 SIMTAG BOOSTER PUMP, OR Distribution Unattended 34.50 4.16 19 2
295 SOUTH DUNES, OR Distribution Unattended 115.00 12.47 9 1
296 SOUTHGATE, OR Distribution Unattended 69.00 20.80 20 1
297 SPRAGUE RIVER, OR Distribution Unattended 69.00 12.47 7 3
298 STATE STREET, OR Distribution Unattended 115.00 20.80 40 2
299 STAYTON, OR Distribution Unattended 69.00 20.80 55 2
300 STEAMBOAT, OR Distribution Unattended 115.00 7.20 0 1
301 STEVENS ROAD, OR Distribution Unattended 115.00 20.80 50 2
302 SUTHERLIN, OR Distribution Unattended 115.00 12.47 25 1
303 SWEET HOME, OR Distribution Unattended 115.00 20.80 42 2
304 TAKELMA, OR Distribution Unattended 115.00 20.80 13 1
305 TALENT, OR Distribution Unattended 115.00 12.47 50 2
306 TEXUM, OR Distribution Unattended 69.00 12.47 25 1
307 TILLER, OR Distribution Unattended 115.00 12.47 5 1 1
308 TOLO, OR Distribution Unattended 69.00 12.47 11 1
309 TURKEY HILL, OR Distribution Unattended 69.00 12.47 13 3
310 UMAPINE, OR Distribution Unattended 69.00 12.47 20 1
311 UMATILLA, OR Distribution Unattended 69.00 12.47 25 2
312 VERNON, OR Distribution Unattended 115.00 12.47 7.20 50 2
313 VILAS, OR Distribution Unattended 115.00 12.47 25 1
314 VILLAGE GREEN, OR Distribution Unattended 115.00 20.80 40 2
315 VINE STREET, OR Distribution Unattended 69.00 20.80 30 1
316 WALLOWA, OR Distribution Unattended 69.00 12.47 7 1
317 WARM SPRINGS, OR Distribution Unattended 69.00 20.80 13 3
318 WARRENTON, OR Distribution Unattended 115.00 12.47 38 2
319 WASCO, OR Distribution Unattended 20.80 4.16 2 3
320 WECOMA BEACH, OR Distribution Unattended 20.80 4.16 3 1
321 WESTON, OR Distribution Unattended 69.00 12.47 25 1
322 WEYERHAEUSER, OR Distribution Unattended 69.00 12.47 40 2
323 WHITE CITY, OR Distribution Unattended 115.00 12.47 65 3
324 WILLOW COVE, OR Distribution Unattended 34.50 4.16 28 3
325 WINCHESTER, OR Distribution Unattended 115.00 69.00 12.47 75 5
326 WINSTON, OR Distribution Unattended 69.00 12.47 23 3
327 YEW AVENUE, OR Distribution Unattended 115.00 12.47 25 1
328 YOUNGS BAY, OR Distribution Unattended 115.00 12.47 37 2
329 LEMOLO 1, OR Transmission Attended 12.47 7.20 2 3
330 PARRISH GAP, OR Transmission Attended 230.00 69.00 12.47 150 1
331 APPLEGATE, OR Transmission Unattended 115.00 69.00 12.47 65 2
332 CALAPOOYA, OR Transmission Unattended 230.00 20.80 12.47 88 2
333 CAVE JUNCTION, OR Transmission Unattended 115.00 69.00 13.20 70 2
334 CHILOQUIN, OR Transmission Unattended 230.00 115.00 12.47 131 5 1
335 COLD SPRINGS, OR Transmission Unattended 230.00 69.00 66 2
336 COVE, OR Transmission Unattended 230.00 69.00 2.40 127 3
337 DIAMOND HILL, OR Transmission Unattended 230.00 69.00 12.47 75 1
338 DIXONVILLE 230, OR Transmission Unattended 230.00 115.00 13.80 344 6
339 (i)
DIXONVILLE 500, OR Transmission Unattended 500.00 230.00 34.50 650 3 1
340 FRIEND, OR Transmission Unattended 230.00 115.00 12.47 500 2
341 FRY, OR Transmission Unattended 230.00 115.00 12.47 500 2 3
342 GRANTS PASS, OR Transmission Unattended 230.00 115.00 12.47 583 4 2
343 HAZELWOOD, OR Transmission Unattended 115.00 69.00 12.47 154 3
344 (j)
HURRICANE, OR Transmission Unattended 230.00 69.00 29 2 1
345 ISTHMUS, OR Transmission Unattended 230.00 115.00 13.80 250 1
346 KLAMATH FALLS, OR Transmission Unattended 230.00 69.00 13.80 401 7
347 LONE PINE, OR Transmission Unattended 230.00 115.00 13.80 733 10
348 (k)
MALIN, OR Transmission Unattended 500.00 230.00 13.80 775 4 1
349 (l)
MERIDIAN, OR Transmission Unattended 500.00 230.00 34.50 1300 6 1
350 MILE HI, OR Transmission Unattended 115.00 69.00 12.47 39 4
351 NICKEL MOUNTAIN, OR Transmission Unattended 230.00 115.00 12.47 125 1
352 PILOT BUTTE, OR Transmission Unattended 230.00 69.00 400 4
353 PONDEROSA, OR Transmission Unattended 230.00 115.00 12.47 500 2
354 PROSPECT CENTRAL, OR Transmission Unattended 115.00 69.00 12.47 45 3 1
355 (m)
ROUNDUP SUB, OR Transmission Unattended 230.00 69.00 67 2
356 (n)
SANTIAM TIE, OR Transmission Unattended 230.00 69.00 12.47 75 1
357 SNOW GOOSE, OR Transmission Unattended 500.00 230.00 34.50 650 3 1
358 TROUTDALE, OR Transmission Unattended 230.00 115.00 13.20 500 3
359 TUCKER, OR Transmission Unattended 115.00 69.00 12.47 100 2
360 WHETSTONE, OR Transmission Unattended 230.00 115.00 12.47 250 1 1
361 PIONEER PLANT, UT Distribution Attended 138.00 12.47 30 1
362 WEST VALLEY, UT Distribution Attended 138.00 12.47 30 1
363 106TH SOUTH, UT Distribution Unattended 138.00 12.47 30 1
364 118TH SOUTH, UT Distribution Unattended 138.00 12.47 30 1
365 126TH SOUTH, UT Distribution Unattended 138.00 12.47 66 2
366 23RD STREET, UT Distribution Unattended 46.00 12.47 13 1
367 70TH SOUTH, UT Distribution Unattended 138.00 12.47 30 1
368 ALTAVIEW, UT Distribution Unattended 46.00 12.47 45 2
369 AMALGA, UT Distribution Unattended 46.00 12.47 11 1
370 AMERICAN FORK, UT Distribution Unattended 138.00 12.47 63 2
371 ANGEL, UT Distribution Unattended 138.00 46.00 12.47 135 3
372 ARAGONITE, UT Distribution Unattended 46.00 12.47 1 1
373 AURORA, UT Distribution Unattended 46.00 12.47 3 1
374 BANGERTER, UT Distribution Unattended 138.00 13.20 63 2
375 BDO, UT Distribution Unattended 138.00 12.47 30 1
376 BEAR RIVER, UT Distribution Unattended 46.00 12.47 33 1
377 BENJAMIN, UT Distribution Unattended 46.00 12.47 4 1
378 BINGHAM, UT Distribution Unattended 46.00 13.20 25 1
379 BLACK MOUNTAIN, UT Distribution Unattended 46.00 7.20 1 1
380 BLUE CREEK, UT Distribution Unattended 46.00 12.47 2 3
381 BLUFF, UT Distribution Unattended 69.00 12.47 2 1
382 BLUFFDALE, UT Distribution Unattended 46.00 12.47 14 1
383 BOTHWELL, UT Distribution Unattended 46.00 12.47 4 1
384 BRIAN HEAD, UT Distribution Unattended 34.50 12.47 14 1
385 BRIGHTON, UT Distribution Unattended 46.00 24.90 29 2
386 BROOKLAWN, UT Distribution Unattended 46.00 12.47 6 1
387 BRUNSWICK, UT Distribution Unattended 46.00 12.47 42 2 1
388 BURTON, UT Distribution Unattended 34.50 12.47 11 3
389 BUSH, UT Distribution Unattended 46.00 12.47 14 1
390 CANNON, UT Distribution Unattended 46.00 12.47 7.20 13 1
391 CANYONLANDS, UT Distribution Unattended 69.00 12.47 1 1
392 CAPITOL, UT Distribution Unattended 46.00 12.47 20 1
393 CARBIDE, UT Distribution Unattended 69.00 12.47 3 1
394 CARBONVILLE, UT Distribution Unattended 46.00 12.47 6 1
395 CARLISLE, UT Distribution Unattended 138.00 12.47 30 1
396 CASTO, UT Distribution Unattended 46.00 12.47 28 1
397 CENTENNIAL, UT Distribution Unattended 138.00 12.47 40 2
398 CENTERVILLE, UT Distribution Unattended 46.00 12.47 22 1
399 CENTRAL, UT Distribution Unattended 46.00 12.47 9 1
400 CHAPEL HILL, UT Distribution Unattended 138.00 12.47 30 1
401 CHERRYWOOD, UT Distribution Unattended 138.00 12.47 55 2
402 CIRCLEVILLE, UT Distribution Unattended 69.00 12.47 3 1
403 CLEAR CREEK, UT Distribution Unattended 46.00 12.47 4 1
404 CLEAR LAKE, UT Distribution Unattended 46.00 12.47 0 3
405 CLEARFIELD SOUTH, UT Distribution Unattended 138.00 12.47 60 2
406 CLINTON, UT Distribution Unattended 138.00 12.47 50 2
407 CLIVE, UT Distribution Unattended 46.00 12.47 4 1
408 COALVILLE, UT Distribution Unattended 138.00 12.47 22 1
409 COLD WATER CANYON, UT Distribution Unattended 138.00 12.47 30 1
410 COLEMAN, UT Distribution Unattended 138.00 69.00 6.60 119 4
411 COLTON WELL, UT Distribution Unattended 46.00 2.40 1 3
412 COMMERCE, UT Distribution Unattended 138.00 12.47 30 1
413 COPPER HILLS, UT Distribution Unattended 138.00 13.20 63 2
414 CORRINE, UT Distribution Unattended 46.00 12.47 3 1
415 COVE FORT, UT Distribution Unattended 46.00 12.47 2 3
416 COZYDALE, UT Distribution Unattended 138.00 12.47 30 1
417 CRANER FLAT, UT Distribution Unattended 138.00 7.20 20 1 1
418 CROSS HOLLOW, UT Distribution Unattended 138.00 12.47 20 1 1
419 CROYDON, UT Distribution Unattended 138.00 46.00 12.47 81 2
420 CUDAHY, UT Distribution Unattended 138.00 12.47 30 1
421 DAMMERON VALLEY, UT Distribution Unattended 34.50 12.47 5 1
422 DECADE, UT Distribution Unattended 138.00 13.20 60 2
423 DECKER LAKE, UT Distribution Unattended 138.00 12.47 55 2
424 DELLE, UT Distribution Unattended 46.00 12.47 6 1
425 DELTA, UT Distribution Unattended 69.00 46.00 13.20 48 3
426 DEWEYVILLE, UT Distribution Unattended 46.00 12.47 14 1
427 DIMPLE DELL, UT Distribution Unattended 138.00 12.47 60 2
428 DRAPER, UT Distribution Unattended 138.00 13.20 60 2
429 DUMAS, UT Distribution Unattended 138.00 12.47 60 2
430 EAST BENCH, UT Distribution Unattended 138.00 12.47 30 1
431 EAST HYRUM, UT Distribution Unattended 46.00 12.47 6 1
432 EAST LAYTON, UT Distribution Unattended 138.00 12.47 30 1
433 EAST MILLCREEK, UT Distribution Unattended 46.00 12.47 20 1
434 EDEN, UT Distribution Unattended 46.00 12.47 19 2
435 ELBERTA, UT Distribution Unattended 46.00 12.47 5 1
436 ELK MEADOWS, UT Distribution Unattended 46.00 12.47 3 1
437 ELSINORE, UT Distribution Unattended 46.00 12.47 2 1
438 EMERY CITY, UT Distribution Unattended 69.00 12.47 3 3
439 EMIGRATION, UT Distribution Unattended 46.00 12.47 25 1
440 ENOCH, UT Distribution Unattended 138.00 12.47 14 1
441 ENTERPRISE VALLEY, UT Distribution Unattended 138.00 12.47 14 1
442 EUREKA, UT Distribution Unattended 46.00 12.47 3 1
443 FARMINGTON, UT Distribution Unattended 138.00 13.20 60 2
444 FAYETTE, UT Distribution Unattended 46.00 12.47 1 2
445 FERRON, UT Distribution Unattended 69.00 12.47 5 1
446 FIELDING, UT Distribution Unattended 46.00 12.47 6 1
447 FIFTH WEST, UT Distribution Unattended 138.00 13.20 60 2
448 FLUX, UT Distribution Unattended 46.00 12.47 4 1
449 FOOL CREEK, UT Distribution Unattended 46.00 12.47 4 1
450 FORT DOUGLAS, UT Distribution Unattended 138.00 13.20 40 1
451 FOUNTAIN GREEN, UT Distribution Unattended 46.00 12.47 7 1
452 FREEDOM, UT Distribution Unattended 46.00 7.20 0 1
453 FRUIT HEIGHTS, UT Distribution Unattended 46.00 12.47 22 1
454 GARDEN CITY, UT Distribution Unattended 69.00 12.47 13 1
455 GATEWAY, UT Distribution Unattended 69.00 12.47 14 1 2
456 GOLD RUSH, UT Distribution Unattended 138.00 13.20 30 1
457 GORDON AVENUE, UT Distribution Unattended 138.00 12.47 30 1
458 GOSHEN UTAH, UT Distribution Unattended 46.00 12.47 7 1
459 GRANGER, UT Distribution Unattended 46.00 12.47 50 2
460 GRANTSVILLE, UT Distribution Unattended 46.00 12.47 24 1
461 GRAVEL PIT, UT Distribution Unattended 46.00 12.47 3 1
462 GROW, UT Distribution Unattended 138.00 12.47 78 3
463 GUNNISON, UT Distribution Unattended 46.00 12.47 20 1
464 HAMMER, UT Distribution Unattended 138.00 12.47 60 2
465 HAVASU, UT Distribution Unattended 69.00 12.47 3 1
466 HELPER CITY, UT Distribution Unattended 46.00 4.16 3 3
467 HERRIMAN, UT Distribution Unattended 138.00 13.20 60 2
468 HIGHLAND, UT Distribution Unattended 138.00 46.00 12.47 97 2
469 HIGHLAND DISTRIBUTION, UT Distribution Unattended 46.00 12.47 25 1
470 HOGGARD, UT Distribution Unattended 138.00 12.47 50 2
471 HOLDEN, UT Distribution Unattended 46.00 12.47 4 1
472 HOLLADAY, UT Distribution Unattended 46.00 12.47 32 2
473 HONEYVILLE, UT Distribution Unattended 138.00 46.00 6.60 35 1
474 HUNTER, UT Distribution Unattended 46.00 12.47 22 1
475 HUNTINGTON CITY, UT Distribution Unattended 69.00 12.47 7 1
476 IRON MOUNTAIN, UT Distribution Unattended 34.50 12.47 1 3
477 IRONTON, UT Distribution Unattended 46.00 12.47 2 1
478 IVINS, UT Distribution Unattended 69.00 12.47 30 1 1
479 JORDAN NARROWS, UT Distribution Unattended 46.00 2.40 14 2
480 JORDAN PARK, UT Distribution Unattended 138.00 12.47 30 1
481 JORDANELLE, UT Distribution Unattended 138.00 12.47 30 1
482 JUAB, UT Distribution Unattended 46.00 12.47 4 1
483 JUDGE, UT Distribution Unattended 46.00 12.47 22 1
484 JUNCTION, UT Distribution Unattended 69.00 12.47 3 1
485 KAIBAB, UT Distribution Unattended 69.00 12.47 5 1
486 KAMAS, UT Distribution Unattended 46.00 12.47 11 1
487 KEARNS, UT Distribution Unattended 138.00 12.47 60 2
488 KENSINGTON, UT Distribution Unattended 46.00 4.16 7 1
489 KYUNE, UT Distribution Unattended 46.00 7.20 0 1
490 LAKE PARK, UT Distribution Unattended 138.00 12.47 53 2
491 LAYTON, UT Distribution Unattended 46.00 12.47 40 2
492 LEE CREEK, UT Distribution Unattended 138.00 13.20 30 1
493 LEGRANDE, UT Distribution Unattended 46.00 12.47 2 1
494 LEWISTON, UT Distribution Unattended 46.00 7.20 22 1
495 LINCOLN, UT Distribution Unattended 46.00 12.47 20 1
496 LINDON, UT Distribution Unattended 46.00 12.47 25 1
497 LISBON, UT Distribution Unattended 69.00 12.47 3 1
498 LOAFER, UT Distribution Unattended 46.00 7.20 0 1
499 LOGAN CANYON, UT Distribution Unattended 46.00 7.20 1 1
500 LONE TREE, UT Distribution Unattended 34.50 12.47 20 1
501 LOWER BEAVER, UT Distribution Unattended 46.00 13.20 0 1
502 LYNNDYL, UT Distribution Unattended 46.00 12.47 4 1
503 MAESER, UT Distribution Unattended 69.00 12.47 20 1
504 MAGNA, UT Distribution Unattended 138.00 12.47 60 2
505 MANILA, UT Distribution Unattended 138.00 12.47 30 1
506 MANTUA, UT Distribution Unattended 46.00 12.47 3 1
507 MAPLETON, UT Distribution Unattended 46.00 12.47 25 1
508 MARRIOTT, UT Distribution Unattended 46.00 12.47 20 1
509 MARYSVALE, UT Distribution Unattended 46.00 12.47 3 1
510 MATHIS, UT Distribution Unattended 46.00 12.47 9 1
511 MAYFLOWER, UT Distribution Unattended 138.00 13.20 33 1
512 MCCORNICK, UT Distribution Unattended 46.00 12.47 6 1
513 MCKAY, UT Distribution Unattended 46.00 12.47 28 1
514 MEADOWBROOK, UT Distribution Unattended 138.00 12.47 42 2
515 MEDICAL, UT Distribution Unattended 46.00 12.47 56 3
516 MIDLAND, UT Distribution Unattended 138.00 12.47 30 1
517 MIDVALE, UT Distribution Unattended 46.00 12.47 25 1
518 MILFORD, UT Distribution Unattended 138.00 46.00 13.20 89 2
519 MILFORD TV, UT Distribution Unattended 46.00 13.20 0 1
520 MINERSVILLE, UT Distribution Unattended 46.00 12.47 2 1
521 MOAB CITY, UT Distribution Unattended 69.00 12.47 19 2 1
522 MOORE, UT Distribution Unattended 69.00 12.47 3 1
523 MORGAN, UT Distribution Unattended 46.00 12.47 5 1
524 MORONI, UT Distribution Unattended 46.00 12.47 6 1
525 MORTON COURT, UT Distribution Unattended 138.00 12.47 65 2
526 MOUNTAIN DELL, UT Distribution Unattended 46.00 12.47 5 1
527 MOUNTAIN GREEN, UT Distribution Unattended 46.00 12.47 9 1
528 MYTON, UT Distribution Unattended 69.00 12.47 6 1
529 NAPLES, UT Distribution Unattended 138.00 13.20 30 1
530 NEW HARMONY, UT Distribution Unattended 69.00 12.47 7 1
531 NEWGATE, UT Distribution Unattended 46.00 12.47 16 1
532 NEWTON, UT Distribution Unattended 46.00 12.47 5 1
533 NIBLEY, UT Distribution Unattended 138.00 24.90 70 2
534 NORTH BENCH, UT Distribution Unattended 46.00 12.47 25 1
535 NORTH FIELDS, UT Distribution Unattended 46.00 12.47 3 1
536 NORTH LOGAN, UT Distribution Unattended 46.00 12.47 25 1
537 NORTH OGDEN, UT Distribution Unattended 46.00 12.47 22 1
538 NORTH SALT LAKE, UT Distribution Unattended 46.00 13.20 25 1
539 NORTHEAST, UT Distribution Unattended 46.00 12.47 45 2
540 NORTHRIDGE, UT Distribution Unattended 46.00 12.47 14 1
541 OAKLAND AVENUE, UT Distribution Unattended 46.00 12.47 22 1
542 OAKLEY, UT Distribution Unattended 46.00 12.47 6 1
543 OLYMPUS, UT Distribution Unattended 46.00 12.47 22 1
544 OPHIR, UT Distribution Unattended 46.00 12.47 3 1
545 ORANGE, UT Distribution Unattended 46.00 12.47 33 1
546 ORANGEVILLE, UT Distribution Unattended 69.00 12.47 14 1
547 OREM, UT Distribution Unattended 46.00 12.47 48 2
548 PANGUITCH, UT Distribution Unattended 69.00 12.47 5 1
549 PARIETTE, UT Distribution Unattended 69.00 24.90 14 1
550 PARK CITY, UT Distribution Unattended 46.00 12.47 42 2
551 PARKSIDE, UT Distribution Unattended 138.00 12.47 60 2
552 PARKWAY, UT Distribution Unattended 138.00 12.47 50 2
553 PARLEYS, UT Distribution Unattended 46.00 12.47 16 2
554 PELICAN POINT, UT Distribution Unattended 46.00 12.47 6 1
555 PETERSON, UT Distribution Unattended 46.00 12.47 30 1
556 PINE CANYON, UT Distribution Unattended 138.00 12.47 55 2
557 PINE CREEK, UT Distribution Unattended 46.00 12.47 6 1
558 PINNACLE, UT Distribution Unattended 46.00 12.47 14 1
559 PLAIN CITY, UT Distribution Unattended 138.00 12.47 22 1
560 PLEASANT GROVE, UT Distribution Unattended 138.00 12.47 30 1
561 PLEASANT VIEW, UT Distribution Unattended 46.00 12.47 14 1
562 PONY EXPRESS, UT Distribution Unattended 138.00 12.47 60 2
563 PORTER ROCKWELL, UT Distribution Unattended 138.00 13.20 60 2
564 PROMONTORY, UT Distribution Unattended 46.00 12.47 2 1
565 QUAIL CREEK, UT Distribution Unattended 69.00 12.47 14 1
566 QUARRY, UT Distribution Unattended 138.00 12.47 60 2
567 QUICHAPA, UT Distribution Unattended 34.50 12.47 7.20 14 1
568 RAINS, UT Distribution Unattended 46.00 7.20 0 1
569 RANDOLPH, UT Distribution Unattended 46.00 12.47 2 1
570 RASMUSON, UT Distribution Unattended 46.00 12.47 2 1 1
571 RATTLESNAKE, UT Distribution Unattended 69.00 24.90 14 1
572 REDWOOD, UT Distribution Unattended 46.00 12.47 45 2
573 RESEARCH PARK, UT Distribution Unattended 46.00 12.47 45 2
574 RICH, UT Distribution Unattended 69.00 12.47 5 1
575 RICHFIELD, UT Distribution Unattended 46.00 12.47 35 2
576 RICHMOND, UT Distribution Unattended 46.00 12.47 11 1
577 RIDGELAND, UT Distribution Unattended 138.00 12.47 40 2
578 RITER, UT Distribution Unattended 46.00 12.47 20 1
579 RIVERDALE, UT Distribution Unattended 138.00 46.00 6.60 180 3
580 ROCK CANYON, UT Distribution Unattended 69.00 12.47 5 1
581 ROCKVILLE, UT Distribution Unattended 34.50 12.47 4 1
582 ROCKY POINT, UT Distribution Unattended 138.00 12.47 30 1
583 ROSE PARK, UT Distribution Unattended 46.00 12.47 42 2
584 ROYAL, UT Distribution Unattended 46.00 4.16 0 3
585 SALINA, UT Distribution Unattended 46.00 12.47 11 1
586 SANDY, UT Distribution Unattended 138.00 12.47 60 2
587 SARATOGA, UT Distribution Unattended 138.00 13.20 60 2
588 SCHOO MINE, UT Distribution Unattended 46.00 12.47 9 1
589 SCOFIELD, UT Distribution Unattended 46.00 12.47 1 3
590 SCOFIELD RESERVOIR, UT Distribution Unattended 46.00 7.20 1 1
591 SEGO CANYON, UT Distribution Unattended 69.00 12.47 14 1
592 SEVEN MILE, UT Distribution Unattended 69.00 12.47 5 1 1
593 SHARON, UT Distribution Unattended 46.00 12.47 20 1
594 SHORELINE, UT Distribution Unattended 138.00 13.20 60 2
595 SIXTH SOUTH, UT Distribution Unattended 46.00 12.47 20 1
596 SKULL VALLEY, UT Distribution Unattended 46.00 12.47 2 1
597 SKYPARK, UT Distribution Unattended 138.00 13.20 73 2
598 SMITHFIELD, UT Distribution Unattended 138.00 46.00 6.60 63 2
599 SNARR, UT Distribution Unattended 46.00 12.47 53 2
600 SNOWVILLE, UT Distribution Unattended 69.00 12.47 5 1
601 SNYDERVILLE, UT Distribution Unattended 138.00 46.00 13.80 127 3
602 SOLDIER SUMMIT, UT Distribution Unattended 46.00 12.47 2 1
603 SOUTH JORDAN, UT Distribution Unattended 138.00 12.47 60 2
604 SOUTH MILFORD, UT Distribution Unattended 46.00 24.90 28 2
605 SOUTH MOUNTAIN, UT Distribution Unattended 138.00 12.47 60 2
606 SOUTH OGDEN, UT Distribution Unattended 46.00 12.47 25 1
607 SOUTH PARK, UT Distribution Unattended 138.00 12.47 30 1
608 SOUTH WEBER, UT Distribution Unattended 138.00 12.47 22 1
609 SOUTHEAST, UT Distribution Unattended 138.00 12.47 60 2
610 SOUTHWEST, UT Distribution Unattended 46.00 12.47 22 2
611 SPANISH VALLEY, UT Distribution Unattended 69.00 12.47 14 1
612 SPRINGDALE, UT Distribution Unattended 34.50 12.47 14 1
613 ST JOHN, UT Distribution Unattended 46.00 12.47 8 1
614 STANSBURY, UT Distribution Unattended 138.00 12.47 33 1
615 SUMMIT CREEK, UT Distribution Unattended 138.00 13.80 30 1
616 SUMMIT PARK, UT Distribution Unattended 46.00 12.47 7 1
617 SUNRISE, UT Distribution Unattended 138.00 12.47 60 2
618 SUTHERLAND, UT Distribution Unattended 46.00 24.90 14 1
619 TAMARISK, UT Distribution Unattended 138.00 12.47 20 1
620 TAYLOR, UT Distribution Unattended 46.00 12.47 14 1
621 THIEF CREEK, UT Distribution Unattended 138.00 24.90 14 1
622 THIRD WEST, UT Distribution Unattended 138.00 13.20 100 2
623 THIRTEENTH SOUTH, UT Distribution Unattended 46.00 12.47 22 1
624 TOOELE DEPOT, UT Distribution Unattended 46.00 12.47 25 1
625 TOQUERVILLE, UT Distribution Unattended 69.00 34.50 34 2
626 TRI-CITY, UT Distribution Unattended 138.00 12.47 30 1 2
627 UINTAH, UT Distribution Unattended 46.00 12.47 39 2
628 UNION, UT Distribution Unattended 46.00 12.47 50 2
629 VALLEY CENTER, UT Distribution Unattended 46.00 12.47 22 1
630 VERMILLION, UT Distribution Unattended 46.00 12.47 3 1
631 VERNAL, UT Distribution Unattended 69.00 12.47 33 2
632 VICKERS, UT Distribution Unattended 46.00 12.47 4 1
633 VINEYARD, UT Distribution Unattended 138.00 13.20 30 1
634 WALLSBURG, UT Distribution Unattended 138.00 12.47 13 1
635 WALNUT GROVE, UT Distribution Unattended 138.00 12.47 30 1
636 WARREN, UT Distribution Unattended 138.00 12.47 30 1
637 WASATCH STATE PARK, UT Distribution Unattended 46.00 12.47 2 3
638 WASHAKIE, UT Distribution Unattended 138.00 4.16 14 1
639 WELBY, UT Distribution Unattended 46.00 12.47 42 2
640 WELFARE, UT Distribution Unattended 46.00 12.47 11 1
641 WEST COMMERCIAL, UT Distribution Unattended 46.00 12.47 22 1
642 WEST JORDAN, UT Distribution Unattended 138.00 12.47 28 1
643 WEST OGDEN, UT Distribution Unattended 138.00 12.47 60 2
644 WEST POINT, UT Distribution Unattended 138.00 13.20 40 1
645 WEST ROY, UT Distribution Unattended 46.00 12.47 25 1
646 WEST TEMPLE, UT Distribution Unattended 46.00 7.20 53 3
647 WESTFIELD, UT Distribution Unattended 138.00 12.47 20 1
648 WESTWATER, UT Distribution Unattended 69.00 12.47 5 1
649 WHITE ROCK, UT Distribution Unattended 138.00 13.20 30 1
650 WILLOWCREEK, UT Distribution Unattended 46.00 12.47 1 1
651 WILLOWRIDGE, UT Distribution Unattended 46.00 12.47 25 1
652 WINCHESTER HILLS, UT Distribution Unattended 34.50 12.47 4 1
653 WINKLEMAN, UT Distribution Unattended 46.00 7.20 0 1
654 WOLF CREEK, UT Distribution Unattended 69.00 12.47 4.16 6 1
655 WOODRUFF, UT Distribution Unattended 46.00 12.47 2 1
656 WOODS CROSS, UT Distribution Unattended 46.00 12.47 20 1
657 CUTLER, UT Transmission Attended 138.00 46.00 6.60 50 1
658 EMERY, UT Transmission Attended 345.00 138.00 12.47 411 3
659 GADSBY, UT Transmission Attended 138.00 46.00 13.80 168 1
660 90TH SOUTH, UT Transmission Unattended 345.00 138.00 12.47 1604 6
661 ABAJO, UT Transmission Unattended 138.00 69.00 13.80 67 2
662 ASHLEY, UT Transmission Unattended 138.00 69.00 12.47 134 2
663 BEN LOMOND, UT Transmission Unattended 345.00 230.00 13.80 2202 6
664 BLACK ROCK, UT Transmission Unattended 230.00 69.00 13.20 75 1
665 BLACKHAWK, UT Transmission Unattended 138.00 69.00 7.20 100 2
666 BUTLERVILLE, UT Transmission Unattended 138.00 46.00 13.80 205 4
667 CAMERON, UT Transmission Unattended 138.00 46.00 12.47 100 4
668 CAMP WILLIAMS, UT Transmission Unattended 345.00 138.00 13.20 200 2
669 CLOVER, UT Transmission Unattended 345.00 138.00 24.90 400 1
670 COLUMBIA, UT Transmission Unattended 138.00 46.00 6.60 71 2
671 COTTONWOOD, UT Transmission Unattended 138.00 46.00 12.47 301 6 1
672 EL MONTE, UT Transmission Unattended 138.00 46.00 12.47 313 3
673 EMMA PARK, UT Transmission Unattended 138.00 12.47 8 1
674 GARKANE, UT Transmission Unattended 69.00 46.00 2.40 33 1
675 GREEN CANYON, UT Transmission Unattended 138.00 46.00 6.60 67 2
676 HALE, UT Transmission Unattended 138.00 46.00 12.47 114 2
677 HELPER, UT Transmission Unattended 138.00 46.00 12.47 77 2
678 HORSESHOE, UT Transmission Unattended 138.00 46.00 6.60 80 2
679 HUNTINGTON, UT Transmission Unattended 345.00 138.00 12.47 270 4
680 JERUSALEM, UT Transmission Unattended 138.00 46.00 6.60 67 1
681 JORDAN, UT Transmission Unattended 138.00 46.00 12.47 195 4
682 LAMPO, UT Transmission Unattended 138.00 46.00 12.47 75 1
683 MATHINGTON, UT Transmission Unattended 138.00 46.00 13.20 75 1
684 MCCLELLAND, UT Transmission Unattended 138.00 46.00 13.80 340 3
685 MCFADDEN, UT Transmission Unattended 138.00 69.00 13.80 45 1
686 MIDDLETON, UT Transmission Unattended 138.00 69.00 6.60 137 3
687 MIDVALLEY, UT Transmission Unattended 345.00 138.00 13.80 1150 2
688 MIDWAY CITY, UT Transmission Unattended 138.00 46.00 12.47 67 1
689 MINERAL PRODUCTS, UT Transmission Unattended 69.00 46.00 6.60 13 1
690 MOAB, UT Transmission Unattended 138.00 69.00 6.60 67 1
691 NEBO, UT Transmission Unattended 138.00 46.00 6.60 67 1
692 OQUIRRH, UT Transmission Unattended 345.00 138.00 13.80 835 4
693 PAROWAN VALLEY, UT Transmission Unattended 230.00 138.00 13.80 138 2
694 PARRISH, UT Transmission Unattended 138.00 46.00 13.80 97 2
695 PAVANT, UT Transmission Unattended 230.00 46.00 13.80 133 2
696 PINTO, UT Transmission Unattended 345.00 138.00 13.80 257 (t)3
697 PURGATORY FLAT, UT Transmission Unattended 138.00 69.00 12.47 300 2
698 RED BUTTE, UT Transmission Unattended 345.00 138.00 24.90 414 2
699 SCIPIO, UT Transmission Unattended 46.00 12.47 2 3
700 SEVIER, UT Transmission Unattended 138.00 46.00 6.60 38 2
701 SIGURD, UT Transmission Unattended 345.00 230.00 13.80 1075 (u)6
702 SILVER CREEK, UT Transmission Unattended 138.00 46.00 13.80 100 2
703 SPANISH FORK, UT Transmission Unattended 345.00 138.00 13.80 1400 2 1
704 SYRACUSE, UT Transmission Unattended 345.00 138.00 13.80 1300 6
705 TAYLORSVILLE, UT Transmission Unattended 138.00 46.00 12.47 358 4
706 TERMINAL, UT Transmission Unattended 345.00 138.00 12.47 1624 6
707 THREE PEAKS, UT Transmission Unattended 345.00 138.00 12.47 450 1
708 TIMP, UT Transmission Unattended 138.00 46.00 7.20 130 2
709 TOOELE, UT Transmission Unattended 138.00 46.00 13.20 249 3
710 WEST CEDAR, UT Transmission Unattended 230.00 138.00 12.47 147 2
711 ATTALIA, WA Distribution Unattended 69.00 12.47 25 1
712 BOWMAN, WA Distribution Unattended 69.00 12.47 45 2
713 CASCADE KRAFT, WA Distribution Unattended 69.00 12.47 151 7
714 CENTRAL, WA Distribution Unattended 69.00 12.47 14 1
715 CLINTON, WA Distribution Unattended 115.00 12.47 25 1
716 DAYTON, WA Distribution Unattended 69.00 12.47 23 2
717 DODD ROAD, WA Distribution Unattended 69.00 20.80 25 4
718 FLINT SUBSTATION, WA Distribution Unattended 115.00 13.20 30 1
719 GRANDVIEW, WA Distribution Unattended 115.00 69.00 12.47 58 2
720 GROMORE, WA Distribution Unattended 115.00 12.47 25 1
721 HOPLAND, WA Distribution Unattended 115.00 12.47 50 2
722 MILL CREEK, WA Distribution Unattended 69.00 12.47 45 2
723 NACHES, WA Distribution Unattended 115.00 12.47 25 1
724 NOB HILL, WA Distribution Unattended 115.00 12.47 42 2
725 NORTH PARK, WA Distribution Unattended 115.00 12.47 45 2
726 ORCHARD, WA Distribution Unattended 115.00 12.47 50 2
727 PACIFIC, WA Distribution Unattended 115.00 12.47 28 3
728 POMEROY, WA Distribution Unattended 69.00 12.47 9 1
729 POMONA HEIGHTS, WA Distribution Unattended 230.00 115.00 12.47 325 3
730 PROSPECT POINT, WA Distribution Unattended 69.00 12.47 40 2
731 PUNKIN CENTER, WA Distribution Unattended 115.00 13.20 44 3
732 RIVER ROAD, WA Distribution Unattended 115.00 12.47 76 5
733 SELAH, WA Distribution Unattended 115.00 12.47 45 2
734 SULPHUR CREEK, WA Distribution Unattended 115.00 12.47 25 1
735 SUNNYSIDE, WA Distribution Unattended 115.00 12.47 45 2
736 TIETON, WA Distribution Unattended 115.00 34.50 29 2 1
737 TOPPENISH, WA Distribution Unattended 115.00 12.47 50 2
738 TOUCHET, WA Distribution Unattended 69.00 12.47 13 1
739 VOELKER, WA Distribution Unattended 115.00 12.47 25 1
740 WAITSBURG, WA Distribution Unattended 69.00 12.47 9 1
741 WAPATO, WA Distribution Unattended 115.00 12.47 45 2
742 WENAS, WA Distribution Unattended 115.00 12.47 25 2
743 WHITE SWAN, WA Distribution Unattended 115.00 12.47 22 2
744 WILEY, WA Distribution Unattended 115.00 12.47 45 2
745 (o)
DRY GULCH, WA Transmission Unattended 115.00 69.00 50 1
746 OUTLOOK, WA Transmission Unattended 230.00 115.00 12.47 250 1
747 PASCO, WA Transmission Unattended 115.00 69.00 7.20 39 9
748 UNION GAP, WA Transmission Unattended 230.00 115.00 13.20 595 5
749 (p)
WALLA WALLA, WA Transmission Unattended 230.00 69.00 300 3
750 WALLULA, WA Transmission Unattended 230.00 69.00 120 2 1
751 WINE COUNTRY, WA Transmission Unattended 230.00 115.00 250 1
752 ANTELOPE MINE, WY Distribution Unattended 230.00 34.50 13.20 25 1
753 ARROWHEAD, WY Distribution Unattended 230.00 34.50 13.20 150 2
754 ASTLE STREET, WY Distribution Unattended 34.50 13.20 13 1
755 BAILEY DOME, WY Distribution Unattended 57.00 4.16 2 1
756 BAIROIL, WY Distribution Unattended 115.00 69.00 13.20 53 3
757 BAR X, WY Distribution Unattended 230.00 34.50 13.20 25 1
758 BARR NUNN, WY Distribution Unattended 115.00 12.47 30 1
759 BATTLE SPRINGS, WY Distribution Unattended 34.50 13.80 2 1
760 BELLAMY 2, WY Distribution Unattended 69.00 4.16 5 1
761 BIG MUDDY, WY Distribution Unattended 69.00 12.47 7 1
762 BIG PINEY, WY Distribution Unattended 69.00 24.90 14 1
763 BLACKS FORK, WY Distribution Unattended 230.00 34.50 13.20 225 3 1
764 BRIDGER PUMP, WY Distribution Unattended 230.00 34.50 7.20 74 4
765 BRYAN, WY Distribution Unattended 115.00 12.47 25 1
766 BUFFALO, WY Distribution Unattended 230.00 20.80 20 1 1
767 BYRON, WY Distribution Unattended 34.50 4.16 2 3
768 CASSA, WY Distribution Unattended 57.00 20.80 2 6
769 CENTER STREET, WY Distribution Unattended 115.00 12.47 13 1
770 CHAPMAN, WY Distribution Unattended 46.00 12.47 4 1
771 CHUKAR, WY Distribution Unattended 12.47 4.16 1 1
772 COKEVILLE, WY Distribution Unattended 46.00 24.90 8 1
773 COLUMBIA GENEVA, WY Distribution Unattended 230.00 12.47 45 2
774 COMMUNITY PARK, WY Distribution Unattended 115.00 12.47 50 2
775 CROOKS GAP, WY Distribution Unattended 34.50 12.47 6 1
776 DEAVER, WY Distribution Unattended 34.50 4.16 0 3
777 DEER CREEK, WY Distribution Unattended 69.00 12.47 9 1
778 DJ COAL MINE, WY Distribution Unattended 69.00 34.50 13 1
779 DRY FORK, WY Distribution Unattended 69.00 4.16 9 1
780 ELK BASIN, WY Distribution Unattended 34.50 7.20 5 1
781 ELK HORN, WY Distribution Unattended 115.00 12.47 25 1
782 EMIGRANT, WY Distribution Unattended 115.00 12.47 13 1
783 EVANS, WY Distribution Unattended 115.00 12.47 9 1
784 EVANSTON, WY Distribution Unattended 138.00 12.47 40 2
785 FIREHOLE, WY Distribution Unattended 230.00 34.50 13.20 50 2
786 FORT CASPER, WY Distribution Unattended 69.00 12.47 28 1
787 FORT SANDERS, WY Distribution Unattended 115.00 13.20 20 1
788 FRANNIE, WY Distribution Unattended 230.00 34.50 2.40 50 2
789 FRONTIER, WY Distribution Unattended 69.00 4.16 6 1
790 GARLAND, WY Distribution Unattended 230.00 34.50 13.20 45 2
791 GRASS CREEK, WY Distribution Unattended 230.00 34.50 13.20 25 1
792 GREAT DIVIDE, WY Distribution Unattended 115.00 34.50 20 1
793 GREEN MOUNTAIN, WY Distribution Unattended 34.50 4.16 5 1
794 GREYBULL, WY Distribution Unattended 34.50 4.16 3 1
795 HANNA, WY Distribution Unattended 34.50 13.20 6 1
796 HILLTOP, WY Distribution Unattended 115.00 34.50 13.20 45 2 1
797 HOLLY SUGAR, WY Distribution Unattended 34.50 4.16 5 1
798 JACKALOPE, WY Distribution Unattended 115.00 13.20 55 2
799 KEMMERER, WY Distribution Unattended 69.00 24.90 14 1
800 KIRBY CREEK, WY Distribution Unattended 34.50 4.16 2 3
801 KIRBY CREEK PUMPING, WY Distribution Unattended 34.50 2.40 2 3
802 LABARGE, WY Distribution Unattended 69.00 24.90 8 6 1
803 LANDER, WY Distribution Unattended 34.50 12.47 13 1
804 LARAMIE, WY Distribution Unattended 115.00 13.20 50 2
805 LATHAM, WY Distribution Unattended 230.00 46.00 7.20 575 3
806 LINCH, WY Distribution Unattended 69.00 13.80 12 1
807 LITTLE MOUNTAIN, WY Distribution Unattended 230.00 34.50 20 1
808 LOVELL, WY Distribution Unattended 34.50 4.16 4 1
809 MANSFACE, WY Distribution Unattended 230.00 34.50 2.40 20 1
810 MILL IRON, WY Distribution Unattended 34.50 13.80 12 1
811 MILLS, WY Distribution Unattended 12.47 4.16 2 3
812 MINERS, WY Distribution Unattended 230.00 34.50 7.20 20 1
813 MOUNTAIN GAS, WY Distribution Unattended 34.50 12.47 4.16 3 1
814 MURPHY DOME, WY Distribution Unattended 34.50 12.47 13 1
815 NAUGHTON CONSTRUCTION, WY Distribution Unattended 69.00 12.47 2 3
816 NUGGETT, WY Distribution Unattended 69.00 7.20 0 1
817 OPAL, WY Distribution Unattended 69.00 24.90 8 1
818 OREGON BASIN, WY Distribution Unattended 230.00 69.00 13.20 100 2
819 ORIN, WY Distribution Unattended 57.00 7.20 1 1 1
820 OWL CREEK PUMP #1, WY Distribution Unattended 34.50 4.16 2 3
821 PARADISE, WY Distribution Unattended 69.00 24.90 30 1
822 PARCO, WY Distribution Unattended 34.50 13.20 3 1
823 PHILLIPS GAS PLANT PIPELINE, WY Distribution Unattended 12.47 2.40 1 3
824 PINEDALE, WY Distribution Unattended 69.00 24.90 20 1
825 PITCHFORK, WY Distribution Unattended 69.00 24.90 11 3 1
826 PLATTE, WY Distribution Unattended 230.00 115.00 13.20 140 3
827 PLATTE PIPE BYRON, WY Distribution Unattended 34.50 4.16 2 3
828 PLATTE PIPE OREGON BASIN, WY Distribution Unattended 34.50 4.16 2 3
829 PLATTE RIVER DJ, WY Distribution Unattended 69.00 12.47 2 3
830 POINT OF ROCKS, WY Distribution Unattended 230.00 34.50 13.20 25 1
831 POISON SPIDER, WY Distribution Unattended 69.00 2.40 3 1
832 RAINBOW, WY Distribution Unattended 34.50 13.20 13 1
833 RAVEN, WY Distribution Unattended 230.00 34.50 12.47 200 2
834 RED BUTTE, WY Distribution Unattended 115.00 13.20 30 1
835 REFINERY, WY Distribution Unattended 115.00 12.47 45 2
836 RIVERTON, WY Distribution Unattended 230.00 34.50 13.20 77 4
837 ROCK SPRINGS 230, WY Distribution Unattended 230.00 34.50 13.20 50 2 2
838 SAGE HILL, WY Distribution Unattended 34.50 13.20 9 1
839 SHOSHONI, WY Distribution Unattended 34.50 2.40 2 3
840 SINCLAIR PIPELINE, WY Distribution Unattended 34.50 4.16 5 1
841 SLATE CREEK, WY Distribution Unattended 69.00 13.80 1 1
842 SOUTH CODY, WY Distribution Unattended 69.00 24.90 14 3 1
843 SOUTH ELK BASIN, WY Distribution Unattended 34.50 4.16 2 6
844 SOUTH TRONA, WY Distribution Unattended 230.00 34.50 13.20 150 2
845 SPRING CREEK, WY Distribution Unattended 115.00 13.20 28 1
846 SVILAR, WY Distribution Unattended 34.50 4.16 2 3
847 TEN MILE, WY Distribution Unattended 69.00 12.47 5 1
848 THERMOPOLIS TOWN, WY Distribution Unattended 34.50 4.16 5 1
849 THERMOPOLIS(WAPA), WY Distribution Unattended 115.00 34.50 25 1
850 THUNDER CREEK, WY Distribution Unattended 69.00 12.47 14 1
851 VETERANS, WY Distribution Unattended 34.50 13.20 25 2
852 WAMSUTTER AMOCO, WY Distribution Unattended 34.50 4.16 2 3
853 WARM SPRINGS SPL, WY Distribution Unattended 115.00 4.16 9 1
854 WERTZ SINCLAIR, WY Distribution Unattended 57.00 4.16 3 6
855 WEST ADAMS, WY Distribution Unattended 34.50 4.16 3 1
856 WESTVACO, WY Distribution Unattended 230.00 34.50 25 1
857 WHISKEY GULCH, WY Distribution Unattended 57.00 12.47 9 1
858 WORLAND TOWN, WY Distribution Unattended 34.50 4.16 4 1
859 WYCO BEAR CREEK, WY Distribution Unattended 20.80 2.40 1 3
860 WYCO STROUD, WY Distribution Unattended 13.20 4.16 2 3
861 WYOPO, WY Distribution Unattended 230.00 34.50 20 1 1
862 YELLOWCAKE, WY Distribution Unattended 230.00 34.50 13.20 100 2
863 (q)
DAVE JOHNSTON, WY Transmission Attended 230.00 115.00 13.20 269 3 1
864 (r)
JIM BRIDGER, WY Transmission Attended 345.00 230.00 34.50 850 6 1
865 NAUGHTON, WY Transmission Attended 230.00 138.00 13.80 661 4
866 AEOLUS, WY Transmission Unattended 500.00 230.00 34.50 1600 3
867 ANTICLINE, WY Transmission Unattended 500.00 345.00 34.50 1600 3 1
868 CASPER, WY Transmission Unattended 230.00 115.00 13.80 575 4
869 CHAPPEL CREEK, WY Transmission Unattended 230.00 69.00 12.47 75 1
870 CHIMNEY BUTTE, WY Transmission Unattended 230.00 69.00 12.47 75 1
871 FOOTE CREEK, WY Transmission Unattended 230.00 34.50 12.47 196 2
872 GLENDO AUTO, WY Transmission Unattended 69.00 57.00 8 1 1
873 MIDWEST, WY Transmission Unattended 230.00 69.00 13.20 158 3
874 MUSTANG, WY Transmission Unattended 230.00 115.00 13.20 100 1
875 RAILROAD, WY Transmission Unattended 230.00 138.00 24.90 448 2
876 SAGE, WY Transmission Unattended 69.00 46.00 2.40 22 1
877 STANDPIPE, WY Transmission Unattended 230.00 12.47 75
878 THERMOPOLIS, WY Transmission Unattended 230.00 115.00 12.47 84 1
879 TotalDistributionSubstationAttendedMember 133
880 TotalDistributionSubstationUnttendedMember 20,008
881 TotalTransmissionSubstationAttendedMember 2,964
882 TotalTransmissionSubstationUnattendedMember 39,833
883 Total 62,938 0
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: SubstationNameAndLocation
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. 100% of the capacity is
reported.
(b) Concept: SubstationNameAndLocation
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. 100% of the capacity is
reported.
(c) Concept: SubstationNameAndLocation
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. 100% of the capacity is
reported.
(d) Concept: SubstationNameAndLocation
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. 100% of the capacity is
reported.
(e) Concept: SubstationNameAndLocation
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. 100% of the capacity is
reported.
(f) Concept: SubstationNameAndLocation
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. 100% of the capacity is
reported.
(g) Concept: SubstationNameAndLocation
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. 100% of the capacity is reported.
(h) Concept: SubstationNameAndLocation
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. 100% of the capacity is reported.
(i) Concept: SubstationNameAndLocation
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%. 100% of the capacity is reported.
(j) Concept: SubstationNameAndLocation
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. 100% of the capacity is
reported.
(k) Concept: SubstationNameAndLocation
Substation is jointly owned by PacifiCorp, Bonneville Power Administration and Portland General Electric Company. Ownership and operations and maintenance costs vary by type of asset as defined in the operations and
maintenance agreement. 100% of the capacity is reported.
(l) Concept: SubstationNameAndLocation
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%. 100% of the capacity is reported.
(m) Concept: SubstationNameAndLocation
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.
100% of the capacity is reported.
(n) Concept: SubstationNameAndLocation
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.
100% of the capacity is reported.
(o) Concept: SubstationNameAndLocation
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. 100% of
the capacity is reported.
(p) Concept: SubstationNameAndLocation
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. 100% of the capacity is
reported.
(q) Concept: SubstationNameAndLocation
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. 100% of the capacity is reported.
(r) Concept: SubstationNameAndLocation
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. 100% of the capacity is
reported.
(s) Concept: NumberOfTransformersInService
Includes one 3-phase transformer
(t) Concept: NumberOfTransformersInService
Represents three phase shifters at the substation, which does not change the voltage and reports a 3-phase bank as three transformers.
(u) Concept: NumberOfTransformersInService
Includes one 3-phase transformer
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
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 to an associated/affiliated company for non-power goods and services. The
good or service must be specific in nature. Respondents should not attempt 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.
Line
No.
Description of the Good or Service
(a)
Name of Associated/Affiliated Company
(b)
Account(s) Charged or
Credited
(c)
Amount Charged or Credited
(d)
1 Non-power Goods or Services Provided by Affiliated
2 Coal purchases Bridger Coal Company 151, 501 135,796,074
3 Coal purchases Trapper Mining Inc.151, 501 25,655,112
4 Interest expense Pacific Minerals, Inc.430 1,146,989
5 (a)
Administrative services under the IASA Berkshire Hathaway Energy Company
107, 165, 184, 426.4,
426.5, 903, 920, 921,
923, 924, 925, 930.2,
935
153,604,260
6 Employee relocation services HomeServices of America, Inc.
501, 506, 539, 549, 557,
561.2, 580, 590, 592,
593, 921
428,445
7 Administrative services under the IASA Kern River Gas Transmission Company 107, 923 50,176
8 Gas transportation services Kern River Gas Transmission Company 547 3,114,296
9 Administrative services under the IASA MidAmerican Energy Company
107, 165, 426.4, 426.5,
557, 920, 921, 923, 925,
930.2, 935
12,707,196
10 Equipment purchase MidAmerican Energy Company 394 275,716
11 Administrative services under the IASA Nevada Power Company 107, 923 1,137,168
12 Operational support services Nevada Power Company 570, 107 665,076
13 Administrative services under the IASA Northern Natural Gas 107, 923 675,585
14 Banking services Bank of America Corporation 427, 431, 557 297,547
15 Underwriting services BofA Securities, Inc.181 675,000
16 Rail services and right-of-way fees BNSF Railway Company 151, 501, 507, 567, 571,
589, 593 (b)23,908,886
17 Materials and supplies Marmon Utility LLC 107 17,022,890
18 Rating agency fees Moody's Investors Service, Inc.186 1,406,000
19 Travel services NetJets, Inc.426.5, 923 410,792
19
20 Non-power Goods or Services Provided for Affiliated
21 Information technology and administrative support services Bridger Coal Company 501, 557, 925, 931 2,342,670
22 Administrative services under the IASA Berkshire Hathaway Energy Company
506, 535, 557, 560, 580,
588, 590, 597, 901, 903,
908, 922, 923, 929
24,727,078
23 Administrative services under the IASA BHE AltaLink Ltd.557, 580, 922, 929 313,089
24 Administrative services under the IASA BHE Renewables, LLC 535, 557, 560, 580, 922,
923, 929 610,571
25 Administrative services under the IASA BHE GT&S, LLC 556, 557, 580, 922, 923,
929 2,450,225
26 Administrative services under the IASA Kern River Gas Transmission Company 557, 560, 580, 922, 923,
929, 930 267,253
27 Operational support services Kern River Gas Transmission Company 454 38,717
28 Administrative services under the IASA Northern Natural Gas Company 557, 580, 922, 923, 929 1,619,652
29 Administrative services under the IASA BHE Turbo Machinery, LLC 426.5, 535, 539, 922,
929 2,873,287
30 Administrative services under the IASA MidAmerican Energy Company 557, 580, 903, 922, 923,
929 4,441,738
31 Administrative services under the IASA Northern Powergrid Holdings Company 557, 580, 922, 929 1,965,905
32 Administrative services under the IASA NV Energy, Inc.557, 580, 903, 922, 923,
929, 935 3,424,808
33 Mutual assistance NV Energy, Inc.416 252,846
34 Administrative services under the IASA Nevada Power Company 557, 580, 922, 923, 929 601,155
35 Administrative services under the IASA Sierra Pacific Power Company 557, 580, 922, 923, 929 367,376
36 Operational support services Sierra Pacific Power Company 456 7,668
42
FERC FORM NO. 1 ((NEW))
Page 429
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/11/2024
Year/Period of Report
End of: 2023/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionOfNonPowerGoodOrService
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 the following allocations: Customers: An allocation based on customer counts.
Employees: An allocation based on employee counts. Two combinations of this allocator are used for allocating costs that benefit different companies within the BHE organization. Capital Spend: An allocation based on
capital expenditures. Weighted Customer/Customer Service Agents: An allocation based on a combination of customer counts and customer service agent counts. 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 costs 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. Additionally, certain costs
are allocated at the invoice or project level based on unique allocations.
(b) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies
Non-power goods or services provided by BNSF Railway Company are as follows: $ 23,778,710 of rail services and $130,176 of right-of-way.
FERC FORM NO. 1 ((NEW))
Page 429