2022Annual Report FERC Form 1.pdf

1407 W. North Temple, Suite 330 
Salt Lake City, UT 84116 

April 25, 2023

VIA ELECTRONIC DELIVERY

Jan Noriyuki
Commission Secretary
Idaho Public Utilities Commission
11331 W Chinden Blvd.
Building 8 Suite 201A
Boise, ID 83714

Re: FERC Form 1

Dear Ms. Noriyuki:

Rocky Mountain Power, a division of PacifiCorp, submits for electronic filing PacifiCorp’s annual
FERC Form 1 report for the year ended December 31, 2022.

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

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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. TheFederal Energy Regulatory Commission does not consider these reports to beof confidential nature
Exact Legal Name of Respondent (Company)
PacifiCorp
Year/Period of ReportEnd of: 2022/ Q4
FERC FORM NO. 1 (REV. 02-04)
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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 regulatoryrequirement 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 PowerAct (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 toStockholders, mail the stockholders report to the Secretary of the Commission at:SecretaryFederal 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 CPACertification 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 theretoand 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 phrasesonly 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 andsuch 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 theFederal 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 donot 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 168hours per response.
Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street
NE, Washington, DC 20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer
for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information does not display a valid control number (44 U.S.C. § 3512 (a)).
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 dateamounts.
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 bereported 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 towhy 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" isNetwork 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 NetworkTransmission 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 dateof 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 anyof 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 apart 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 tointerstate 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 thepurposes 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 projectand 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 mayrequire any such person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless the Commission otherwise specifies*.10
"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)
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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: 2022/ 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)
04/18/2023
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)
04/18/2023
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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
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
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40 276
41 278
42 300
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
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
0 414 N/A
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
Accumulated Deferred Income Taxes-Other
Other Regulatory Liabilities
Electric Operating Revenues
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)
Transmission Line Statistics Pages
Transmission Lines Added During Year
Substations
Transactions with Associated (Affiliated) Companies
Footnote Data
Stockholders' Reports (check appropriate box)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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-namedPacifiCorp, 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 2.0 million retail electric customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp is principally engaged in the business of generating, transmitting, distributing and selling electricity. In addition to retailsales, 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)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 beneficially owned by family members and related or affiliate entities of the late Mr. Walter Scott, Jr., a former member of BHE's Board of Directors.
FERC FORM No. 1 (ED. 12-96)Page 102
1
1
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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.
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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, 2022, 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, 2022, the Foundation's two directors are also directors of PacifiCorp.FERC FORM No. 1 (ED. 12-96)Page 103
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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, 2022:
2 Chair of the Board of Directors and Chief Executive Officer, PacifiCorp (b)Scott W. Thon
3 Former Chair of the Board of Directors and Chief Executive Officer, PacifiCorp (c)William J. Fehrman
4 President and Chief Executive Officer, Pacific Power Stefan A. Bird 510,000
5 President and Chief Executive Officer, Rocky Mountain Power Gary W. Hoogeveen 510,000
6 Vice President, Chief Financial Officer and Treasurer, PacifiCorp Nikki L. Kobliha 282,182
FERC FORM No. 1 (ED. 12-96)
Page 104
Title Name of Officer Salary for Year Date Started in Period Date Ended in Period
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: OfficerTitle
PacifiCorp sets forth compensation information for its "named executive officers" for the year ended December 31, 2022 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 April 13, 2022, Mr. William J. Fehrman resigned as PacifiCorp's Chair of the Board of Directors and Chief Executive Officer and Mr. Scott W. Thon was elected as PacifiCorp's Chair of the Board of Directors and Chief Executive Officer. Neither Mr. Fehrman nor Mr. Thon received any direct compensation from PacifiCorp in 2022. PacifiCorp reimbursed its indirect parent company, Berkshire Hathaway Energy Company ("BHE"), for
the cost of Mr. Fehrman’s and Mr. Thon's time spent on matters supporting PacifiCorp, including compensation paid to them by BHE, pursuant to an intercompany administrative services agreement among BHE and its subsidiaries. For further information on executive compensation, refer to BHE’s Annual Report on Form 10-K for the year ended December 31, 2022.
(c) Concept: OfficerName
On April 13, 2022, Mr. William J. Fehrman resigned as PacifiCorp's Chair of the Board of Directors and Chief Executive Officer and Mr. Scott W. Thon was elected as PacifiCorp's Chair of the Board of Directors and Chief Executive Officer. Neither Mr. Fehrman nor Mr. Thon received any direct compensation from PacifiCorp in 2022. PacifiCorp reimbursed its indirect parent company, Berkshire Hathaway Energy Company ("BHE"), for the cost of Mr. Fehrman’s and Mr. Thon's time spent on matters supporting PacifiCorp, including compensation paid to them by BHE, pursuant to an intercompany administrative services agreement among BHE and its subsidiaries. For further information on executive compensation, refer to BHE’s Annual Report on Form 10-K for the year ended December 31, 2022.
FERC FORM No. 1 (ED. 12-96)Page 104
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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).
LineNo.(a)(b)(c)(d)
1 Scott W. Thon (Chair of the Board of Directors and Chief Executive Officer, PacifiCorp)666 Grand Avenue, 27th Floor, Des Moines, IA 50309 false false
2 William J. Fehrman (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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 ER11-3643
FERC FORM No. 1 (NEW. 12-08)Page 106
FERC Rate Schedule or Tariff Number FERC Proceeding
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Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/18/2023
Year/Period of Report
End of: 2022/ 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 theformula rate(s)?
☑ Yes
☐ No
If yes, provide a listing of such filings as contained on the Commission's eLibrary website.
LineNo.(a)(b)(c)(d)(e)
1 20220118-5202 01/18/2022 ER22-836-000 (a)See footnote PacifiCorp's Volume No. 11 Open Access Transmission Tariff
2 20220318-5107 03/18/2022 ER20-1828-003 (b)See footnote PacifiCorp's Volume No. 11 Open Access Transmission Tariff
3 20220330-5122 03/30/2022 ER22-1510-000 (c)See footnote PacifiCorp's Volume No. 11 Open Access Transmission Tariff
4 20220407-5164 04/07/2022 ER22-1601-000 (d)See footnote PacifiCorp's Volume No. 11 Open Access Transmission Tariff
5 20220415-5172 04/15/2022 ER22-1651-000 (e)See footnote PacifiCorp's Volume No. 11 Open Access Transmission Tariff
6 20220513-5198 05/13/2022 ER11-3643-000 (f)See footnote PacifiCorp's Volume No. 11 Open Access Transmission Tariff
7 20220606-5193 06/06/2022 ER20-1828-004 (g)See footnote PacifiCorp's Volume No. 11 Open Access Transmission Tariff
8 20220617-5147 06/17/2022 EL22-38-000 (h)See footnote PacifiCorp's Volume No. 11 Open Access Transmission Tariff
9 20221202-5019 12/02/2022 ER23-545-000 (i)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
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Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/18/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionOfFiling
PacifiCorp submits tariff filing per 35.13(a)(2)(iii: OATT Revised Attachment H-1 (Updates Form 1 Source References 2022) to be effective 3/20/2022 under ER22-836
(b) Concept: DescriptionOfFiling
PacifiCorp submits tariff filing per 35: OATT Order 864 Compliance Filing - Third Deficiency Response to be effective 1/27/2020 under ER20-1828
(c) Concept: DescriptionOfFiling
PacifiCorp submits tariff filing per 35.13(a)(2)(iii: OATT Revised Attachment H-1 (Rev Depreciation Rates 2022) to be effective 6/1/2022 under ER22-1510
(d) Concept: DescriptionOfFiling
PacifiCorp submits tariff filing per 35.13(a)(2)(iii: OATT Revised Attachment H-1 (Additional Update Form 1 Source References 2022) to be effective 4/8/2022 under ER22-1601
(e) Concept: DescriptionOfFiling
PacifiCorp submits tariff filing per 35.13(a)(2)(iii: OATT Formula Rate - Schedule 10 Trans System Loss Factor June 2022 to be effective 6/1/2022 under ER22-1651
(f) Concept: DescriptionOfFiling
Transmission Formula Rate Annual Update Informational Filing of PacifiCorp under ER11-3643
(g) Concept: DescriptionOfFiling
PacifiCorp submits tariff filing per 35: OATT Order 864 Compliance Filing - June 2022 to be effective 1/27/2020 under ER20-1828
(h) Concept: DescriptionOfFiling
Initial Brief of PacifiCorp under EL22-38
(i) Concept: DescriptionOfFiling
PacifiCorp submits tariff filing per 35.13(a)(2)(iii: OATT Revised Attachment H-1 - Attachment 14 to be effective 2/2/2023 under ER23-545
FERC FORM NO. 1 (NEW. 12-08)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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)35
19 320-323 Electric Operation and Maintenance Expenses (b)185
20 320-323 Electric Operation and Maintenance Expenses (b)196
21 320-323 Electric Operation and Maintenance Expenses (b)197
FERC FORM No. 1 (NEW. 12-08)Page 106b
Page No(s).Schedule Column Line No.
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 gasmade 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
None
Oregon
Central Point 01/28/2022 01/28/2032 7.0%
Gates 04/15/2022 04/15/2032 7.0%
Madras 10/20/2022 10/20/2032 7.0%
Medford 10/17/2022 10/17/2023 7.0%
Seaside 03/17/2022 03/17/2042 7.0%
Utah
Alta 01/10/2022 01/10/2032 6.0%
Erda 12/01/2022 12/01/2042 6.0%
Farmington 01/01/2022 01/01/2027 6.0%
River Heights 03/01/2022 03/01/2027 5.0%
Vernon 05/01/2022 05/01/2042 —%
Weber County 03/01/2022 03/01/2032 —%
Washington
Benton 12/15/2022 10/25/2032 6.0%
Wyoming
Kemmerer 06/01/2022 06/01/2047 2.0%
(1) In California, franchise agreement fees are an expense to PacifiCorp and are embedded in rates.
(2) In Idaho, PacifiCorp collects franchise agreement fees from customers and remits them directly to the applicable municipalities.
(3) In Oregon, the first 3.5% of the franchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 3.5% is collected from customers and remitted directly to the applicable municipalities.
(4) In Utah, 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.
None.
ITEM 4.None.
ITEM 5.
For the twelve-month period ended December 31, 2022, PacifiCorp did not significantly increase or decrease its transmission or distribution territory. Refer to Page 424, Transmission lines added or altered of this Form No. 1 for additional information regarding transmission lines added or removed during the year.
ITEM 6.
Long-term Debt
In December 2022, PacifiCorp issued $1.1 billion of its 5.350% First Mortgage Bonds due December 2053. 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 Berkshire Hathaway Energy's Green Financing Framework. Proceeds will not knowingly be allocated to the same portion of a project that received allocation of proceeds under any other Green FinancingInstrument; activities related to the exploration, production, transportation, or consumption of fossil fuels; or activities related to nuclear energy.
As of December 31, 2022, PacifiCorp had regulatory authority from the Public Utility Commission of Oregon ("OPUC") and the Idaho Public Utilities Commission ("IPUC") to issue an additional $900 million of long-term debt. PacifiCorp must make a notice filing with the Washington Utilities and Transportation Commission prior to any future issuance. Also, as of December 31,2022, PacifiCorp had an effective shelf registration statement with the United States Securities and Exchange Commission to issue an indeterminate amount of first mortgage bondsthrough September 2023. State commission authorizations to issue an additional $900 million of long-term debt are as follows:
•OPUC – Docket No. UF-4318, Order No. 20-393, dated November 3, 2020.
•IPUC – Case No. PAC-E-20-15, Order 34831, dated November 12, 2020, effective through September 30, 2025.
PacifiCorp's Mortgage and Deed of Trust creates a lien on most of PacifiCorp's electric utility property, allowing the issuance of bonds based on a percentage of utility property additions, bond credits arising from retirement of previously outstanding bonds or deposits of cash. The amount of bonds that PacifiCorp may issue generally is also subject to a net earnings test. As of December 31, 2022, PacifiCorp estimated it would be able to issue up to $8.5 billion of new first mortgage bonds under the most restrictive issuance test in the mortgage. Any issuances aresubject to market conditions and amounts are further limited by regulatory authorizations or commitments or by covenants and tests contained in other financing agreements. PacifiCorp also has the ability to release property from the lien of the mortgage on the basis of property additions, bond credits or deposits of cash.
For further discussion, refer to Note 8 of Notes to Financial Statements in this Form No. 1.
ITEM 7.
None.
(1)
(2)
(3)
(4)
(5)
(6)
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ITEM 8.
For the twelve-month period ended December 31, 2022, 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)2.36%01/26/2022 $2,019,563
IBEW 57 Power Supply (UT, ID & WY)2.34%01/26/2022 835,395
IBEW 57 Combustion Turbine (UT)2.34%01/26/2022 77,468
IBEW 77 (WA)4.50%01/26/2022 52,527
IBEW 125 (OR, WA)5.93%01/26/2022 1,687,820
IBEW 659 (OR, CA)1.48%04/26/2022 484,431
UWUA 197 (OR)4.06%05/26/2022 61,054
IBEW 57 Laramie (WY)1.30%06/26/2022 8,780
UWUA 127 (WY)0.61%09/26/2022 $268,632
Total $5,495,670
.(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, 2022, other than preferred and common stock dividends declared and paid.
In January 2023, PacifiCorp declared dividends of $300 million payable to PPW Holdings LLC in February 2023.
ITEM 12.
None.
ITEM 13.
On April 13, 2022, Scott W. Thon replaced William J. Fehrman 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)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 33,039,040,567 32,293,100,959
3 200 2,476,435,222 1,131,734,692
4 35,515,475,789 33,424,835,651
5 200 12,334,383,396 11,632,340,710
6 23,181,092,393 21,792,494,941
7 202
8
9
10
11
12 202
13
14 23,181,092,393 21,792,494,941
15
16
17
18 21,206,842 21,197,450
19 3,254,224 3,221,891
20 69,928 69,928
21 224 136,476,068 115,816,829
23 228
24 100,689,729 118,042,168
25
26
27
28 131,896,187 106,001,549
29
30 14,530,841 19,559,679
31
32 401,615,371 377,465,712
33
34
35 21,115,014 1,470,795
36
37
38 566,381,766 151,097,351
39 1,383,552 1,361,714
40 533,992,933 479,505,475
41 75,334,312 49,554,169
42 18,532,513 17,701,164
43
44 (a)83,670,876 (b)55,652,195
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)
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45 227 133,979,566 192,078,435
46 227
47 227
48 227 340,361,073 281,877,967
49 227
50 227
51 202/227
52 228 2,577,755
53 228
54 227
55
56
57 129,879,658 81,560,111
58
59 1,275,153 1,965
60 1,665,826 1,181,610
61 300,524,000 263,654,000
62
63 198,724,444 95,643,511
64 14,530,841 19,559,679
65
66
67 2,357,802,574 1,617,378,455
68
69 49,255,311 42,678,915
70 230a
71 230b
72 232 1,807,229,847 1,278,010,867
73 20,141,195 9,534,716
74
75
76
77
78 233 128,330,985 107,087,451
79
80 352
81 2,392,432 2,836,085
82 234 695,784,538 701,421,321
83
84 2,703,134,308 2,141,569,355
85 28,643,644,646 25,928,908,463
FERC FORM No. 1 (REV. 12-03)Page 110-111
Fuel Stock (151)
Fuel Stock Expenses Undistributed (152)
Residuals (Elec) and Extracted Products (153)
Plant Materials and Operating Supplies (154)
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)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) 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.
(b) Concept: AccountsReceivableFromAssociatedCompanies
As of December 31, 2021, Account 146, Accounts receivable from associated companies, included $54,474,838 of income tax receivable from Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.FERC FORM No. 1 (REV. 12-03)Page 110-111
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 6,188,985,268 5,387,352,868
12 118 80,131,357 61,817,828
13 250
14
15 122(a)(b)(9,348,616)(17,132,153)
16 10,741,074,400 9,913,344,934
17
18 256 9,742,150,000 8,797,150,000
19 256
20 256
21 256
22 227 2,945
23 26,507,475 24,493,189
24 9,715,642,752 8,772,659,756
25
26 18,311,335 19,860,468
27 7,696,932 5,351,421
28 168,270,561 153,152,301
29 59,591,258 75,091,507
30 32,419,032 32,368,828
31 1,720,000 8,549,918
32 1,875,535 7,091,366
33
34 331,315,147 303,597,269
35 621,199,800 605,063,078
36
37
38 981,087,553 617,255,909
39 (a)3,375
40 148,494,505 139,954,550
41 50,669,328 45,305,524
42 262 44,786,760 56,245,950
43 129,544,631 122,543,764
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) Reaquired 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) Reaquired 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)
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44 40,475 40,475
45
46
47 22,624,875 21,220,657
48 126,309,990 87,320,483
49 4,197,623 3,638,134
50 6,554,192 37,762,438
51 1,875,535 7,091,366
52
53
54 1,512,437,772 1,124,196,518
55
56 140,928,435 120,471,243
57 266 9,732,439 11,945,656
58
59 269 393,065,634 237,702,175
60 278 1,629,731,766 1,563,255,203
61
62 272 134,154,544 143,583,856
63 3,180,346,057 3,054,144,040
64 565,331,047 382,542,004
65 6,053,289,922 5,513,644,177
66 28,643,644,646 25,928,908,463
FERC FORM No. 1 (REV. 12-03)
Page 112-113
Dividends Declared (238)
Matured Long-Term Debt (239)
Matured Interest (240)
Tax Collections Payable (241)
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 Reaquired 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)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 majorfactors 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.
LineNo.Title of Account(a)(Ref.) Page No.(b)
Total Current Year to Date Balance forQuarter/Year(c)
Total Prior Year to Date Balance forQuarter/Year(d)
Current 3 Months Ended - Quarterly Only - No4th Quarter(e)
Prior 3 Months Ended - Quarterly Only - No 4thQuarter(f)
Electric
Utility
Current Yearto Date (indollars)(g)
Electric
Utility
PreviousYear to Date(in dollars)(h)
GasUtiity
Current
Year toDate(indollars)(i)
GasUtilityPreviousYear toDate (in
dollars)
(j)
OtherUtility
Current
Year toDate(indollars)(k)
OtherUtilityPreviousYear toDate (in
dollars)
(l)
1
2 300 5,666,541,404 5,292,889,125 5,666,541,404 5,292,889,125
3
4 320 2,824,097,503 2,523,615,762 2,824,097,503 2,523,615,762
5 320 420,905,231 382,291,665 420,905,231 382,291,665
6 336 (a)1,016,353,629 986,207,765 1,016,353,629 986,207,765
7 336 (b)0 (e)0
8 336 64,937,656 58,932,504 64,937,656 58,932,504
9 336 1,132,844 3,113,124 1,132,844 3,113,124
10
11
12 11,367,893 11,401,911 11,367,893 11,401,911
13
14 262 (c)194,545,089 213,406,731 194,545,089 213,406,731
15 262 (227,053,116)(165,049,160)(227,053,116) (165,049,160)
16 262 (2,662,119)5,479,455 (2,662,119)5,479,455
17 234, 272 985,200,400 833,817,129 985,200,400 833,817,129
18 234, 272 824,722,423 757,999,686 824,722,423 757,999,686
19 266 (1,055,726)(1,339,178)(1,055,726) (1,339,178)
20
21
22 100 47 100 47
23
24 (d)0
25 4,463,046,761 4,093,877,975 4,463,046,761 4,093,877,975
27 1,203,494,643 1,199,011,150 1,203,494,643 1,199,011,150
28
29
30
31 1,478,728 2,662,913
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)
(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)
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32 1,467,260 2,873,018
33
34 28,146 25,341
35 323,052 296,773
36 119 18,430,410 18,855,602
37 43,673,333 24,486,132
38 70,977,165 49,860,757
39 (3,107,598)5,733,860
40 1,060,447 2,363,941
41 131,340,131 101,361,619
42
43 31 1,472
44 1,331,741 1,331,000
45 2,441,962 2,445,690
46 1,221,220 (10,128,246)
47 (54,691)50,152
48 1,353,122 1,146,393
49 3,532,867 7,903,583
50 9,826,252 2,750,044
51
52 262 331,830 332,818
53 262 6,925,565 4,382,388
54 262 1,568,448 992,489
55 234, 272 468,056,659 91,464,238
56 234, 272 467,729,785 91,395,252
57
58 2,501,395 1,105,184
59 6,651,322 4,671,497
60 114,862,557 93,940,078
61
62 404,320,904 405,404,301
63 4,457,195 4,541,192
64 443,653 607,365
65 2,718 9,640
66
67 136,625 8,260
68 20,255,501 18,094,181
69 31,361,791 23,737,375
70 398,249,369 404,908,284
71 920,107,831 888,042,944
72
73
74
75
76 262
77
78 920,107,831 888,042,944
FERC FORM No. 1 (REV. 02-04)Page 114-117
(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)
(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)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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, 2022 and 2021, depreciation expense associated with transportation equipment was $23,520,027 and $21,897,241, 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, 2022 and 2021, payroll taxes were $42,754,894 and $41,389,456, 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023
Year/Period of Report
End of: 2022/ 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 5,328,687,084 4,574,204,823
2
3
4
9
10
15
16 901,677,421 869,187,342
17
17.1 215.1 (7,224,984)(4,673,767)
22 (7,224,984)(4,673,767)
23
23.1 238 (a)(161,902)(d)(161,902)
29 (161,902)(161,902)
30
30.1 238 (100,000,000)(150,000,000)
36 (100,000,000)(150,000,000)
37 216.1 (b)116,881 (e)40,130,588
38 6,123,094,500 5,328,687,084
39
45
46 (c)65,890,768 (f)58,665,784
47 65,890,768 58,665,784
48 6,188,985,268 5,387,352,868
49 61,817,828 83,092,814
50 18,430,410 18,855,602
51
52
52.1 (116,881)(40,130,588)
53 80,131,357 61,817,828
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)
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)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) 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
(b) Concept: TransfersFromUnappropriatedUndistributedSubsidiaryEarnings
For the twelve-month period ended December 31, 2022, paid distributions from subsidiaries of PacifiCorp were as follows:
Trapper Mining, Inc.$116,881
$116,881
(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, 2021 and declared dividends on preferred stock during the twelve-month period ended December 31, 2021 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: TransfersFromUnappropriatedUndistributedSubsidiaryEarnings
For the twelve-month period ended December 31, 2021, paid distributions from subsidiaries of PacifiCorp were as follows:
Pacific Minerals, Inc.$40,000,000
Trapper Mining, Inc.130,588
$40,130,588
(f) 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
2 920,107,831 888,042,944
3
4 (a)1,041,278,061 1,013,325,570
5
5.1
5.2 66,269,397 60,263,504
5.3 1,132,844 3,113,124
5.4 11,243,603 11,277,621
8 160,804,851 75,886,429
9 (3,557,121)(2,444,362)
10 (143,775,110)(13,561,927)
11 (384,237)8,420,328
12
13 292,340,442 (3,178,644)
14 (425,809,415)(124,842,614)
15 (118,013,860)(63,774,428)
16 70,977,165 49,860,757
17 18,313,529 (21,274,986)
18
18.1 (27,463,823)(34,978,927)
18.2 95,100,000 18,900,000
18.3
18.4 2,548,699 2,539,731
18.5 (1,322,710)(2,788,571)
18.6 2,306,885 3,748,044
18.7 1,252,307 (10,097,198)
18.8 4,454,477 4,580,196
18.9 3,385,848 (2,492,380)
18.10 (30,747)(411,687)
22 1,792,577,528 1,802,940,982
24
25
26 (2,236,811,129)(1,562,755,515)
27
28
29
30 (70,977,165)(49,860,757)
31
34 (2,165,833,964)(1,512,894,758)
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):
Amounts Due To/From Affiliates (Net)
Derivative Collateral (Net)
Other Operating Activities:
Depreciation and depletion included in cost of fuel
Net gain 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)
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36
37 (b)1,404,192 (c)13,387,785
39
40
41
42
44
45
46
47
49
50
51
52
53
53.1
53.2 996,980 487,069
53.3 2,353,006 (2,310,144)
57 (2,161,079,786)(1,501,330,048)
59
60
61 1,087,491,374 983,978,493
62
63
64
66
67
70 1,087,491,374 983,978,493
72
73 (155,000,000)(870,000,000)
74
75
76
76.1 (24,835,000)
76.2 (574,649)(1,287,340)
76.3 (539,251)(24,738)
76.4 (1,404,405)(5,220,564)
78 (92,998,346)
80 (161,902)(161,902)
81 (100,000,000)(150,000,000)
83 829,811,167 (160,549,397)
85
86 461,308,909 141,061,537
88 159,272,371 18,210,834
90 620,581,280 159,272,371
FERC FORM No. 1 (ED. 12-96)
Page 120-121
Acquisition of Other Noncurrent Assets (d)
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 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):
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):
Net repayments of affiliate borrowing from subsidiary company, Pacific Minerals, Inc.
Other deferred financing costs
Other
Repayment of Finance Lease Principal in Capital Lease Obligations
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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: DepreciationAndDepletion
Includes depreciation expense associated with transportation equipment and finance lease assets of $24,924,432 and $27,117,805 during the years ended December 31,2022 and 2021, respectively.
(b) Concept: ProceedsFromDisposalOfNoncurrentAssets
Represents proceeds from the disposal of fixed assets.
(c) Concept: ProceedsFromDisposalOfNoncurrentAssets
Represents proceeds from the disposal of fixed assets.
FERC FORM No. 1 (ED. 12-96)Page 120-121
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 Cormmission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof.4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-termcontracts; 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.
(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 institutionsand 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. Theaccounting 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 temporarydifferences 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 toreport 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, includingderivative 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 the 2022 McKinney fire described in Note 14. Actual results may differ from the estimates used in preparing the financial statements.
Accounting for the Effects of Certain Types of Regulation
PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, PacifiCorp defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in rates occur.
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 areassumed 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, custodial and nuclear decommissioning funds. A reconciliation of cash and cash equivalents and restricted cashequivalents as of December 31, 2022 and 2021 as presented in 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):
2022 2021
Cash (131)$21 $1
Other special funds (128)34 7
Temporary cash investments (136)566 151
Total cash and cash equivalents and restricted cash and cash equivalents 621 159
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, 2022 and 2021, 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, PacifiCorpprimarily 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):
2022 2021
Beginning balance $18 $17
Charged to operating costs and expenses, net 18 13
Write-offs, net (17)(12)
Ending balance $19 $18
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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 withcounterparties 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.
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 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 accountsare 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 becapitalized 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 fromnon-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. Other revenue consists primarily of contractual agreements, including derivative arrangements.
Revenue recognized is equal to what PacifiCorp has the right to invoice as it corresponds directly with the value to the customer of PacifiCorp's performance to date and includes billed and unbilled amounts. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted tobe 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.
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 that are associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain property-related basis differences and other variousdifferences 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 incometax 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.
Subsequent Events
PacifiCorp has evaluated the impact on its financial statements of events occurring after December 31, 2022 up to February 24, 2023, 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 18,2023. 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 3.5% and 3.5% for the years ended December 31, 2022 and 2021, respectively.
(4) Jointly Owned Utility Facilities
Under joint facility ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly owned generation, transmission and distribution facilities. PacifiCorp accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Statement of Income include PacifiCorp'sshare 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, 2022 (dollars in millions):
PacifiCorp Share Facility in Service Accumulated Depreciation and Amortization Construction Work-in-Progress
Jim Bridger Nos. 1 - 4 67 %$1,535 $944 $39
Hunter No. 1 94 517 227 3
Hunter No. 2 60 305 147 6
Wyodak 80 491 273 1
Colstrip Nos. 3 and 4 10 262 184 —
Hermiston 50 189 108 —
Craig Nos. 1 and 2 19 372 196 —
Hayden No. 1 25 77 52 —
Hayden No. 2 13 44 31 —
Transmission and distribution facilities Various 916 327 129
Total $4,708 $2,489 $178
(5) Leases
The following table summarizes PacifiCorp's leases recorded on the Comparative Balance Sheet as of December 31 (in millions):
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2022 2021
Right-of-use assets:
Operating leases $11 $11
Finance leases 12 13
Total right-of-use assets $23 $24
Lease liabilities:
Operating leases $11 $11
Finance leases 11 12
Total lease liabilities $22 $23
The following table summarizes PacifiCorp's lease costs for the years ended December 31 (in millions):
2022 2021
Variable $61 $56
Operating 3 3
Finance:
Amortization 1 5
Interest 1 2
Short-term 5 3
Total lease costs $71 $69
Weighted-average remaining lease term (years):
Operating leases 11.4 12.7
Finance leases 9.7 10.1
Weighted-average discount rate:
Operating leases 3.9 %3.7 %
Finance leases 11.4 %11.1 %
Cash payments associated with operating and finance lease liabilities approximated lease cost for the years ended December 31, 2022 and 2021.
PacifiCorp has the following remaining lease commitments as of December 31, 2022 (in millions):
Operating Finance Total
2023 $3 $2 $5
2024 2 2 4
2025 2 2 4
2026 1 2 3
2027 1 2 3
Thereafter 5 8 13
Total undiscounted lease payments 14 18 32
Less - amounts representing interest (3)(7)(10)
Lease liabilities $11 $11 $22
(6) Regulatory Matters
Regulatory Assets
PacifiCorp had regulatory assets not earning a return on investment of $1,197 million and $720 million as of December 31, 2022 and 2021, respectively.
(7) Short-term Debt and Credit Facilities
The following table summarizes PacifiCorp's availability under its unsecured credit facility as of December 31 (in millions):
2022:
Credit facility $1,200
Less:
Tax-exempt bond support and letters of credit (249)
Net credit facility $951
2021:
Credit facility $1,200
Less:
Tax-exempt bond support (218)
Net credit facility $982
As of December 31, 2022, PacifiCorp was in compliance with the covenants of its credit facilities and letter of credit arrangements.
PacifiCorp has a $1.2 billion unsecured credit facility expiring in June 2025 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. As ofDecember 31, 2022 and 2021, PacifiCorp did not have any commercial paper borrowings outstanding.
The credit facility requires 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.
In January 2023, PacifiCorp entered into an additional $800 million 364-day unsecured credit facility expiring in January 2024. No amounts are currently outstanding against this new credit facility.
As of December 31, 2022 and 2021, PacifiCorp had $38 million and $19 million, respectively, of fully available letters of credit issued under committed arrangements outside of its credit facility in support of certain transactions required by third parties that generally have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.
(8) Long-term Debt
In December 2022, PacifiCorp issued $1.1 billion of its 5.35% First Mortgage Bonds due December 2053. 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. Proceeds will not knowingly be allocated to the same portion of a project that received allocation of proceeds under any other Green Financing Instrument; activities related tothe exploration, production, transportation, or consumption of fossil fuels; or activities related to nuclear energy.
PacifiCorp's long-term debt generally includes provisions that allow PacifiCorp to redeem the first mortgage bonds in whole or in part at any time through the payment of a make-whole premium. Variable-rate tax-exempt bond obligations are generally redeemable at par value.
PacifiCorp currently has regulatory authority from the Oregon Public Utility Commission and the Idaho Public Utilities Commission to issue an additional $900 million of long-term debt. PacifiCorp must make a notice filing with the Washington Utilities and Transportation Commission prior to any future issuance. PacifiCorp currently has an effective shelf registration statement filed with the U.S. Securities and Exchange Commission to issue an indeterminate amount of first mortgage bonds through September 2023.
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's mortgage. Approximately $33 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage as of December 31, 2022.
As of December 31, 2022, the annual principal maturities of long-term debt for 2023 and thereafter are as follows (in millions):
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Long-termDebt
2023 $449
2024 591
2025 302
2026 100
2027 —
Thereafter 8,300
Total $9,742
Unamortized discount (26)
Total $9,716
(9) Income Taxes
Income tax (benefit) expense consists of the following for the years ended December 31 (in millions):
2022 2021
Current:
Federal $(220)$(161)
State (1)6
Total $(221)$(155)
Deferred:
Federal 90 34
State 71 42
Total $161 $76
Investment tax credits (4)(2)
Total income tax benefit $(64)$(81)
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
2022 2021
Federal statutory income tax rate 21 %21 %
State income taxes, net of federal income tax benefit 3 4
Effects of ratemaking (12)(14)
Federal income tax credits (22)(20)
Valuation allowance 2 —
Other 1 (1)
Effective income tax rate (7)%(10)%
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, 2022 and 2021 totaled $185million and $164 million, respectively.
Effects of ratemaking is primarily attributable to activity associated with excess deferred income taxes. Excess deferred income tax amortization, net of deferrals, was $102 million for 2022. Excess deferred income tax amortization, net of deferrals was $112 million for 2021, including the use of $4 million to amortize certain regulatory balances in Wyoming and Idaho.
The net deferred income tax liability consists of the following as of December 31 (in millions):
2022 2021
Deferred income tax assets:
Regulatory liabilities $421 $404
Employee benefits 59 68
State carryforwards 73 73
Loss contingencies 45 34
Asset retirement obligations 79 73
Other 54 64
Total deferred income tax assets $731 $716
Valuation Allowances $(35)$(15)
Total deferred income tax assets, net $696 $701
Deferred income tax liabilities:
Property, plant and equipment (3,315)(3,198)
Regulatory assets (461)(332)
Other (104)(50)
(3,880)(3,580)
Net deferred income tax liability $(3,184)$(2,879)
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, 2022 (in millions):
State
Net operating loss carryforwards $1,159
Deferred income taxes on net operating loss carryforwards $53
Expiration dates 2023 - indefinite
Tax credit carryforwards $20
Expiration dates 2023 - 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, 2018, 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 whichthe 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, collectively the PacifiCorp Retirement Plan ("Retirement Plan"), and the Supplemental Executive Retirement Plan ("SERP"). The Retirement Plan is closed to all non-union employees hired after January 1, 2008. All non-union Retirement Plan participants hired prior to January 1, 2008 that did not elect to receive equivalent fixed contributions to the 401(k) Plan effective January 1, 2009 earned benefits based on a cash balance formula through December 31, 2016. Effective January1, 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 payformula. 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 and 2021 as a result of the amount of lump sum distributions in the Retirement Plan exceeding the service and interest cost threshold. The 2021 pension settlement accounting included an interim July 31, 2021 remeasurement of the pension plan assets and projected benefit obligation. As a result of the settlement accounting, PacifiCorp recognized settlement losses of $6 million, net of regulatory deferrals during the years ended December 31, 2022 and 2021.
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):
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Pension Other Postretirement
2022 2021 2022 2021
Service cost $— $— $2 $2
Interest cost 29 29 8 7
Expected return on plan assets (42)(51)(11)(9)
Settlement 6 6 — —
Net amortization 16 21 1 1
Net periodic benefit cost (credit)$9 $5 $— $1
Pension amounts represent settlement losses of $24 million and $15 million net of deferrals of $18 million and $9 million during the years ended December 31, 2022 and 2021.
Funded Status
The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
Pension Other Postretirement
2022 2021 2022 2021
Plan assets at fair value, beginning of year $1,058 $1,064 $324 $327
Employer contributions 4 5 — 1
Participant contributions — — 5 6
Actual (loss) return on plan assets (172)109 (42)14
Settlement (67)(52)— —
Benefits paid (65)(68)(23)(24)
Plan assets at fair value, end of year $758 $1,058 $264 $324
(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
2022 2021 2022 2021
Benefit obligation, beginning of year $1,048 $1,202 $288 $307
Service cost — — 2 2
Interest cost 29 29 8 7
Participant contributions — — 5 6
Actuarial gain (199)(63)(61)(10)
Settlement (67)(52)— —
Benefits paid (65)(68)(23)(24)
Benefit obligation, end of year $746 $1,048 $219 $288
Accumulated benefit obligation, end of year $746 $1,048
(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
2022 2021 2022 2021
Plan assets at fair value, end of year $758 $1,058 $264 $324
Less - Benefit obligation, end of year 746 1,048 219 288
Funded status $12 $10 $45 $36
Amounts recognized on the Comparative Balance Sheet:
Other special funds (128)$53 $63 $45 $36
Miscellaneous current and accrued liabilities (242)(4)(4)— —
Accumulated provision for pension and benefits (228.3)(37)(49)— —
Amounts recognized $12 $10 $45 $36
The SERP has no plan assets; however, PacifiCorp has a Rabbi trust that holds corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERP. The cash surrender value of all of the policies included in the Rabbi trust, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $61 million and $69 million as of December 31, 2022 and 2021, respectively. These assets are not included in the plan assets in the above table, but are reflected primarily inother investments as of December 31, 2022 and 2021, respectively, on the Comparative Balance Sheet. The projected and accumulated benefit obligations for the SERP were $42 million and $54 million at December 31, 2022 and 2021, respectively.
As of December 31, 2022, 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
2022 2021 2022 2021
Net loss (gain)$273 $298 $(36)$(28)
Regulatory deferrals 29 11 1 2
Total $302 $309 $(35)$(26)
(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, 2022 and 2021 is as follows (in millions):
(1)
(1)
(1)
(2)
(1)
(1)
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Regulatory Asset Accumulated Other Comprehensive Loss Total
Pension
Balance, December 31, 2020 $432 $25 $457
Net gain arising during the year (120)(1)(121)
Net amortization (20)(1)(21)
Settlement (6)— (6)
Total (146)(2)(148)
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
RegulatoryLiability
Other Postretirement
Balance, December 31, 2020 $(10)
Net gain arising during the year (15)
Net amortization (1)
Total (16)
Balance, December 31, 2021 (26)
Net gain arising during the year (8)
Net amortization (1)
Total (9)
Balance, December 31, 2022 $(35)
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
Pension Other Postretirement
2022 2021 2022 2021
Benefit obligations as of December 31:
Discount rate 5.55 %2.90 %5.50 %2.90 %
Rate of compensation increase N/A N/A N/A N/A
Interest crediting rates for cash balance plan - non-union
2020 N/A N/A N/A N/A
2021 N/A 0.82 %N/A N/A
2022 0.88 %0.88 %N/A N/A
2023 4.73 %0.88 %N/A N/A
2024 4.73 %1.90 %N/A N/A
2025 and beyond 2.60 %1.90 %N/A N/A
Interest crediting rates for cash balance plan - union
2020 N/A N/A N/A N/A
2021 N/A 1.42 %N/A N/A
2022 1.94 %1.94 %N/A N/A
2023 3.55 %1.94 %N/A N/A
2024 3.55 %2.30 %N/A N/A
2025 and beyond 2.40 %2.30 %N/A N/A
Net periodic benefit cost for the years ended December 31:
Discount rate 2.90 %2.50 %2.90 %2.50 %
Expected return on plan assets 4.70 6.00 3.44 2.90
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 2023. 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 specifiedunder 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 2023 through 2027 and for the five years thereafter are summarized below (in millions):
Projected Benefit Payments
Pension Other Postretirement
2023 $76 $23
2024 73 22
2025 70 21
2026 67 20
2027 64 20
2028-2032 277 87
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 withsufficient 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, 2022:
Pension Other Postretirement
%%
Debt securities 73 77
Equity securities 22 23
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):
(1)(1)
(2)
(2)
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Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Total
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
As of December 31, 2021:
Cash equivalents $— $15 $— $15
Debt securities:
U.S. government obligations 51 — — 51
Corporate obligations — 299 — 299
Municipal obligations — 22 — 22
Agency, asset and mortgage-backed obligations 38
Equity securities:
U.S. companies 61 — — 61
Total assets in the fair value hierarchy $112 $374 $— 486
Investment funds measured at net asset value 538
Limited partnership interests measured at net asset value 34
Investments at fair value $1,058
(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 50% and 50%, respectively for 2022 and 59% and 41%, respectively, for 2021, and are invested in U.S. and international securities of approximately 90% and 10%, respectively, for 2022 and 84% and 16%, respectively, for 2021.
(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, 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
Limited partnership interests measured at net asset value —
Investments at fair value $264
As of December 31, 2021:
Cash equivalents $4 $1 $— $5
Debt securities:
U.S. government obligations 24 — — 24
Corporate obligations — 79 — 79
Municipal obligations — 15 — 15
Agency, asset and mortgage-backed obligations — 35 — 35
Equity securities:
U.S. companies 4 — — 4
Total assets in the fair value hierarchy $32 $130 $— 162
Investment funds measured at net asset value 161
Limited partnership interests measured at net asset value 1
Investments at fair value $324
(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 2022 and 39% and 61%, respectively, for 2021, and are invested in U.S. and international securities of approximately 91% and 9%, respectively, for 2022 and 90% and 10%, respectively, for 2021.
(3)Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.
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 assetvalue 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 changesin facts and circumstances for a withdrawal occurring by July 2015. As communicated in a letter received in August 2016, the plan trustees determined a withdrawal liability of $115 million. Energy West Mining Company began making installment payments in November 2016 and has the option to elect a lump sum payment to settle the withdrawal obligation. The ultimate amount paid by Energy West Mining Company to settle the obligation is dependent on a variety of factors, including the results of ongoing negotiations with the plan trustees.
The Local 57 Trust Fund is a joint trustee plan such that the board of trustees is represented by an equal number of trustees from PacifiCorp and the union. The Local 57 Trust Fund was established pursuant to the provisions of the Taft-Hartley Act and although formed with the ability for other employers to participate in the plan, there are no other employers that participate in this plan.
The risk of participating in multiemployer pension plans generally differs from single-employer plans in that assets are pooled such that contributions by one employer may be used to provide benefits to employees of other participating employers and plan assets cannot revert to employers. If an employer ceases participation in the plan, the employer may be obligated to pay a withdrawal liability based on the participants' unfunded, vested benefits in the plan. This occurred as a result of Energy West Mining Company's withdrawal from the UMWA 1974 PensionPlan. 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
EmployerIdentificationNumber 2022 2021 Funding improvement plan Surcharge imposed under PPA of 2006 2022 2021 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 $6 $6 2022, 2021
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, 2022, 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 $44 million and $40 million for the years ended December 31, 2022 and 2021, 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.
(1)(1)(1)
(2)
(3)
(2)
(3)
(1)(1)(1)
(2)
(3)
(2)
(3)
(1)
(1)(2)
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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 $1,332 million and $1,187 million as ofDecember 31, 2022 and 2021, respectively.
The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 31 (in millions):
2022 2021
Beginning balance $304 $270
Change in estimated costs 20 40
Additions 3 —
Retirements (6)(15)
Accretion 10 9
Ending balance $331 $304
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 towide 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 may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.
The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Comparative Balance Sheet (in millions):
CurrentAssets Long-termAssets CurrentLiabilities Long-termLiabilities Total
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)
Total derivatives - net basis $184 $15 $(5)$(2)$192
As of December 31, 2021
Not designated as hedging contracts :
Commodity assets $81 $21 $2 $— $104
Commodity liabilities (5)(1)(38)(7)(51)
Total 76 20 (36)(7)53
Total derivatives 76 20 (36)(7)53
Cash collateral receivable — — 5 — 5
Total derivatives - net basis $76 $20 $(31)$(7)$58
(1)PacifiCorp's commodity derivatives are generally included in rates. As of December 31, 2022 a regulatory liability of $270 million was recorded related to the net derivative asset of $270 million. As of December 31, 2021 a regulatory liability of $53 million was recorded related to the net derivative asset of $53 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):
2022 2021
Beginning balance $(53)$17
Changes in fair value recognized in regulatory (liabilities) assets (513)(171)
Net (losses) reclassified to operating revenue (13)(23)
Net gains reclassified to energy costs 309 124
Ending balance $(270)$(53)
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 2022 2021
Electricity purchases, net Megawatt hours 2 2
Natural gas purchases Decatherms 127 106
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 amountof unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand"adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2022 PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $48 million and $37 million as of December 31, 2022 and 2021, respectively, for which PacifiCorp had posted collateral of $- million and $5 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, 2022 and 2021, PacifiCorp would have been required to post $3 million and $23 million, respectively, ofadditional 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. Thethree 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):
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Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Other Total
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)
As of December 31, 2021
Assets:
Commodity derivatives $— $104 $— $(8)$96
Money market mutual funds 156 — — — 156
Investment funds 28 — — — 28
$184 $104 $— $(8)$280
Liabilities - Commodity derivatives $— $(51)$— $13 $(38)
Represents netting under master netting arrangements and a net cash collateral payable of $78 million and a net cash collateral receivable of $5 million as of December 31, 2022 and 2021, 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 usesforward 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 pricingrelationships 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 valueand estimated fair value of PacifiCorp's long-term debt as of December 31 (in millions):
2022 2021
CarryingValue FairValue CarryingValue FairValue
Long-term debt $9,715 $9,045 $8,773 $10,374
(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, 2022 are as follows (in millions):
2023 2024 2025 2026 2027 2028 and Thereafter Total
Contract type:
Purchased electricity contracts -
commercially operable $547 $241 $199 $197 $197 $2,162 $3,543
Purchased electricity contracts -
non-commercially operable — — 6 12 12 208 238
Fuel contracts 784 398 148 146 153 401 2,030
Construction commitments 535 210 14 1 — — 760
Transmission 108 100 74 65 55 418 820
Easements 21 20 20 21 21 720 823
Maintenance, service and
other contracts 101 54 55 53 53 197 513
Total commitments $2,096 $1,023 $516 $495 $491 $4,106 $8,727
Purchased Electricity Contracts - Commercially Operable
As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-term purchases and exchange agreements. PacifiCorp has 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 7 to 30 years in duration, with certain of the PPAs extending through 2054. Future payments associated with these PPAs are expected to bematerial. 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 notany electricity is produced. These arrangements accounted for less than 5% of PacifiCorp's 2022 and 2021 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 7 to 30 years in duration with certain of the PPAs extending through 2054.
In September 2022, PacifiCorp entered into a purchased electricity contract for a 400 MW solar generating facility including a 200 MW battery storage unit. Minimum obligations associated with the battery storage unit are included in the table above. In January 2023, PacifiCorp entered into a PPA for a 525 MW solar generating facility with a corresponding agreement for a 150 MW battery storage unit for which the minimum obligations are being evaluated.
Future payments associated with these arrangements are expected to be material. However, 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.
Construction Commitments
PacifiCorp's construction commitments included in the table above relate to firm commitments and include costs associated with certain generating plant, transmission, and distribution projects.
Transmission
PacifiCorp has contracts for the right to transmit electricity over other entities' transmission lines to facilitate delivery to PacifiCorp's customers.
Easements
PacifiCorp has non-cancelable easements for land on which certain of its assets, primarily wind-powered generating facilities, are located.
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 $200million 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 forPacifiCorp 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 splitbetween 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 publicutility 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 LowerKlamath 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 is anticipated to begin in 2023, and removal of the remaining three dams (J.C. Boyle, Copco No. 1, and Iron Gate) is anticipated to begin 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 $282 million over the next 10 years.
Legal Matters
PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its financial results. PacifiCorp is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.
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Wildfires Overview
A provision for a loss contingency is recorded when it is probable that a liability has been incurred 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.
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 proximately caused by negligence, including real and personal property and natural resource damages; fire suppression costs; personal injury and loss of life damages; and interest.
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. Fire suppression costs estimated by various agencies total approximately $150 million.
Investigations into the cause and origin of each wildfire are complex and ongoing and 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, numerous lawsuits have been filed in Oregon and California, including a class action complaint in Oregon, on behalf of plaintiffs related to the 2020 Wildfires. The plaintiffs seek damages that include property damages, economic losses, punitive damages, exemplary damages, attorneys' fees and other damages. Additionally, several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. The final determinations of liability, however, will only bemade following the completion of comprehensive investigations and litigation processes.
PacifiCorp accrued cumulative estimated probable losses associated with the 2020 Wildfires of $477 million, through December 31, 2022. The accrual as of December 31, 2022 includes PacifiCorp's estimate of losses for fire suppression costs, real and personal property damages, natural resource damages for certain areas and noneconomic damages such as personal injury damages and loss of life damages that it was reasonably able to estimate based on information available through February 24, 2023, the date through which PacifiCorp has evaluated the impactsof events occurring after December 31, 2022 as indicated under "Subsequent Events". Any information associated with the 2020 Wildfires arising subsequent to February 24, 2023 will be considered in a future period. For certain aspects of the 2020 Wildfires for which loss is considered probable, information necessary to reasonably estimate the potential losses, such as those related to certain areas of natural resource damages, is not currently available.
It is reasonably possible PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved and the variation in those types of properties and lack of available details. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover a portion of the losses.
The following table presents changes in PacifiCorp's liability for estimated losses associated with the 2020 Wildfires for the years ended December 31 (in millions):
2022 2021
Beginning balance $252 $252
Accrued losses 225 —
Payments (53)—
Ending balance $424 $252
PacifiCorp's receivable for expected insurance recoveries associated with the probable losses was $246 million and $116 million, respectively, as of December 31, 2022 and 2021. During the years ended December 31, 2022 and 2021, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $64 million and $— million, respectively.
2022 McKinney Fire
According to California Department of Forestry and Fire Protection, on July 29, 2022, at approximately 2:16 p.m. Pacific Time, a wildfire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California (the"2022 McKinney Fire") located in PacifiCorp's service territory. Third party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged, 185 structures destroyed, 12 injuries and four fatalities and consumed 60,000 acres. The cause of the 2022 McKinney Fire is undetermined and remains under investigation by the U.S. Forest Service.
Due to the preliminary nature of the investigation PacifiCorp does not believe a loss is probable and therefore has not accrued any loss as of the date of this filing. While the loss is not probable, PacifiCorp estimates the potential loss, excluding losses for natural resource damages, to be $31 million, net of expected insurance recoveries. The loss estimate includes PacifiCorp's estimate of losses for fire suppression costs; real and personal property damages; and noneconomic damages such as personal injury damages and loss of life damages. PacifiCorp is unable toestimate the total potential loss, including losses for natural resource damages, because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PacifiCorp. PacifiCorp has insurance available and estimates the potential insurance recoveries to be $103 million, to cover potential losses.
As of the date of this filing, multiple lawsuits have been filed in California on behalf of plaintiffs related to the 2022 McKinney Fire. The plaintiffs seek damages that include property damages, economic losses, punitive damages, exemplary damages, attorneys' fees and other damages but the amount of damages sought are not specified. The final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.
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, 2022, 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 reducePacifiCorp's common equity below 44% of its total capitalization, excluding short-term debt and current maturities of long-term debt. As of December 31, 2022, PacifiCorp's actual common equity percentage, as calculated under this measure, was 54%, and PacifiCorp would have been permitted to dividend $3.5 billion under this commitment.
These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings or BHE if PacifiCorp's senior unsecured debt rating is BBB- or lower by Standard & Poor's Rating Services or Fitch Ratings, or Baa3 or lower by Moody's Investor Service, as indicated by two of the three rating services. As of December 31, 2022, PacifiCorp met the minimum required senior unsecured debt ratings for making distributions.
PacifiCorp is also subject to a maximum debt-to-total capitalization percentage under various financing agreements as further discussed in Note 7.
In January 2023, PacifiCorp declared dividends of $300 million payable to PPW Holdings LLC in February 2023.
(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):
2022 2021
Interest paid, net of amounts capitalized $380 $395
Income taxes (received), net $(197)$(128)
Supplemental disclosure of non-cash investing and financing activities:
Accounts payable related to utility plant additions $558 $254
(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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 (netamount)(c)
Foreign Currency Hedges
(d)
Other Adjustments
(e)
Other Cash Flow Hedges Interest RateSwaps(f)
OtherCashFlow
Hedges
[Specify](g)
Totals foreachcategory ofitems
recorded in
Account219(h)
Net Income
(Carried
Forwardfrom Page116, Line78)(i)
TotalComprehensive
Income
(j)
1 Balance of Account 219 at Beginning of Preceding Year (19,097,488)(19,097,488)
2 Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income 1,024,956 1,024,956
3 Preceding Quarter/Year to Date Changes in Fair Value 940,379 940,379
4 Total (lines 2 and 3)1,965,335 1,965,335 888,042,944 890,008,279
5 Balance of Account 219 at End of Preceding Quarter/Year (17,132,153)(17,132,153)
6 Balance of Account 219 at Beginning of Current Year (17,132,153)(17,132,153)
7 Current Quarter/Year to Date Reclassifications from Account 219 to Net Income 963,429 963,429
8 Current Quarter/Year to Date Changes in Fair Value 6,820,108 6,820,108
9 Total (lines 7 and 8)7,783,537 7,783,537 920,107,831 927,891,368
10 Balance of Account 219 at End of Current Quarter/Year (9,348,616)(9,348,616)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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.
LineNo.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 32,448,292,017 32,448,292,017
4 22,614,635 22,614,635
5
6 397,490,857 397,490,857
7
8 32,868,397,509 32,868,397,509
9
10 14,174,575 14,174,575
11 2,476,435,222 2,476,435,222
12 156,468,483 156,468,483
13 35,515,475,789 35,515,475,789
14 12,334,383,396 12,334,383,396
15 23,181,092,393 23,181,092,393
16
17
18 11,453,591,865 11,453,591,865
19
20
21 736,465,711 736,465,711
22 12,190,057,576 12,190,057,576
23
24
25
26
27
28
29
30
31
32 144,325,820 144,325,820
33 12,334,383,396 12,334,383,396
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 ANDDEPLETION
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)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 afootnote)(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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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) atentative 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 distributedin 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.
LineNo.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 215,423,339 105,320 42,030,535 173,498,124
4 (303) Miscellaneous Intangible Plant 891,051,459 74,067,430 9,554,460 (81,343)955,483,086
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)1,106,474,798 74,172,750 51,584,995 (81,343)1,128,981,210
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 1,004,609,523 3,888,755 1,623,308 1,006,874,970
10 (312) Boiler Plant Equipment 4,385,686,357 95,768,477 49,083,603 4,432,371,231
11 (313) Engines and Engine-Driven Generators
12 (314) Turbogenerator Units 948,553,837 50,876,552 13,072,802 986,357,587
13 (315) Accessory Electric Equipment 426,564,107 434,363 (644,759)427,643,229
14 (316) Misc. Power Plant Equipment 31,717,120 2,304,284 578,566 33,442,838
15 (317) Asset Retirement Costs for Steam Production 163,179,963 18,654,036 534,481 (2,429,830)178,869,688
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)7,052,025,859 171,926,467 64,248,001 (2,429,830)7,157,274,495
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 38,970,017 498,918 38,471,099
28 (331) Structures and Improvements 296,483,149 4,972,302 19,415,888 282,039,563
29 (332) Reservoirs, Dams, and Waterways 538,126,024 19,946,186 43,034,535 515,037,675
30 (333) Water Wheels, Turbines, and Generators 147,692,537 2,079,050 19,295,449 130,476,138
31 (334) Accessory Electric Equipment 88,567,241 1,555,433 17,214,461 72,908,213
32 (335) Misc. Power Plant Equipment 3,157,355 (316,136)178,121 2,663,098
33 (336) Roads, Railroads, and Bridges 26,488,531 1,888,693 3,209,740 25,167,484
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)1,139,484,854 30,125,528 102,847,112 1,066,763,270
36 D. Other Production Plant
37 (340) Land and Land Rights 52,835,471 30,599 52,866,070
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38 (341) Structures and Improvements 274,719,174 1,542,377 (193,213)276,454,764
39 (342) Fuel Holders, Products, and Accessories 16,412,329 16,412,329
40 (343) Prime Movers 4,030,276,168 29,139,260 21,721,081 (5,308,639)4,032,385,708
41 (344) Generators 591,723,261 4,538,241 1,279,338 594,982,164
42 (345) Accessory Electric Equipment 456,676,770 998,954 (181,570)5,308,639 463,165,933
43 (346) Misc. Power Plant Equipment 25,083,248 (150,806)68,283 24,864,159
44 (347) Asset Retirement Costs for Other Production 47,502,786 420,513 47,923,299
44.1 (348) Energy Storage Equipment - Production
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)5,495,229,207 36,519,138 22,693,919 5,509,054,426
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)(a)13,686,739,920 238,571,133 189,789,032 (2,429,830)(g)13,733,092,191
47 3. Transmission Plant
48 (350) Land and Land Rights 336,993,434 14,288,777 1,708,579 (638,347)348,935,285
48.1 (351) Energy Storage Equipment - Transmission
49 (352) Structures and Improvements 357,271,647 25,732,783 326,711 624,089 383,301,808
50 (353) Station Equipment 2,750,324,187 32,371,588 15,924,454 157,678 2,766,928,999
51 (354) Towers and Fixtures 1,517,407,609 13,253,337 1,459,459 1,529,201,487
52 (355) Poles and Fixtures 1,250,621,690 52,450,381 3,793,472 (624,089)1,298,654,510
53 (356) Overhead Conductors and Devices 1,652,324,459 46,478,960 4,608,308 1,694,195,111
54 (357) Underground Conduit 3,857,985 10,632 3,868,617
55 (358) Underground Conductors and Devices 9,080,617 9,080,617
56 (359) Roads and Trails 12,141,468 12,141,468
57 (359.1) Asset Retirement Costs for Transmission Plant 2,528,190 2,528,190
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)(b)7,892,551,286 184,586,458 27,820,983 (480,669)(h)8,048,836,092
59 4. Distribution Plant
60 (360) Land and Land Rights 76,017,898 1,778,162 1,091,305 1,867,163 78,571,918
61 (361) Structures and Improvements 135,987,493 10,653,193 441,011 24,579 146,224,254
62 (362) Station Equipment 1,198,438,925 65,817,286 7,274,607 80,306 1,257,061,910
63 (363) Energy Storage Equipment – Distribution
64 (364) Poles, Towers, and Fixtures 1,425,923,124 96,291,297 12,822,271 (279,932)1,509,112,218
65 (365) Overhead Conductors and Devices 888,377,419 64,292,444 7,765,193 (121,686)944,782,984
66 (366) Underground Conduit 442,119,714 38,938,521 3,392,654 477,665,581
67 (367) Underground Conductors and Devices 1,025,725,688 67,733,841 4,609,144 1,088,850,385
68 (368) Line Transformers 1,545,518,058 67,010,753 11,175,103 1,601,353,708
69 (369) Services 957,204,238 53,297,939 1,273,210 1,009,228,967
70 (370) Meters 265,165,951 43,779,733 27,269,745 9,541 281,685,480
71 (371) Installations on Customer Premises 8,800,720 99,207 59,830 8,840,097
72 (372) Leased Property on Customer Premises
73 (373) Street Lighting and Signal Systems 63,006,725 1,603,714 1,583,620 63,026,819
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)8,033,617,302 511,296,090 78,757,693 1,579,971 (i)8,467,735,670
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)
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85 6. General Plant
86 (389) Land and Land Rights 23,821,241 1,250,756 25,071,997
87 (390) Structures and Improvements 272,650,424 14,373,611 1,282,220 332,258 286,074,073
88 (391) Office Furniture and Equipment 91,949,178 21,137,105 8,258,185 281,763 105,109,861
89 (392) Transportation Equipment 140,274,020 13,237,218 861,511 83,055 152,732,782
90 (393) Stores Equipment 16,057,936 1,534,790 311,487 274,012 17,555,251
91 (394) Tools, Shop and Garage Equipment 65,027,849 7,428,214 1,972,457 (2,353,011)68,130,595
92 (395) Laboratory Equipment 37,098,364 5,985,671 836,355 1,035,578 43,283,258
93 (396) Power Operated Equipment 215,385,271 18,170,357 2,211,444 (77,645)231,266,539
94 (397) Communication Equipment 504,642,261 32,365,426 11,088,250 134,343 526,053,780
95 (398) Miscellaneous Equipment 10,057,171 (233,916)309,463 483,134 9,996,926
96 SUBTOTAL (Enter Total of lines 86 thru 95)1,376,963,715 115,249,232 27,131,372 193,487 1,465,275,062
97 (399) Other Tangible Property (d)1,822,901 (j)1,822,901
98 (399.1) Asset Retirement Costs for General Plant 39,748 39,748
99 TOTAL General Plant (Enter Total of lines 96, 97, and 98)(e)1,378,826,364 115,249,232 27,131,372 193,487 (k)1,467,137,711
100 TOTAL (Accounts 101 and 106)32,098,209,670 1,123,875,663 375,084,075 (2,429,830)1,211,446 32,845,782,874
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)32,098,209,670 1,123,875,663 375,084,075 (2,429,830)1,211,446 (l)32,845,782,874
FERC FORM No. 1 (REV. 12-05)Page 204-207
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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)13,686,739,920
Less: (317) Asset Retirement Costs for Steam Production 15 (b)163,179,963
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)47,502,786
Revised TOTAL Production Plant $13,476,057,171
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)$7,892,551,286
Less: (359.1) Asset Retirement Costs for Transmission Plant 57 (b)2,528,190
Revised TOTAL Transmission Plant $7,890,023,096
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)$8,033,617,302
Less: (374) Asset Retirement Costs for Distribution Plant 74 (b)1,331,349
Revised TOTAL Distribution Plant $8,032,285,953
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)$1,378,826,364
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 $1,376,963,715
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)$1,106,474,798
Revised TOTAL Production Plant 13,476,057,171
Revised TOTAL Transmission Plant 7,890,023,096
Revised TOTAL Distribution Plant 8,032,285,953
Revised TOTAL General Plant 1,376,963,715
(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 $31,881,804,733
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: 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)$13,733,092,191
Less: (317) Asset Retirement Costs for Steam Production 15 (g)178,869,688
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)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.
(h) Concept: TransmissionPlant
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(2)
(1)
(2)
(1)
(2)
(3)
(4)
(1)
(2)
(3)
(4)
(1)
(1)
(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)$8,048,836,092
Less: (359.1) Asset Retirement Costs for Transmission Plant 57 (g)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.
(i) 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)$8,467,735,670
Less: (374) Asset Retirement Costs for Distribution Plant 74 (g)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.
(j) Concept: OtherTangibleProperty
Account 399.21, Land owned in fee
(k) 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)$1,467,137,711
Less: (399) Other Tangible Property 97 (g)1,822,901
Less: (399.1) Asset Retirement Costs for General Plant 98 (g)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.
(l) 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)$1,128,981,210
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 (g)—
(Less) (102) Electric Plant Sold 102 (g)—
(103) Experimental Plant Unclassified 103 (g)—
Revised TOTAL Electric Plant in Service $32,613,267,699
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)
(1)
(1)
(1)
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(2)
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(3)
(4)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
Name of Lessee
*
(DesignationofAssociatedCompany)
Description of Property Leased Commission Authorization Expiration Date of Lease Balance at End of Year
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43
44
45
46
47 TOTAL
FERC FORM No. 1 (ED. 12-95)
Page 213
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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)
Description and Location of Property Date Originally Included in This Account Date Expected to be used in Utility Service Balance at End of Year
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 95,284,569
3 Field Ai-Field Asset Intelligence and Related Software Implementations 29,229,752
4 Cutler Hydro Relicensing 5,379,906
5 UII Software Upgrade 4,576,373
6 Mobile GIS Software 2,404,322
7 PacifiCorp Public Safety Partner Portal Software 1,368,268
8 APIM-Asset Performance and Investment Management Software 1,223,131
9 Endur Software Upgrade 1,102,948
10 Advanced Weather Forecasting & Analytics Software 1,006,904
11 Production:
12 Wind Plant Equipment Purchases 47,556,196
13 Jim Bridger Coal Combustion Residual Flue Gas Desulfurization Pond 3 28,543,293
14 Lewis River System Relicensing Implementation 18,390,330
15 Foote Creek II-IV Wind 16,153,311
16 Fall Creek Hatchery 8,720,383
17 North Umpqua Pumped Storage 7,545,083
18 Yale Saddle Dam Seismic Remediation 7,418,108
19 Naughton U2 Stator Rewind 6,374,339
20 Toketee Dam Rehabilitation Evaluation 5,885,467
21 Viva Naughton FERC Production Compliance 3,722,494
22 Grace Hydro Unit 3 Overhaul 3,163,270
23 Yale Main Dam In-Situ Instrumentation 3,102,450
24 Cutler Hydro Surge Tank Anchor Upgrades 2,678,058
25 Prospect 3 Hydro - South Fork Flowline Repairs 2,510,064
26 Swift 1 Hydro Spillway Gate Bulkhead 2,507,389
27 TB Flats Wind - Capital Blades Set 2,479,309
28 Swift 1 Hydro Spillway Improvements 2,402,178
29 Yale Dam Spillway Upgrades Evaluation 2,387,159
30 Prior Mountain Wind - Capital Blades Set 2,009,532
31 Soda Hydro Spinning Reserve 1,956,628
32 Hunter Waste Water Pond Liner 1,891,698
33 ILR 4.5 Yale Downstream Fish Passage 1,683,780
34 Swift 1 Hydro Spillway Gate Retrofit 1,583,189
35 Bear River Hydro Flood and Structural Assessment Project 1,555,482
36 Weber Dam Improvements Evaluation 1,492,253
37 Jim Bridger U3 SCR Catalyst Replacement 1,411,403
38 Hunter U2 Generator Field and Exciter Rewinds 1,351,904
39 Hunter U1 Spare Generator Step-Up Transformer Replacement 1,339,859
40 Lemolo 1 Spillway Improvements 1,336,378
41 Ashton Hydro Trash Rake 1,199,796
42 Iron Gate Bridge K6 Life Extension 1,022,298
Description of Project Construction work in progress - Electric (Account 107)
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43 Transmission:
44 Aeolus - Mona 500kV Line 1,125,696,718
45 Boardman - Hemingway 500kV Line 122,169,275
46 Populus - Hemingway 500kV Line 85,475,742
47 Windstar - Shirley Basin 230kV Line 83,459,552
48 Anticline - Populus 500kV Line 60,956,270
49 Anticline 345 kV Phase Shifting Transformers 22,638,420
50 Sams Valley New 500-230kV Substation 20,371,483
51 Oquirrh - Terminal 345kV Line 19,015,749
52 Path C Transmission Improvements 14,535,237
53 Klamath Falls-Snow Goose 230kV No2 Line TPL 9,534,717
54 Q0155 UAMPS Heber Light & Power 5,525,526
55 Lebanon 115 kV Loop Reliability Upgrade 5,350,297
56 Bear River 138kV Conversion 5,256,523
57 Project Specialized, 242 MW Load 5,009,811
58 Q255 Cedar Creek Wind 4,720,165
59 Midvalley Substation - Replace Transformer 4,463,158
60 Central Utah High Voltage Mitigation 4,254,660
61 Snyderville-Park Cty 46kV Rebuild for Wildfire 3,499,252
62 Magna Cap and Tooele-Pine Canyon Rebuild 3,470,764
63 Columbia - Coal Creek Wildfire Mitigation and Restoration 3,303,885
64 Q763 Appaloosa Solar I LLC Interconnection 3,047,836
65 St. Johns (BPA) to Knott 115 kV Line Conversion 2,905,317
66 Tucker 69 kV Tie Line 2,895,083
67 Walla Walla 69 kV Loop Reconfigure and Reconductor 2,620,293
68 Cottonwood-Snyderville 138kV Rebuild for Wildfire 2,509,683
69 Q0835 Rock Creek Wind LLC–Rock Creek Wind I 2,246,963
70 Grantsville Convert to 138 kV 2,193,706
71 Madras Purchase 230-69kV (125 MVA) Transformer 2,001,406
72 Aligned Energy Data Ctrs Propco, 200 MW 1,976,284
73 Lyons Loop into Santiam - New Tie Line 1,768,754
74 Replace Sigurd #6 Trf 345-230kV 450MVA 1,743,996
75 El Monte-Eden 46kV Rebuild for Wildfire 1,714,500
76 North Bench-Northeast 46kV Rebuild for Wildfire 1,611,090
77 Hurricane Sub Spare 230-69 kV-25 MVA Transformer 1,535,039
78 Klamath Falls-Hornet 69 kV Line 9 Reconductor 1,431,602
79 Wasatch Springs 46kV Line Replacements 1,398,136
80 Ben Lomond-Naughton #1 230kV Line Replace Structures 1,385,351
81 North Bench-Medical-McClelland Breaker & Relay Replacements 1,259,070
82 Jim Bridger - Goshen 345kV Line Structures Replacement 1,224,779
83 Midpoint 500kV Series Cap Bank Replacement (IDP)1,204,971
84 Q0777 Hornshadow Solar 1,195,476
85 Malin-Casebeer New 69 kV Line 1,185,207
86 Capitol-North Bench 138kV Line Rebuild for Wildfire 1,131,229
87 Construct Jackalope-Bixby 115kV Line 1,119,062
88 Montpelier Area Voltage Support 1,027,362
89 Distribution:
90 Portland Willamette River Crossing Project 23,174,854
91 Fire High Consequence Area (FHCA) - Rebuild Brighton 12 14,521,132
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92 Conser Road - Constuct New 115kV to 20.8 kV Substation 13,417,603
93 OR Fire Mitigation Distribution Sub Relay Replace Phase 1 5,733,842
94 Cross Hollow Add Distribution Capacity 4,625,428
95 Fire High Consequence Area (FHCA) - Rebuild Olympus 13 4,394,156
96 Stansbury Increase Capacity 4,307,109
97 Krah USA LLC Service Request 4,158,895
98 Fire High Consequence Area (FHCA) - Rebuild Mountain Dell 11 4,091,908
99 Utah Underground Cable Replacement 3,883,148
100 West Weed/Edgewood Distribution Spacer Cable Install 3,746,102
101 Camp Williams Bank #1 Replacement for STASTA, LLC 3,700,566
102 Happy Camp Core 5G16 - Pt 1, 2, 3 3,624,716
103 Utah Transit Authority, 10.24 MW Load 3,470,441
104 RG Lakeview, 50.47 MW Load 3,462,030
105 North Logan Area Greenfld 138-12.5kV Sub 3,372,226
106 Skypark Sub 2nd 138-12kV Transformer 3,256,821
107 California Distribution Spacer Cable Installation 3,173,026
108 Merlin Russel Road Areas 1, 2, 3 - 5R288 3,085,648
109 Olympia Development LLC, 35.92 MW Load 2,917,100
110 118th South 6400 West 2,914,637
111 Nutglade Distribution Spacer Cable Install 2,910,842
112 South Dunsmuir - 7G75 2,894,855
113 Weed North Old Stage Rd Pts 1,2,3 - 5G83 2,828,468
114 Copper Hills Install Second Transformer 2,688,087
115 Oregon Energy Storage Project 2,588,385
116 Fire High Consequence Area (FHCA) - Rebuild Butlerville 16 2,587,921
117 Snarr Bank 1 - Capacity Increase 2,581,756
118 MW California Expulsion Fuse Replacement 2,515,641
119 Flint Substation - Construct New 115-12.5kV Substation 2,463,563
120 Calif Fire Mitigation CA-D Sub Relay 2,302,988
121 MW Oregon 2022 Expulsion Fuse Replacement 2,207,755
122 Washington Distribution Spacer Cable Install 2,202,448
123 Aligned Energy Data Centers SLC, 20 MW 2,199,975
124 West Valley Install Second Transformer 2,175,510
125 Hoy Road Distribution Spacer Cable Install 1,947,386
126 Utah-Distribution Mandated Wildfire Mitigation 1,943,424
127 Russellville Distribution Automation Project - FLISR 1,893,223
128 Weed Shastina Drive - Pt 1, 2 - 5G45 1,881,734
129 Selma McMullin Creek Road - 5R65 1,841,307
130 Nibley - Constuct new 25Kv Circuit 1,839,402
131 North Weed Distribution Spacer Cable Install 1,819,218
132 Syracuse 138-13.2 kV Transformer 1,762,795
133 BDO Sub: Install 2nd 138-12kV Transformer 1,729,397
134 Timp Sub 2nd 138-12.5 kV 30 MVA Transformer 1,694,210
135 EX Utah Development, 19.03 MW Load 1,644,107
136 Siskiyou Lake Distribution Spacer Cable Install 1,637,012
137 Fire High Consequence Area (FHCA) - Rebuild New Harmony 11 1,605,294
138 Weed College of the Siskiyous - 5G83 1,573,716
139 Lassen Substation - New Substation 1,572,049
140 Little Cottonwood Canyon Undergrould Cable Replacement 1,442,327
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141 90th South Install 30 MVA Transformer 1,397,509
142 Oregon Distribution Spacer Cable Installation 1,393,839
143 Rebuild North Salt Lake - NSL11 1,339,145
144 DHIC Little Valley, LLC, 1.8 MVA Load in Magna, UT 1,260,879
145 Sunroc Corporation, 2.01 MW Load 1,207,346
146 Apple Valley: New 69-12.47 kV Substation 1,179,451
147 Medford Distribution Automation Project - FLISR 1,168,750
148 Obrien Redwood Hwy PT 1/2 - 5R106 1,153,028
149 Fire High Consequence Area (FHCA) - Rebuild Columbia 11 1,094,715
150 Salt Lake Dept of Airports - 14.7 MW Load 1,015,307
151 MW - CFCI 2021 California (Communicating Fault Current Indicators)1,002,791
152 Purchase New Spare 138-13.2kV 33MVA Transformer 1,001,625
153 General:
154 North Temple Campus Redevelopment 4,290,885
155 AMI System Hardware Replacement 3,721,149
156 Bend Juniper Ridge Service Center 3,126,688
157 Ogden Service Center - New Technician Operations Building 1,675,492
158 Rock Springs Operations Consolidation 1,301,474
159 Miscellaneous Projects each under $1,000,000 280,110,313
43 Total 2,476,435,222
FERC FORM No. 1 (ED. 12-87)
Page 216
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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.
LineNo.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 10,763,643,074 10,763,643,074
2 Depreciation Provisions for Year, Charged to
3 (a)1,016,353,629 1,016,353,629
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 256,234 256,234
9.3 Account 182.3, Other Regulatory Assets: asset retirement obligations asset depreciation 21,989,009 21,989,009
9.4 Account 182.3, Other Regulatory Assets: depreciation deferrals 7,436,908 7,436,908
9.5 Transportation depreciation allocated to operations and maintenance expense based on usage activity 23,520,027 23,520,027
9.6 Account 503, Steam from other sources: Blundell depreciation 2,495,158 2,495,158
10 1,072,050,965 1,072,050,965
11 Net Charges for Plant Retired:
12 (322,447,354)(322,447,354)
13 (70,753,061)(70,753,061)
14 2,960,468 2,960,468
15 (390,239,947)(390,239,947)
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 (1,133,517)(1,133,517)
17.3 Other items include:9,805,771 9,805,771
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
17.8 Transfer of retired Klamath generating plant assets unrecovered net book value to Intangible Plant
18 (534,481)(534,481)
19 11,453,591,865 (c)11,453,591,865
Section B. Balances at End of Year According to Functional Classification
20 4,482,492,347 (d)4,482,492,347
21
22 440,043,652 (e)440,043,652
23
24 583,777,958 (f)583,777,958
25 2,146,262,364 (g)2,146,262,364
26 3,236,081,637 (h)3,236,081,637
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
Distribution
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27
28 564,933,907 (i)564,933,907
29 11,453,591,865 (j)11,453,591,865
FERC FORM No. 1 (REV. 12-05)Page 219
Regional Transmission and Market Operation
General
TOTAL (Enter Total of lines 20 thru 28)
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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 $4,372,506,495
Nuclear Production 21 (c)—
Revised Hydraulic Production - Conventional 440,043,652
Hydraulic Production - Pumped Storage 23 (c)—
Revised Other Production 582,571,086
Revised Transmission 2,146,075,860
Revised Distribution 3,234,824,181
Regional Transmission and Market Operation 27 (c)—
Revised General 565,097,827
Revised TOTAL $11,341,119,101
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)$4,482,492,347
Less: Asset retirement obligations related cost components 109,985,852
Revised Steam Production $4,372,506,495
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)$440,043,652
Less: Asset retirement obligations related cost components —
Revised Hydraulic Production - Conventional $440,043,652
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)$583,777,958
Less: Asset retirement obligations related cost components 1,206,872
Revised Other Production $582,571,086
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)$2,146,262,364
Less: Asset retirement obligations related cost components 186,504
Revised Transmission $2,146,075,860
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)$3,236,081,637
Less: Asset retirement obligations related cost components 1,257,456
Revised Distribution $3,234,824,181
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)$564,933,907
Less: Asset retirement obligations related cost components (163,920)
Revised General $565,097,827
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)
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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 $4,372,506,495
Nuclear Production 21 (c)—
Revised Hydraulic Production - Conventional 440,043,652
Hydraulic Production - Pumped Storage 23 (c)—
Revised Other Production 582,571,086
Revised Transmission 2,146,075,860
Revised Distribution 3,234,824,181
Regional Transmission and Market Operation 27 (c)—
Revised General 565,097,827
Revised TOTAL $11,341,119,101
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)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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.
LineNo.(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 52,659,175 18,924,173 71,583,348
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 9,158,653 (493,763)(b)10,893,719
42 Total Cost of Account 123.1 $53,999,001 Total 115,816,829 18,430,410 136,476,068
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 Revenuesfor Year
Amount of
Investmentat End ofYear
Gain orLoss fromInvestmentDisposed
of
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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.
(b) Concept: InvestmentInSubsidiaryCompanies
During the year ended December 31, 2022, Trapper Mining Inc., a subsidiary of PacifiCorp, (Trapper) paid a distribution of $116,881 to PacifiCorp. Also during the year ended December 31, 2022, PacifiCorp recorded an increase in its investment in Trapper of $2,345,710 as a result of Tri-State Generation and Transmission Association, Inc. terminating its membership in Trapper.
FERC FORM No. 1 (ED. 12-89)
Page 224-225
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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.
LineNo.Account(a)Balance Beginning of Year(b)Balance End of Year(c)Department or Departments which Use Material(d)
1 Fuel Stock (Account 151)192,078,435 133,979,566 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)203,514,526 251,987,732 Electric
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)63,327,074 65,271,248 Electric
8 Transmission Plant (Estimated)815,425 1,327,748 Electric
9 Distribution Plant (Estimated)14,220,942 21,774,345 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)281,877,967 340,361,073
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 473,956,402 474,340,639
FERC FORM No. 1 (REV. 12-05)
Page 227
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
LineNo.(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)(l)(m)
1 Balance-Beginning of Year 1,336,572 156,646 156,645 156,647 4,072,412 5,878,922
2
3 Acquired During Year:
4 Issued (Less Withheld Allow)156,645 156,645
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 22,110 22,110
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 1,314,462 156,646 156,645 156,647 4,229,057 6,013,457
30
31 Sales:
32 Net Sales Proceeds(Assoc. Co.)
33 Net Sales Proceeds (Other)
34 Gains
35 Losses
Allowances Withheld (Acct 158.2)
SO2 Allowances Inventory (Account 158.1)No.Amt.No.Amt.No.Amt.No.Amt.No.Amt.No.Amt.
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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
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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 FutureYears 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)
NOx Allowances Inventory (Account 158.1)No.Amt.No.Amt.No.Amt.No.Amt.No.Amt.No.Amt.
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36 Balance-Beginning of Year
37 Add: Withheld by EPA
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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
WRITTEN OFF DURING YEAR
LineNo.(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 Authorizationto 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
WRITTEN OFF DURING YEAR
LineNo.(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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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.
LineNo.(a)(b)(c)(d)(e)
1 Transmission Studies
2 Q0219 1,556 561.6
3 Q2611 3,876 561.6 3,875 456
4 Q2913 166 561.6 166 456
5 Q2914 166 561.6 166 456
6 Q3004-Q3005 166 561.6 166 456
7 Q3032 3,731 561.6 3,730 456
8 Q3033 350 561.6 350 456
9 Q3034 3,247 561.6 3,247 456
10 Q3048 4,787 561.6 4,787 456
11 Q3049 - A 5,582 561.6 5,582 456
12 Q3049 - B 2,908 561.6 2,908 456
13 Q3050 4,439 561.6 4,439 456
14 Q3055 961 561.6
15 Q3065 166 561.6 166 456
16 Q3081 3,445 561.6
17 Q3088 - A 1,110 561.6
18 Q3088 - B 7,549 561.6
19 Q3089 - A 1,210 561.6
20 Q3089 - B 3,522 561.6
21 Q3090 514 561.6
22 Q3091 2,054 561.6
23 Q3092 2,054 561.6
24 Q3093 3,048 561.6
25 Q3094 1,856 561.6
26 Q3097 4,141 561.6
27 Q3102 1,756 561.6
28 Q3109 2,849 561.6
29 Q3112 166 561.6 166 456
30 Q3116 - A 1,458 561.6 1,458 456
31 Q3116 - B 2,220 561.6 2,220 456
32 Q3117 961 561.6 961 456
33 Q3124 6,324 561.6
34 Q3128 762 561.6
35 Q3134 - A 5,830 561.6 5,830 456
36 Q3134 - B 37 561.6 37 456
37 Q3135 3,346 561.6 3,346 456
38 Q3143 7,420 561.6
39 Q3163 1,856 561.6
40 Q3165 216 561.6
Description Costs Incurred During Period Account Charged Reimbursements Received During the Period Account Credited With Reimbursement
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41 Q3170 1,259 561.6
42 Customer Studies Accrual 27,111 561.6
43 Adjustments 11,575 561.6
20 Total 137,750 43,600
21 Generation Studies
22 Customer Studies Accrual 4,050 561.7 4,050 456
23 GIQ0789 207 561.7 207 456
24 SGIQ1191 473 561.7 473 456
25 LGIQ0731 12,278 561.7 12,278 456
26 LGIQ0838 16,840 561.7 16,840 456
27 LGIQ0787 - A 184 561.7 184 456
28 LGIQ0824 16,788 561.7 16,788 456
29 OCSGIQ0062 - A 769 561.7 769 456
30 OCSGIQ0063 - A 1,090 561.7 1,090 456
31 SGIQ0815 458 561.7 458 456
32 LGIQ0805 117 561.7 117 456
33 GIQ0823 866 561.7
34 OCSGIQ0048 2,266 561.7 2,266 456
35 LGIQ0951 2,124 561.7 2,124 456
36 GIQ1068 143 561.7 143 456
37 GIQ1069 143 561.7 143 456
38 GIQ1071 471 561.7 471 456
39 GIQ1117 551 561.7 551 456
40 GIQ1149 279 561.7 279 456
41 GIQ1150 121 561.7 121 456
42 GIQ1151 121 561.7 121 456
43 GIQ1175 227 561.7 227 456
44 GIQ1234 245 561.7 245 456
45 OCSGIQ0071 223 561.7 223 456
46 OCSGIQ0058 164 561.7 164 456
47 OCSGIQ0078 102 561.7 102 456
48 OCSGIQ0074 245 561.7 245 456
49 OCSGIQ0070 182 561.7 182 456
50 GIQ0905 18,864 561.7 18,864 456
51 GIQ0907 10,108 561.7 10,108 456
52 OCSGIQ0072 286 561.7 286 456
53 OCSGIQ0076 204 561.7 204 456
54 OCSGIQ0077 123 561.7 123 456
55 LGIQ0906 27,232 561.7 27,232 456
56 LGIQ1065 5,331 561.7 5,332 456
57 OGIQ1126 1,751 561.7 1,751 456
58 GIQ0985 2,162 561.7 2,162 456
59 LGIQ1159 622 561.7 622 456
60 OCSGIQ0062 - B 1,289 561.7 1,289 456
61 OCSGIQ0063 - B 1,231 561.7 1,231 456
62 IS0008 19,926 561.7 19,926 456
63 ISGIQ0009 117 561.7 117 456
64 ISGIQ0010 890 561.7 890 456
65 LGIQ0787 - B 8,503 561.7 8,503 456
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66 LGIQ0016 1,949 561.7 1,949 456
67 PIS0004 5,465 561.7 5,465 456
68 OGIQ0194 5,850 561.7 5,850 456
69 LGIQ1161 2,763 561.7 2,763 456
70 LGIQ1162 1,862 561.7 1,862 456
71 SIS0007 666 561.7 666 456
72 SIS0008 909 561.7 909 456
73 SIS0009 909 561.7 909 456
74 SIS0010 721 561.7 721 456
75 SIS0011 1,033 561.7 1,033 456
76 SIS0012 994 561.7 994 456
77 SIS0013 952 561.7 952 456
78 LGIQ1163 2,991 561.7 2,991 456
79 SGIQ1205 1,862 561.7 1,862 456
80 SGIQ1206 1,737 561.7 1,737 456
81 OGIQ1214 1,571 561.7 1,571 456
82 SIS002 341 561.7
83 SIS003 415 561.7
84 SIS004 451 561.7
85 SIS005 614 561.7
86 SIS006 504 561.7
87 C1-04 3,209 561.7 3,209 456
88 C1-10 2,910 561.7 2,910 456
89 C1-11 2,374 561.7 2,374 456
90 C1-12 2,181 561.7 2,181 456
91 C1-13 2,081 561.7 2,081 456
92 C1-14 2,142 561.7 2,142 456
93 C1-16 2,363 561.7 2,363 456
94 C1-20 2,910 561.7 2,910 456
95 C1-23 294 561.7 294 456
96 C1-26 2,269 561.7 2,269 456
97 C1-27 2,821 561.7 2,821 456
98 C1-34 3,241 561.7 3,241 456
99 C1-35 389 561.7 389 456
100 C1-37 1,605 561.7 1,605 456
101 C1-39 1,303 561.7 1,303 456
102 C1-40 3,579 561.7 3,579 456
103 C1-43 - A 2,743 561.7 2,743 456
104 C1-43 - B 1,414 561.7 1,414 456
105 C1-44 2,448 561.7 2,449 456
106 C1-46 607 561.7 607 456
107 C1-50 1,996 561.7 1,996 456
108 C1-51 1,887 561.7 1,887 456
109 C1-54 1,911 561.7 1,911 456
110 C1-58 1,735 561.7 1,735 456
111 (a)2020 Transition Cluster Area 4 39 561.7 39 456
112 (b)2020 Transition Cluster Area 5 439 561.7 439 456
113 (c)2020 Transition Cluster Area 8 9,591 561.7 9,591 456
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114 (d)2020 Transition Cluster Area 9 83 561.7 83 456
115 2020 Transition Cluster Restudy Area 4 14,133 561.7 14,133 456
116 OATT Cluster Study 2021 6,789 561.7 6,789 456
117 Cluster 2021 - Cluster Area 1 Restudy 6,154 561.7 6,154 456
118 Cluster 2021 - Cluster Area 3 Restudy 13,584 561.7 13,584 456
119 Cluster 2021 - Cluster Area 5 Restudy 18,364 561.7 18,364 456
120 Cluster 2021 - Cluster Area 6 Restudy 13,967 561.7 13,968 456
121 Cluster 2021 - Cluster Area 7 Restudy 34,827 561.7 34,827 456
122 Cluster 2021 - Cluster Area 12 Restudy 17,647 561.7 17,647 456
123 OATT Cluster Study CY2022 183,589 561.7 183,589 456
124 2022 Cluster Study Report Production 785,776 561.7 790,932 456
125 ESM Cluster Study 2 200,496 561.7
126 Pre-Application Studies - East 3,827 561.7 3,827 456
127 Pre-Application Studies - West 3,145 561.7 3,145 456
39 Total 1,557,787 1,359,259
40 Grand Total 1,695,537 1,402,859
FERC FORM No. 1 (NEW. 03-07)Page 231
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionOfStudyPerformed
For more information, refer to FERC Docket No. ER20-924, PacifiCorp’s tariff filing per 35.13(a)(2)(iii): Open Access Transmission Tariff Queue Reform.
(b) Concept: DescriptionOfStudyPerformed
For more information, refer to FERC Docket No. ER20-924, PacifiCorp’s tariff filing per 35.13(a)(2)(iii): Open Access Transmission Tariff Queue Reform.
(c) Concept: DescriptionOfStudyPerformed
For more information, refer to FERC Docket No. ER20-924, PacifiCorp’s tariff filing per 35.13(a)(2)(iii): Open Access Transmission Tariff Queue Reform.
(d) Concept: DescriptionOfStudyPerformed
For more information, refer to FERC Docket No. ER20-924, PacifiCorp’s tariff filing per 35.13(a)(2)(iii): Open Access Transmission Tariff Queue Reform.
FERC FORM No. 1 (NEW. 03-07)
Page 231
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
LineNo.(a)(b)(c)(d)(e)(f)
1 DSM Balancing Account - CA 144,945 1,080,227 908 1,152,929 72,243
2 DSM Balancing Account - UT 195,778,387 41,148,417 908 31,457,498 205,469,306
3 DSM Balancing Account - WY 14,829,132 9,159,214 908 5,828,537 18,159,809
4 DSM Balancing Account - OR 302,869 323,531 908 147,477 478,923
5 (a)Deferred Excess Net Power Costs - CA 200,121 8,855,302 555 664,697 8,390,726
6 (b)Deferred Excess Net Power Costs - ID 26,457,131 37,822,862 555 20,448,622 43,831,371
7 (c)Deferred Excess Net Power Costs - OR 44,814 117,384,798 555 47,173 117,382,439
8 (d)Deferred Excess Net Power Costs - UT 90,402,982 186,086,564 555 67,763,137 208,726,409
9 Deferred Excess Net Power Costs - WA 12,941,832 70,199,290 83,141,122
10 (e)Deferred Excess Net Power Costs - WY 20,866,758 74,351,194 555 10,732,968 84,484,984
11 Decoupling Mechanism - WA 140,341 7,349,395 440, 442 470,586 7,019,150
12 Solar Investment Tax Credit Basis Adjustment 403,004 4,656 282, 283 29,709 377,951
13 Corporate Activity Tax - OR 640,516 254 640,516
14 Metro Business Income Tax - OR 25,156 165,479 410.1 171,184 19,451
15 (f)Pension 286,322,590 18,008,100 (r)14,619,870 289,710,820
16 Other Postretirement 754,834 128 17,961 736,873
17 Deferred Steam Depreciation - UT 4,851,954 4,968,631 9,820,585
18 Colstrip Unit No. 4 Deferred Maintenance Costs - WA 258,904 258,904
19 Carbon Plant Inventory (5)1,253,899 407.3 413,391 840,508
20 Carbon Plant Inventory - CA (3)374,723 407.3 345,899 28,824
21 (g)Cholla Unit No. 4 Closure Costs - CA 4,712,974 440, 442, 444 241,182 4,471,792
22 Cholla Unit No. 4 Closure Costs - ID (35,512)(35,512)
23 Cholla Unit No. 4 Closure Costs - OR 471,369 11,527 482,896
24 (h)Cholla Unit No. 4 Closure Costs - UT 8,676,583 407.3 2,993,928 5,682,655
25 (i)Cholla Unit No. 4 Closure Costs - WY 43,876,094 407.3 4,175,154 39,700,940
26 Cholla Unit No. 4 Decommissioning Costs - CA 50,140 23,495 73,635
27 Cholla Unit No. 4 Decommissioning Costs - WY 155,360 440, 442, 444 155,360
28 Depreciation Study Deferral - ID (4)13,940,303 403 3,485,076 10,455,227
29 Depreciation Study Deferral - UT (17)1,216,411 403 128,044 1,088,367
30 Depreciation Study Deferral - WY (18)4,200,813 403 442,191 3,758,622
31 (j)Generating Plant Liquidated Damages - UT 420,000 557 35,000 385,000
32 (k)Generating Plant Liquidated Damages - WY 1,027,264 557 54,291 972,973
33 (l)Wind Test Energy Deferral - WY 221,031 557 7,644 213,387
34 Klamath Hydroelectric Relicensing Costs - UT (10)4,146,486 63,382 404 4,209,868
35 Environmental Costs (10)108,358,475 9,580,800 514, 545, 554, 598, 935 7,353,071 (s)110,586,204
36 Asset Retirement Obligations Regulatory Difference 170,624,721 38,809,634 403, 230, 426.5, 131 3,473,461 205,960,894
37 (m)Unamortized Contract Values 36,447,683 242, 253 18,133,410 18,314,273
Description and Purpose of Other Regulatory Assets Balance at Beginning of Current Quarter/Year Debits Written off During Quarter/YearAccount Charged Written off During the Period Amount Balance at end of Current Quarter/Year
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38 Greenhouse Gas Allowance Compliance Costs - CA 2,917,175 4,651,557 232, 254, 456, 555 2,100,457 5,468,275
39 Emergency Service Resiliency Program - CA 6,104 6,104
40 Solar Feed-In Tariff Deferral - OR (1)4,668,230 4,811,617 555, 908 5,246,625 4,233,222
41 Oregon Community Solar Program 1,946,254 761,189 440, 442, 444 210 2,707,233
42 Solar Incentive Subscriber Program - UT 1,921,232 107,403 908 162,007 1,866,628
43 Renewable Portfolio Standards Compliance - WA 208,933 250,735 459,668
44 Deferred Intervenor Funding Grants - CA 392,138 12,574 404,712
45 Deferred Intervenor Funding Grants - ID 40,000 40,000
46 Deferred Intervenor Funding Grants - OR 2,541,940 486,640 3,028,580
47 Deferred Independent Evaluator Costs - OR 38,523 2,238 40,761
48 Deferred Independent Evaluator Costs - UT 99,740 99,740
49 (n)Catastrophic Event - CA 392,771 924 354,079 38,692
50 Washington Low Income Program 2,606,629 421,563 142 1,209,306 1,818,886
51 Deferred Overburden Cost - ID 649,963 1,857,754 501 2,048,411 459,306
52 Deferred Overburden Cost - WY 1,703,639 4,549,232 501 5,122,848 1,130,023
53 BPA Balancing Account - WA 767,714 767,714
54 BPA Balancing Account - OR 3,611,569 143 2,724,209 887,360
55 BPA Balancing Account - ID 1,007,862 1,007,862
56 Property Sales Balancing Account - OR 2,175,917 970,363 421.1, 440, 442, 444 301,629 2,844,651
57 Property Damage - OR 23,204,982 17,592,335 924 8,602,537 32,194,780
58 Property Damage - WA 18,875 1,629,102 924 1,144,819 503,158
59 Property Damage - CA 1,334,868 1,334,868
60 Miscellaneous Regulatory Assets and Liabilities - OR 453,743 8,204 232 3,145 458,802
61 (o)Utah Mine Disposition 115,733,728 4,032,467 506 4,707,957 115,058,238
62 Preferred Stock Redemption Loss - UT (10)182,255 407.3 82,530 99,725
63 Preferred Stock Redemption Loss - WA (10)28,854 407.3 13,317 15,537
64 Preferred Stock Redemption Loss - WY (10)62,807 407.3 28,441 34,366
65 (p)Mobile Home Park Conversion - CA 217,273 16,197 407.3 26,673 206,797
66 (q)Electric Vehicle and Electrification Programs - OR 5,747,726 1,281,611 415, 456, 431 6,422,540 606,797
67 Transportation Electrification Program - WA 588,044 203,488 791,532
68 Fire Hazard and Wildfire Mitigation Plan - CA 22,268,273 12,338,145 34,606,418
69 Wildfire Mitigation and Vegetation Management Plans - OR 70,046,726 70,046,726
70 Wildfire Damaged Plant Net Book Value - OR 1,992,140 108 180,088 1,812,052
71 Wildfire Natural Disaster Plan - CA 83,417 83,417
72 Wildland Fire Mitigation Balancing Account - UT 6,369,454 440, 442, 444, 431, 419 1,538,647 4,830,807
73 AMI Replaced Meters - OR (5)13,863,240 406,382 407.3 2,915,651 11,353,971
74 COVID-19 Bill Assistance Program - OR 10,819,673 1,660,460 12,480,133
75 COVID-19 Bill Assistance Program - WA 3,006,060 95,266 3,101,326
76 Equity Advisory Group for Clean Energy Implementation Plan - WA 535,334 380,936 916,270
77 Low-Carbon Energy Standards - WY 581,607 581,607
78 Low Income Bill Discount Admin Cost - OR 394,588 394,588
79 Utility Community Advisory Group - OR 84,451 84,451
80 Distribution System Plan - OR 994,544 994,544
81 TB Flats - OR 6,040,426 6,040,426
82 Arrearage Payments Program - CA 2,034,439 131 1,807,096 227,343
44 TOTAL 1,278,010,867 775,802,036 246,583,056 1,807,229,847
FERC FORM No. 1 (REV. 02-04)Page 232
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average life is approximately one year.
(b) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average life is approximately one year.
(c) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average life is approximately one year.
(d) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average life is approximately one year.
(e) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average life is approximately one year.
(f) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is 18 years. Substantially represents amounts not yet recognized as a component of net periodic benefit cost.
(g) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is approximately three years.
(h) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is approximately two years.
(i) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is approximately 10 years.
(j) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is 11 years.
(k) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is 21 years.
(l) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is 28 years.
(m) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is one year. Represents frozen values of contracts previously accounted for as derivatives and recorded at fair value.
(n) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average life is approximately one year.
(o) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
$102 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 life of two years.
(p) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is seven years.
(q) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is two years.
(r) 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.
(s) Concept: OtherRegulatoryAssets
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item Ref. Line No.Other Regulatory Assets
(a)(Column)(f)
Environmental Costs 35 (f)110,586,204
Less: Regulatory asset amortization (33,182)
Revised Environmental Costs 110,553,022
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.
FERC FORM No. 1 (REV. 02-04)Page 232
(1)
(1)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
LineNo.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 Lacomb Irrigation (24)3,810 557 3,810
2 Bogus Creek (41)746,480 557 41,280 705,200
3 (a)Mead Phoenix Availability and Transmission Charge 555,253 565 555,253
4 Point-to-Point Transmission 1,561,896 2,415,195 131, 142 19,568 3,957,523
5 Hermiston Swap (40)2,503,858 557 171,693 2,332,165
6 Deferred Coal Costs - Wyodak Settlement (22)335,180 501 335,180
7 (b)Long-Term Lease Commissions Prepaids 7,810 589, 931 6,694 1,116
8 Lake Side Maintenance Prepaid 15,061,682 6,316,971 21,378,653
9 Lake Side 2 Maintenance Prepaid 23,993,982 5,822,394 29,816,376
10 Chehalis Maintenance Prepaid 27,576,562 4,778,584 107 22,816,458 9,538,688
11 Currant Creek Maint. Prepaid 1,197,958 6,414,875 7,612,833
12 Seven Mile Hill Maintenance Prepaid 3,333,334 1,359,871 107 874,835 3,818,370
13 Seven Mile Hill II Maintenance Prepaid 657,642 267,853 107 50,077 875,418
14 Dunlap Ranch I Maintenance Prepaid 2,287,055 1,524,704 107 42,113 3,769,646
15 Ekola Flats Maintenance Prepaid 1,469,192 1,521,576 2,990,768
16 Foote Creek Maintenance Prepaid 328,072 456,781 784,853
17 Glenrock I Maintenance Prepaid 3,331,945 1,359,871 107 910,472 3,781,344
18 Glenrock III Maintenance Prepaid 1,339,267 535,707 107 275,662 1,599,312
19 Goodnoe Hills Maintenance Prepaid 2,189,546 1,104,178 107 114,381 3,179,343
20 High Plains Maintenance Prepaid 3,399,677 1,359,871 107 1,173,806 3,585,742
21 Leaning Juniper Maintenance Prepaid 3,212,092 1,380,475 107 390,223 4,202,344
22 Marengo Maintenance Prepaid 3,072,041 1,713,866 107 96,042 4,689,865
23 Marengo II Maintenance Prepaid 1,519,347 856,933 107 48,021 2,328,259
24 McFadden Ridge I Maintenance Prepaid 978,695 391,478 107 58,291 1,311,882
25 Pryor Mountain Maintenance Prepaid 49,828 4,515,150 4,564,978
26 Rolling Hills Maintenance Prepaid 3,349,354 1,359,871 107 598,522 4,110,703
27 TB Flats Maintenance Prepaid 4,589,494 4,589,494
28 (c)Credit Agreement Costs 1,622,543 574,649 427, 431 679,835 1,517,357
29 (d)PCRB Mode Conversion Costs 221,250 427 68,978 152,272
30 1994 Series Restructuring Costs (16)166,514 427 58,770 107,744
31 Deferred S-3 Shelf Registration Costs 38,617 181 38,617
32 Emission Reduction Credits 306,510 306,510
33 Sales of Electric Utility Facilities and Properties 61,240 61,240
34 IT Licenses and Maintenance Prepaid 108,487 108,487
35 Other Deferred Charges 500,732 589,518 131 537,750 552,500
47 Miscellaneous Work in Progress
48 Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49 TOTAL 107,087,451 128,330,985
FERC FORM No. 1 (ED. 12-94)Page 233
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionOfMiscellaneousDeferredDebits
The amortization period will end when the Cholla Plant Unit 4 has been retired from service and all costs of terminating Unit 4 have been paid.The Cholla Plant Unit 4 was retired from service on December 31, 2020.
(b) Concept: DescriptionOfMiscellaneousDeferredDebits
The weighted average remaining life is less than one year.
(c) Concept: DescriptionOfMiscellaneousDeferredDebits
The weighted average remaining life is three years.
(d) Concept: DescriptionOfMiscellaneousDeferredDebits
The weighted average remaining life is two years.
FERC FORM No. 1 (ED. 12-94)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 67,616,048 59,371,205
3 State Carryfowards 73,272,201 73,141,764
4 Asset Retirement Obligations 72,638,523 79,214,493
5 Regulatory Liabilities 403,728,517 421,123,607
6 Loss Contingencies 34,476,231 45,033,428
7 Other 64,700,056 53,317,506
8 Valuation Allowances (15,010,255)(35,417,465)
7 Other
8 TOTAL Electric (Enter Total of lines 2 thru 7)701,421,321 695,784,538
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)701,421,321 695,784,538
Notes
FERC FORM NO. 1 (ED. 12-88)
Page 234
Description and Location Balance at Beginning of Year Balance at End of Year
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 amountoutstanding without reduction for amounts held
by respondent) Shares
(e)
Outstanding per Bal. Sheet (Total amountoutstanding without reduction for
amounts held by respondent) Amount
(f)
Held by
RespondentAsReacquiredStock (Acct217) Shares
(g)
Held by
RespondentAsReacquiredStock (Acct217) Cost
(h)
Held by
RespondentIn Sinkingand OtherFundsShares
(i)
Held by
RespondentIn Sinkingand OtherFundsAmount
(j)
1 Common Stock (Account 201)
2 (a)(b)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 (c)6.00% Series 100.00 5,930 593,000
11 (d)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 (e)Authorized and Unissued Capital Stock
3 Total
FERC FORM NO. 1 (ED. 12-91)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: CapitalStockDescription
This class of stock is not redeemable.
(b) 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.
(c) Concept: CapitalStockDescription
This series of preferred stock is not redeemable.
(d) Concept: CapitalStockDescription
This series of preferred stock is not redeemable.
(e) Concept: CapitalStockDescription
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.
FERC FORM NO. 1 (ED. 12-91)Page 250-251
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:2023-04-18 Year/Period of ReportEnd of: 2022/ 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:2023-04-18 Year/Period of ReportEnd of: 2022/ 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)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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.
LineNo.(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 300,000,000 8,850,000
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
20 (a)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 4,904,167
21 Secured Medium-Term Notes: 8.26% Series C due 2022 5,000,000 33,243 01/08/1992 01/07/2022 01/08/1992 01/07/2022 6,883
22 Secured Medium-Term Notes: 8.27% Series C due 2022 4,000,000 30,594 01/09/1992 01/10/2022 01/09/1992 01/10/2022 8,270
23 Secured Medium-Term Notes: 8.05% Series E due 2022 - A 15,000,000 131,471 09/18/1992 09/01/2022 09/18/1992 09/01/2022 805,000
24 Secured Medium-Term Notes: 8.07% Series E due 2022 8,000,000 70,118 09/09/1992 09/09/2022 09/09/1992 09/09/2022 444,747
25 Secured Medium-Term Notes: 8.12% Series E due 2022 50,000,000 438,238 09/11/1992 09/09/2022 09/11/1992 09/09/2022 2,796,889
26 Secured Medium-Term Notes: 8.11% Series E due 2022 12,000,000 105,177 09/11/1992 09/09/2022 09/11/1992 09/09/2022 670,427
27 Secured Medium-Term Notes: 8.05% Series E due 2022 - B 10,000,000 87,648 09/14/1992 09/14/2022 09/14/1992 09/14/2022 565,736
28 Secured Medium-Term Notes: 8.08% Series E due 2022 - A 26,000,000 208,198 10/15/1992 10/14/2022 10/15/1992 10/14/2022 1,651,462
29 Secured Medium-Term Notes: 8.08% Series E due 2022 - B 25,000,000 200,190 10/15/1992 10/14/2022 10/15/1992 10/14/2022 1,587,944
30 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 5,000,000 411,500
31 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 4,000,000 329,200
32 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 27,000,000 1,960,200
33 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 11,000,000 798,600
34 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 15,000,000 1,084,500
35 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 30,000,000 2,172,000
Class and Series of Obligation, Coupon Rate (For new issue, givecommission Authorization numbers and dates)Related Account Number Principal Amount of Debt Issued Total Expense, Premium or Discount Total Expense Total Premium TotalDiscount
Nominal
Date of
Issue
Date ofMaturity
AMORTIZATION
PERIOD Date
From
AMORTIZATION
PERIOD Date
To
Outstanding(Totalamountoutstanding
without
reduction foramountsheld byrespondent)
Interest for
Year
Amount
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36 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 5,000,000 337,500
37 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 2,000,000 135,000
38 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 2,000,000 134,400
39 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 20,000,000 1,350,000
40 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 16,000,000 1,080,000
41 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 12,000,000 810,000
42 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
43
(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 21,260,000 347,134
44
(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 8,190,000 131,792
45
(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 1,889,706
46
(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 15,060,000 258,838
47
(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 82,653
48
(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 22,000,000 369,891
49 Environment Improvement Revenue Bonds - Unsecured: SweetwaterCounty, WY, Series 1995 24,400,000 225,000 12/14/1995 11/01/2025 12/14/1995 11/01/2025 24,400,000 361,465
50 Subtotal 9,897,150,000 81,305,417 (81,560)36,397,000 9,742,150,000 (h)404,320,904
51 Reacquired Bonds (Account 222)
52
53
54
55 Subtotal
56 Advances from Associated Companies (Account 223)
57
58
59
60 Subtotal
61 Other Long Term Debt (Account 224)
62 (i)Long-term debt authorized but unissued
63 Subtotal
33 TOTAL 9,897,150,000 9,742,150,000 404,320,904
FERC FORM No. 1 (ED. 12-96)Page 256-257
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: ClassAndSeriesOfObligationCouponRateDescription
In December 2022, PacifiCorp issued $1.1 billion of its 5.35% First Mortgage Bonds due December 2053. State authorizations for this issuance were as follows: (a) Idaho Public Utilities Commission ("IPUC") – Case No. PAC-E-20-15, Order No. 34831, dated November 12, 2020, effective through September 30, 2025; and (b) Oregon Public Utility Commission ("OPUC") – Docket No. UF-4318, Order No. 20-393, dated November 3, 2020.
(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, 2022, PacifiCorp had regulatory authorization from the OPUC and IPUC to issue an additional $900 million 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, 2022, 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 2023. For further information, refer to Item 6 in Important Changes During the Year in this Form No. 1. Authorization to borrow the proceeds of pollution control revenue refunding bonds issued by the counties of Emery, Utah; Carbon, Utah; Converse, Wyoming; Lincoln, Wyoming; Sweetwater, Wyoming; and Moffat, Colorado (total of $300,345,000 authorized and $166,450,000 available as of December 31, 2022) 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, 2022) 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 groupmembers.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)920,107,831
2 Reconciling Items for the Year
3
4 Taxable Income Not Reported on Books
5 Contribution in Aid of Construction 127,757,058
6 Officer's Life Insurance 1,546,377
7 Regulatory Asset - BPA Balancing Account - OR 1,344,266
8 Regulatory Liability - Bridger Accelerated Depreciation - OR 2,724,209
9 Regulatory Liability - Bridger Accelerated Depreciation - WA 1,700,000
10 Regulatory Liability - California Greenhouse Gas Allowance Compliance 254,931
11 Regulatory Liability - Excess Income Tax Deferral-WY 787,743
12 Regulatory Liability - Fly Ash - OR 3,639,439
13 Regulatory Liability - Renewable Portfolio Standards Compliance - OR 88,048
14 Regulatory Liability - Sale of REC - WA 79,201
15 Regulatory Liability - WA Decoupling Mechanism 3,209,814
16 Regulatory Liability - WA Low Energy Program 677,688
17 Transmission Service Deposit 1,647,063
18 Unearned Joint Use Pole Contact Revenue 2,549,408
9 Deductions Recorded on Books Not Deducted for Return
10 Fed/State Tax Expense-Interest 243,912
11 Accrued Retention 26,987
12 Accrued Royalties 611,617
13 Avoided Costs 61,931,061
14 Book Depreciation 1,084,756,779
15 Book Depreciation Allocated to Medicare and M&E 142,528
16 Capitalized labor and benefit costs 5,446,068
17 Company Plane 72,619
18 CWIP Reserve 297,174
19 Deferred Compensation Mark to Market Gain / Loss 1,467,363
20 Environmental Liability - Non-regulated 11,193
21 Employee Remuneration – Section 162(m) limitation 1,017,509
22 Hermiston Swap 171,693
23 Hydro Relicensing Obligation 1,331,741
24 Income Tax Interest 259
25 Injuries and Damages, net of Insurance 41,938,823
26 Lobbying Expenses 1,345,072
27 Long Term Incentive Plan Mark to Market Gain/Loss 2,487,068
28 Meals and Entertainment 658,727
29 Nondeductible Fringe Benefits 157,365
30 Nondeductible Parking Costs 507,122
31 Operating Leases (Liability)414,762
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32 Prepaid Aircraft Maintenance 16,286
33 Prepaid Taxes - UT PUC 79,870
34 Property Insurance Reserve - WY 12,545
35 Regulatory Asset - Arrearage Payment Program - WA 234,000
36 Regulatory Asset - Carbon Decommissioning - CA 345,899
37 Regulatory Asset - Carbon Plant Decom/Inventory 413,391
38 Regulatory Asset - Catastrophic Event Deferral - CA 354,079
39 Regulatory Asset - Cholla U4 Closure 7,398,737
40 Regulatory Asset - Deferred Overburden Costs - ID 190,656
41 Regulatory Asset - Deferred Overburden Costs - WY 573,616
42 Regulatory Asset - Depreciation Increase - ID 3,485,076
43 Regulatory Asset - Depreciation Increase - UT 128,043
44 Regulatory Asset - Depreciation Increase - WY 442,191
45 Regulatory Asset - Electric Vehicle Charging Infrastructure - UT 5,044,149
46 Regulatory Asset - Environmental Costs - WA 452,930
47 Regulatory Asset - FAS 158 Pension Liability 38,858,101
48 Regulatory Asset - Generating Plant Liquidated Damages - UT 35,000
49 Regulatory Asset - Generating Plant Liquidation Damages - WY 5,708
50 Regulatory Asset - Goodnoe Hills Settlement - WY 21,250
51 Regulatory Asset - Klamath Hydroelectric Relicensing Costs - UT 4,146,486
52 Regulatory Asset - Lake Side Settlement - WY 27,331
53 Regulatory Asset - Meters Replaced by AMI - OR 2,509,269
54 Regulatory Asset - Mobile Home Park Conversion - CA 10,476
55 Regulatory Asset - Post Merger Loss - Reacquired Debt 443,653
56 Regulatory Asset - Post-Retirement Settlement Loss 885,059
57 Regulatory Asset - Preferred Stock Redemption Loss - UT 82,531
58 Regulatory Asset - Preferred Stock Redemption Loss - WA 13,318
59 Regulatory Asset - Preferred Stock Redemption Loss - WY 28,442
60 Regulatory Asset - Solar Feed-In Tariff Deferral - OR 435,008
61 Regulatory Asset - STEP Pilot Program Balance Account - Utah 538,809
62 Regulatory Asset - Subscriber Solar Program - Utah 54,604
63 Regulatory Asset - Transportation Electrification Pilot - CA 10,163
64 Regulatory Asset - Transportation Electrification Pilot - OR 5,140,929
65 Regulatory Asset - Utah Mine Disposition 675,491
66 Regulatory Asset - Wind Test Energy Deferral - WY 7,644
67 Regulatory Liability - 50% Bonus Tax Depr - WY 32,317
68 Regulatory Liability - ARO/Reg Diff - Trojan - WA Portion 116,192
69 Regulatory Liability - Blue Sky - CA 28,565
70 Regulatory Liability - Blue Sky - ID 31,452
71 Regulatory Liability - Blue Sky - WA 52,020
72 Regulatory Liability - Cholla Decommissioning - WY 400,281
73 Regulatory Liability - Clean Fuels Program - OR 4,648,020
74 Regulatory Liability - FAS 158 Post Retirement 9,020,590
75 Regulatory Liability - OR Energy Conservation Charge 3,219,450
76 Regulatory Liability - Plant Closure Cost - WA 1,355,736
77 Regulatory Liability - Steam Decommissioning - WA 3,569,616
78 Regulatory liability - Steam Decommmissioning - ID 2,774,994
79 Regulatory Liability - Steam Decommmissioning - UT 17,053,629
80 Regulatory Liability - Steam Decommmissioning - WY 5,668,840
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81 Reimbursements 2,642,844
82 Reserve for Bad Debts 695,513
83 Sales & Use Tax Audit Exposure 1,056,186
84 Trapper Mine Contract Obligation 2,851,236
14 Income Recorded on Books Not Included in Return
15 Book Fixed Asset Gain/Loss (1,322,710)
16 Corporate Owned Life Insurance (144,896)
17 Dividend Received Deduction - Deferred Compensation (86,424)
18 MCI F.O.G. Wire Lease (34)
19 Regulatory Asset - BPA Balancing Account - ID (1,007,862)
20 Regulatory Asset - BPA Balancing Account - WA (767,714)
21 Regulatory Asset - WA Decoupling Mechanism (6,878,808)
22 Regulatory Liability - Alt Rate for Energy Program (CARE) - CA (593,583)
23 Regulatory Liability - BPA Balancing Account - ID (27,912)
24 Regulatory Liability - BPA Balancing Account - WA (835,010)
25 Regulatory Liability - Deferred Excess NPC - OR (3,918,028)
26 Regulatory Liability - Deferred Excess RECs in Rates - UT (283,340)
27 Regulatory Liability - Depreciation Deferral - OR (2,566,105)
28 Regulatory Liability - Excess Income Tax Deferral-CA (2,513,456)
29 Regulatory Liability - Excess Income Tax Deferral-OR (6,595,554)
30 Regulatory Liability - Excess Income Tax Deferral-WA (1,419,478)
31 Regulatory Liability - OR Direct Access 5 Year Opt Out (1,593,901)
32 Regulatory Liability - Utah Home Energy Lifeline (272,531)
33 Regulatory Liability - WA Deferred Steam Depreciation (17,418,111)
34 Regulatory Liability - WA Rate Refunds (2,145,161)
35 Trapper Mining Stock Basis (307,214)
36 Equity Earnings in Subsidiaries (18,430,409)
37 Fed/State Tax Expense / (Benefit)(63,973,494)
38 Intercompany Adjustment (493,763)
19 Deductions on Return Not Charged Against Book Income
20 Accrued Bonus (95,300)
21 Accrued Final Reclamation (319,639)
22 Accrued Payroll Taxes (12,549,801)
23 Accrued Severance (157,112)
24 Accrued Vacation (430,661)
25 Amortization NOPAs 99-00 RAR (147,716)
26 Basis Intangible Difference (361,035)
27 Bear River Settlement Agreement (146,175)
28 Capitalized Depreciation (10,828,269)
29 Contra Receivable from Joint Owners (207,900)
30 Cost of Removal (73,737,233)
31 Debt AFUDC (31,251,311)
32 Deferred Compensation (2,042,533)
33 Deferred Revenue - Lease Incentives (31,062)
34 Deferred Revenue - Other (343,457)
35 Dividend Deduction at 50%(11)
36 Environmental Liability - Regulated (11,563,253)
37 Equity AFUDC (70,726,611)
38 FAS 112 Book Reserve - Postemployment Benefits (211,749)
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39 FAS 158 Pension Asset (14,973,387)
40 FAS 158 Post-retirement Asset (1,215,850)
41 FAS 158 SERP Liability (1,749,850)
42 Federal Tax Depreciation (1,349,521,462)
43 Federal Tax Fixed Asset Gain/Loss (53,397,099)
44 Fuel Cost Adjustment (1,843,608)
45 Idaho Disallowed Loss (315,396)
46 Regulatory Liability – Injuries and Damages – OR (9,262,303)
47 Inventory Reserve (166,455)
48 Klamath Settlement Obligation (2,377,939)
49 Lease Depreciation - Timing Difference (389,790)
50 Lewis River Settlement Agreement (79,476)
51 Long Term Incentive Plan (2,227,959)
52 Miscellaneous Current and Accrued Liability (2,101,953)
53 N Umpqua Settlement Agreement (688,576)
54 Oregon Regulatory Asset/Regulatory Liability Consolidation (5,059)
55 Penalties (45,998)
56 Pension/Retirement Accrual (125,059)
57 Pre-1943 Preferred Stock Dividend - Deduction (107,935)
58 Prepaid - FSA O& M - East (507,000)
59 Prepaid Membership Fees (385,314)
60 Prepaid Taxes - ID PUC (9,246)
61 Prepaid Taxes - OR PUC (37,823)
62 Prepaid Taxes - Property Taxes (3,303,765)
63 Prepaid Water Rights (155,170)
64 Property Insurance Reserve - CA (1,891,633)
65 Property Insurance Reserve - OR (8,989,798)
66 Property Insurance Reserve - UT (1,110,269)
67 Regulatory Asset - Arrearage Payments Program - CA (227,343)
68 Regulatory Asset - CA Greenhouse Gas Allowance Compliance (2,551,099)
69 Regulatory Asset - Carbon Plant Deferred Depreciation - UT (4,968,631)
70 Regulatory Asset - Cedar Springs II - OR (303,805)
71 Regulatory Asset - Community Solar - OR (760,979)
72 Regulatory Asset - Covid-19 Bill Assist Program - OR (1,660,460)
73 Regulatory Asset - Covid-19 Bill Assist Program - WA (95,266)
74 Regulatory Asset - Deferred Excess NPC - CA (8,190,605)
75 Regulatory Asset - Deferred Excess NPC - ID (17,374,241)
76 Regulatory Asset - Deferred Excess NPC - OR (117,337,626)
77 Regulatory Asset - Deferred Excess NPC - UT (118,323,427)
78 Regulatory Asset - Deferred Excess NPC - WA (70,199,290)
79 Regulatory Asset - Deferred Excess NPC - WY (63,618,226)
80 Regulatory Asset - Deferred Independent Evaluator Fees - OR (2,238)
81 Regulatory Asset - Deferred Intervenor Funding Grants - CA (12,573)
82 Regulatory Asset - Deferred Intervenor Funding Grants - ID (40,000)
83 Regulatory Asset - Deferred Intervenor Funding Grants - OR (486,640)
84 Regulatory Asset - Distribution System Plan - OR (994,544)
85 Regulatory Asset - Emergency Service Program-Battery Storage-CA (376,221)
86 Regulatory Asset - Environmental Costs (2,680,659)
87 Regulatory Asset - Equity Advisory Group - WA (380,936)
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88 Regulatory Asset - FAS 158 Post Retirement Liability (8,953,139)
89 Regulatory Asset - Fire Risk Mitigation - CA (12,427,666)
90 Regulatory Asset - Independent Evaluator Costs - UT (449,485)
91 Regulatory Asset - Low Income Bill Discount - OR (394,588)
92 Regulatory Asset - Low-Carbon Energy Standards - WY (581,607)
93 Regulatory Asset - Pension Settlement - CA (508,432)
94 Regulatory Asset - Pension Settlement - OR (6,660,927)
95 Regulatory Asset - Pension Settlement - UT (5,459,731)
96 Regulatory Asset - Pension Settlement - WA (1,767,797)
97 Regulatory Asset - Pension Settlement - WY (3,088,530)
98 Regulatory Asset - Post Employment Costs (1,580,878)
99 Regulatory Asset - Property Sales Balancing Account - OR (668,734)
100 Regulatory Asset - Renewable Portfolio Standards Compliance - WA (250,735)
101 Regulatory Asset - Solar Incentive Program - UT (538,809)
102 Regulatory Asset - TB Flats - OR (5,736,621)
103 Regulatory Asset - Transportation Electrification Pilot - WA (203,488)
104 Regulatory Asset - Utility Community Advisory Group - OR (84,451)
105 Regulatory Asset - Wildfire Damaged Asset - OR (70,548)
106 Regulatory Asset - Wildfire Mitigation - OR (70,046,727)
107 Regulatory Asset - Wildland Fire Protection - UT (5,828,576)
108 Regulatory Asset/Liability - Demand Side Management (12,077,029)
109 Regulatory Liability - Blue Sky - OR (603,389)
110 Regulatory Liability - Blue Sky - UT (272,422)
111 Regulatory Liability - Blue Sky - WY (41,382)
112 Regulatory Liability - California Energy Savings Assistance (571,431)
113 Regulatory Liability - Cholla Decommissioning - CA (23,495)
114 Regulatory Liability - Cholla Decommissioning - ID (87,881)
115 Regulatory Liability - Cholla Plant Unit No. 4 Decommissioning - OR (386,916)
116 Regulatory Liability - Cholla Plant Unit No. 4 Decommissioning - UT (654,278)
117 Regulatory Liability - Deferred Excess NPC - CA (346,153)
118 Regulatory Liability - Deferred Excess NPC - WA (2,765,908)
119 Regulatory Liability - Klamath River Dams Removal (237)
120 Regulatory Liability - Property Insurance Reserve - WA (484,283)
121 Regulatory Liability - UT Solar Incentive Subscriber Program (53,141)
122 Repairs Deduction (174,458,722)
123 Rogue River - Habitat Enhancement Liability (85,978)
124 ROU Asset (Operating Leases)(352,074)
125 Tax Depletion-SRC (151,532)
126 Tax Percentage Depletion - Blundell Steam Field (417,684)
127 Trojan Decommissioning (219,902)
128 Utah Klamath Relicensing Costs (32,081,215)
129 Wasatch Workers Comp Reserve (131,426)
130 Western Coal Carrier Retiree Medical Accrual (2,079,000)
131 State Tax Deductions 3,929,549
27 Federal Tax Net Income (164,564,966)
28 Show Computation of Tax:
29 Federal Income Tax at 21.00%(34,558,643)
30 Provision to Return Adjustment (385,961)
31 Tax Reserve Changes 2,327
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32 Tax Settlement
33 Renewable Energy Production Tax Credits (185,185,275)
34 Other Federal Tax Credits
35 (a)Federal Income Tax Accrual (220,127,552)
FERC FORM NO. 1 (ED. 12-96)Page 261
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 North Geothermal LLC MHC Investment Company
ABA Management, L.L.C.Energy West Mining Company Mid-America Referral Network, Inc.
AC Eagle Corporation Esslinger-Wooten-Maxwell, Inc.MidAmerican Central California Transco, LLC
AC Palm Desert Corporation E-W-M Referral Services, Inc.MidAmerican Energy Company
AC2015 Corporation F&R/T LLC MidAmerican Energy Machining Services LLC
Aeronavis, LLC Falcon Power Operating Company MidAmerican Energy Services, LLC
Alamo 6 Solar Holdings, LLC Farmington Properties, Inc.MidAmerican Funding, LLC
Alamo 6, LLC FFR, Inc.MidAmerican Geothermal Development Corporation
Alaska Gas Transmission Company, LLC First Network Realty, Inc.MidAmerican Wind Tax Equity Holdings, LLC
Alliance Relocations, Inc.First Realty, Ltd.Midland Escrow Services, Inc.
Alliance Title Group, LLC First Weber Illinois, LLC Mid-States Title Insurance Agency, LLC
Ambassador Real Estate Company First Weber Referral Associates, Inc.Midwest Capital Group, Inc.
American Eagle Referral Service, LLC First Weber, Inc.Midwest Power Midcontinent Transmission Development, LLC
Americana Arizona Referrals, LLC Fishlake Power LLC Midwest Power Transmission Arkansas, LLC
Americana Arizona, LLC Flat Top Holdings, LLC Midwest Power Transmission Iowa, LLC
Americana, L.L.C.Flat Top Wind I, LLC Midwest Power Transmission Kansas, LLC
Apex Home Maintenance, LLC Florida Network LLC Midwest Power Transmission Oklahoma, LLC
ARE Commercial Real Estate, LLC Florida Network Property Management, LLC Midwest Power Transmission Texas, LLC
ARE Iowa, LLC Fluvanna Holdings 2, LLC Midwest Preferred Realty, Inc.
Arizona HomeServices, L.L.C.Fluvanna Wind Energy 2, LLC Midwest Realty Ventures, LLC
Attorneys Title Holdings, Incorporated For Rent, Inc.Modern Transportation Services, Inc.
BDFH, Inc.Fort Dearborn Land Title Company, LLC Modular LNG Holdings, Inc.
Beach Properties of Florida, LLC FRTC, LLC Moholland Transfer, Inc.
Bennion & Deville Fine Homes, Inc.Geronimo Community Solar Gardens Holding Company, LLC Montana Alberta Tie LP Inc.
Berkshire Hathaway Energy Company Geronimo Community Solar Gardens, LLC Montana Alberta Tie US Holdings GP Inc.
BH2H Holdings, LLC Gibraltar Title Services, LLC Morton Bay Geothermal LLC
BHE AC Holding, LLC GPWH Holdings, LLC MPT Heartland Development, LLC
BHE America Transco, LLC Grande Prairie Land Holding, LLC MTL Canyon Holdings, LLC
BHE Canada, LLC Grande Prairie Wind Holdings, LLC NE Hub Partners, L.L.C.
BHE Can-Am Generation LLC Grande Prairie Wind II, LLC NE Hub Partners, L.P.
BHE Community Solar, LLC Grande Prairie Wind, LLC Nebraska Referral, Inc.
BHE Compression Services, LLC Greater Metro, LLC Nevada Electric Investment Company
BHE CS Holdings, LLC Guarantee Appraisal Corporation Nevada Power Company
BHE Gas, Inc.Guarantee Real Estate Niche Storage Solutions, LLC
BHE Geothermal, LLC Hegg Limited Referral Company, LLC NNGC Acquisition, LLC
BHE Glacier Wind 1, LLC HEGG Realtors Iowa, Inc.Northeast Referral Group, LLC
BHE Glacier Wind 2, LLC HEGG, Realtors Inc.Northern Natural Gas Company
BHE GT&S, LLC HN Real Estate Group, L.L.C.Northrop Realty, LLC
BHE Hydro, LLC HN Real Estate Group, N.C., Inc.NRS Referral Services, LLC
BHE Infrastructure Group, LLC HN Referral Corporation NV Energy, Inc.
BHE Infrastructure Services, LLC HomeServices Insurance, Inc.NVE Holdings, LLC
BHE Midcontinent Transmission Holdings, LLC HomeServices Lending, LLC NVE Insurance Company, Inc.
BHE Montana, LLC HomeServices MidAtlantic, LLC NW Referral Services, LLC
BHE Pearl Solar Holdings, LLC HomeServices Northeast, LLC Pacific Minerals, Inc.
BHE Pearl Solar, LLC HomeServices of Alabama, Inc.PacifiCorp
BHE Pipeline Group, LLC HomeServices of America, Inc PCG Agencies, Inc.
BHE Power Watch, LLC HomeServices of Arizona, LLC PCRE, L.L.C.
BHE Ravenswood, LLC HomeServices of California, Inc.PHM Holdings, LLC
BHE Renewables, LLC HomeServices of Colorado, LLC Pickford Escrow Company, Inc.
BHE Rim Rock Wind, LLC HomeServices of Connecticut, LLC Pickford Holdings LLC
BHE Solar, LLC HomeServices of Florida, Inc.Pickford Real Estate, Inc.
BHE Southwest Transmission Holdings, LLC HomeServices of Georgia, LLC Pickford Services Company
BHE Texas Transco, LLC HomeServices of Illinois Holdings, LLC Pilot Butte, LLC
BHE Turbomachinery, LLC HomeServices of Illinois, LLC Pinyon Pines Funding, LLC
BHE U.K. Electric, Inc.HomeServices of Iowa, Inc.Pinyon Pines I Holding Company, LLC
BHE U.K. Inc.HomeServices of Kentucky Real Estate Academy, LLC Pinyon Pines II Holding Company, LLC
BHE U.K. Power, Inc.HomeServices of Kentucky, Inc.Pinyon Pines Projects Holding, LLC
BHE U.S. Transmission, LLC HomeServices of Minnesota, LLC Pinyon Pines Wind I, LLC
BHE Wind Watch, LLC HomeServices of MOKAN, LLC Pinyon Pines Wind II, LLC
BHE Wind, LLC HomeServices of Nebraska, Inc.Pivotal JAX LNG, LLC
BHE WV Holdings, LLC HomeServices of Nevada, LLC Pivotal LNG, LLC
BHE WV Renewables, LLC HomeServices of New York, LLC PNJP, LLC
BHEM Balancing Authority Services, LLC HomeServices of Oregon, LLC PNW Referral, LLC
BHER Flat Top Wind Holdings, LLC HomeServices of Texas, LLC PPW Holdings LLC
BHER Gopher Wind Holdings, LLC HomeServices of the Carolinas, Inc.Preferred Carolinas Realty, Inc.
BHER Independence Wind Holdco, LLC HomeServices of Washington, LLC Prime Alliance Real Estate Services, LLC
BHER IWE Holdco, LLC HomeServices of Wisconsin, LLC Priority Title Corporation
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BHER Mariah Wind Holdings LLC HomeServices Partnership Group, LLC Property Services Northeast, LLC
BHER Market Operations, LLC HomeServices Property Management, LLC Prosperity First Title, LLC
BHER Minerals, LLC HomeServices Referral Network, LLC Prosperity Home Mortgage, LLC
BHER Power Resources, Inc.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, LLC Iowa Realty Co., Inc.Saranac Energy Company, Inc.
California Energy Development Corporation Iowa Title Company SCS Realty Investment Group, LLC
California Energy Yuma Corporation Iroquois GP Holding Company, LLC Sequoia Aviation Corporation
California Utility Holdco, LLC Iroquois, Inc.Sierra Gas Holdings Company
CanopyTitle, LLC JBRC, Inc.Sierra Pacific Power Company
Capitol Title Company Jim Huff Realty, Inc.Silver State Property Holdings, LLC
Carolina Gas Services, Inc.Joe Moholland Inc.Silvermine Ventures LLC
Carolina Gas Transmission, LLC JRHBW Realty, Inc. d/b/a/ RealtySouth SoCal Services & Property Management
CE Electric (NY), Inc Jumbo Road Holdings, LLC Solar San Antonio LLC
CE Generation, LLC Kansas City Title, Inc.Solar Star 3, LLC
CE Geothermal, Inc.Kanstar Transmission, LLC Solar Star 4, LLC
CE International Investments, Inc Kentucky Residential Referral Service, LLC Solar Star California XIX, LLC
CE Leathers Company Kentwood Commercial, LLC Solar Star California XX, LLC
CE Turbo LLC Kentwood Real Estate Cherry Creek, LLC Solar Star Funding, LLC
Combined Van Lines, Inc.Kentwood Real Estate City Properties, LLC Solar Star Projects Holding, LLC
Commonsite, Inc.Kentwood Real Estate DTC, LLC Southwest Settlement Services, LLC
Cordova Energy Company LLC Kentwood Real Estate Services, LLC SSC XIX, LLC
Cove Point GP Holding Company, LLC Kentwood, LLC SSC XX, LLC
Crossroads Moving & Storage, Inc.Kern River Gas Transmission Company Texas Emergency Power Reserve, LLC
CTRE, L.L.C.Keystone Partners, LLC The Escrow Firm, Inc.
Dakota Dunes Development Company KR Holding, LLC The Long & Foster Companies, Inc.
DCCO INC.Lands of Sierra, Inc.The Referral Co.
Del Ranch Company Larabee School of Real Estate, Inc.Thoroughbred Title Services, LLC
Denver Rental, LLC Long & Foster Institute of Real Estate, LLC Tioga Properties, LLC
Desert Valley Company Long & Foster Insurance Agency, LLC TLTC LLC
DesertLink Investments, LLC Long & Foster Mortgage Ventures, Inc.Topaz Solar Farms LLC
Earth Energy Power Link LLC Long & Foster Real Estate, Inc.TPZ Holding, LLC
Eastern Brine, LLC Long & Foster Settlement Services, LLC TRMC LLC
Eastern Energy Field Services, Inc.Lovejoy Realty, Inc.TX Jumbo Road Wind, LLC
Eastern Energy Gas Holdings, LLC Lovejoy Referral Network LLC TX Referral Alliance, Inc.
Eastern Gas Transmission and Storage, Inc M & M Ranch Acquisition Company, LLC Volantes, LLC
Eastern Gathering and Processing Inc.M & M Ranch Holding Company, LLC Vulcan Power Company
Eastern MLP Holding Company II, LLC Magma Land Company I Vulcan/BN Geothermal Power Company
Ebby Halliday Alliance, LLC Magma Power Company Wailuku Holding Company, LLC
Ebby Halliday Properties, Inc.Marshall Wind Energy Holdings, LLC Wailuku Investment, LLC
Ebby Halliday Real Estate, Inc.Marshall Wind Energy LLC Wailuku River Hydroelectric Power Company, Inc.
Edina Financial Services, Inc.MEHC Investment, Inc.Walnut Ridge Wind, LLC
Edina Realty Referral Network, Inc.MES Holding, LLC Watermark Realty Referral, Inc.
Edina Realty Title, Inc.Metro Referral Associates, Inc.Watermark Realty, Inc.
Edina Realty, Inc.Metro Referrals, LLC Weathervane Referral Network, Inc.
Elmore Company MHC Inc.Western Capital Group, LLC
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 Freedom Warehouse Corp.Northern States Agency, Inc.
21 SPC, Inc.Fruit of the Loom Direct, Inc.Noveon Hilton Davis, Inc.
21st Communities, Inc.Fruit of the Loom Trading Company NSS TECHNOLOGIES INC
21st Mortgage Corporation Fruit of the Loom, Inc.Oak River Insurance Company
2K Polymer Systems, Inc.Fruit of the Loom, Inc. (Sub)Old United Casualty Company
ACCRA MANUFACTURING INC FTI MANUFACTURING INC Old United Life Insurance Company
Acme Brick Company FTL Regional Sales Co., Inc.Orien Risk Analysts, Inc.
Acme Building Brands, Inc Garan Central America Corp.Oriental Trading Company, Inc.
Acme Management Company Garan Incorporated OTC Brands, Inc.
Acme Ochs Brick and Stone, Inc.Garan Manufacturing Corp.OTC Direct, Inc.
Acme Services Company, LLC Garan Services Corp OTC Worldwide Holdings, Inc.
Adalet/Scott Fetzer Company Garat Co. Ltd.Particle Sciences, Inc.
AEROCRAFT HEAT TREATING CO INC Gateway Underwriters Agency, Inc.PCC FLOW TECHNOLOGIES HOLDINGS INC
Aero-Hose Corporation GEICO Advantage Insurance Company PCC FLOW TECHNOLOGIES INC.
AEROSPACE DYNAMICS INTERNATIONAL INC GEICO Atlantis Corporation PCC ROLLMET INC
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Affiliated Agency Operations Co.GEICO Casualty Co.PCC STRUCTURALS INC
Affinity Insurance Agency, Inc.GEICO Choice Insurance Company Penn Coal Land, Inc.
Affordable Housing Partners, Inc.GEICO Corporation Perfection Hy-Test Company
AIHL Re LLC GEICO Discovery Corporation PERMASWAGE HOLDINGS, INC.
AIPCF V CHI Blocker Inc GEICO Endeavor Corporation Pine Canyon Land Company
AJF Warehouse Distributors, Inc.GEICO General Insurance Co.Piper Finance Company
Albecca, Inc.GEICO Indemnity Co.Platte River Insurance Company
Alleghany Capital Corporation GEICO Marine Insurance Company Plaza Financial Services Co.
Alleghany Capital Corporation GEICO Perspective Corporation Plaza Resources Co.
Alleghany Corporation GEICO Products, Inc.PLICO
Alleghany Corporation GEICO Secure Insurance Company Precision Brand Products, Inc.
Alpha Cargo Motor Express, Inc Gen Re Intermediaries Corporation PRECISION CASTPARTS CORP
Alu-Forge, Inc General Re Corporation Precision Cutting Technologies, Inc.
Ambucor Health Solutions, Inc.General Re Financial Products Corporation PRECISION FOUNDERS INC
American All Risk Insurance Services Inc.General Re Life Corporation Press Forge Company
American Commercial Claims Administrators Inc General Reinsurance Corporation PRIMUS INTERNATIONAL HOLDING COMPANY
American Dairy Queen Corporation General Star Indemnity Company PRIMUS INTERNATIONAL INC
AmGUARD Insurance Company General Star National Insurance Company Princeton Insurance Company
Andrews Laser Works Corporation Genesis Insurance Company Priority One Financial Services, Inc.
APACE Holding Company LLC Government Employees Financial Corp.PRISM Holdings LLC
ARCTURUS MANUFACTURING CORPORATION Government Employees Insurance Co.PRISM Plastics, Inc.
Artform International Inc.GRD Holdings Corporation Pro Installations, Inc.
ATLANTIC PRECISION INC GREENVILLE METALS INC Procrane Holdings, Inc.
AVIBANK MANUFACTURING INC GUARDco, Inc.Professional Risk Management Services, Inc.
AzGUARD Insurance Company H. H. Brown Shoe Company, Inc.PROGRESSIVE INCORPORATED
Bayport Systems, Inc.H.J. Justin & Sons, Inc.PROTECTIVE COATING INC
Ben Bridge Jeweler, Inc.HACKNEY LADISH INC QS Partners LLC
Benjamin Moore & Co.Halex/Scott Fetzer Company QS Security Services LLC
Benson Industries, Inc.HAMILTON AVIATION INC R.C. Willey Home Furnishings
Benson, Ltd.Hawthorn Life International, Ltd.Radnor Specialty Insurance Company
Berkshire Hathaway Assurance Corporation HeatPipe Technology, Inc.Railserve, Inc.
Berkshire Hathaway Automotive Inc.HELICOMB INTERNATIONAL INC Railsplitter Holdings Corporation
Berkshire Hathaway Credit Corporation Henley Holdings, LLC RATHGIBSON HOLDING CO LLC
Berkshire Hathaway Direct Insurance Company Hoffman Burial Supplies, Inc.Redwood Fire and Casualty Insurance Company
Berkshire Hathaway Finance Corporation Hohmann & Barnard, Inc.RENTCO Trailer Corporation
Berkshire Hathaway Global Insurance Services, LLC Homefirst Agency, Inc.Resolute Management Inc.
Berkshire Hathaway Homestate Insurance Company Homemakers Plaza, Inc.Resurgens Specialty Underwriting, Inc.
Berkshire Hathaway Inc.HOWELL PENNCRAFT, INC.Richline Group, Inc
Berkshire Hathaway Life Insurance Company of Nebraska HUNTINGTON ALLOYS CORPORATION Ringwalt & Liesche Co.
Berkshire Hathaway Specialty Insurance Company IdeaLife Insurance Company Rio Grande, Inc.
BH Columbia Inc.Ingersoll Cutting Tool Company Inc.Rochester Crematory, Inc.
BH Credit LLC Innovative Building Products, Inc Roxell USA, Inc.
BH Finance, Inc.Innovative Coatings Technology Corporation RSUI Group, Inc.
BH Holding H Jewelry Inc.Interco Tobacco Retailers, Inc.RSUI Indemnity Company
BH Holding LLC International Dairy Queen, Inc.RSUI Insurance Exchange RPG, Inc.
BH Holding S Furniture Inc International Insurance Underwriters, Inc.RSUI Insurance Exchange RPG, Inc.
BH Media Group, Inc.Intrepid JSB, Inc.RSUI Surplus Lines Insurance Services, Inc.
BH Shoe Holdings, Inc.IPS Professional Engineers and Architects, PC Sager Electrical Supply Co. Inc
BHA Minority Interest Holdco, Inc.IPS-Integrated Project Services Corp.Santa Fe Pacific Insurance Company
BHG Life Insurance Company Ironwood Plastics Inc Santa Fe Pacific Pipeline Holdings, Inc.
BHG Structured Settlements, Inc.Iscar Metals Inc.Santa Fe Pacific Pipelines, Inc.
BHHC Special Risks Insurance Company ITTI Group USA Holdings Inc.Santa Fe Pacific Railroad Company
BHSF, Inc.ITTI Investment Holdings Inc.Scott Fetzer Financial Group, Inc.
biBERK Insurance Services, Inc.J.L. Mining Company ScottCare Corporation
Blue Chip Stamps, Inc.Jazwares Canada Holdings Inc.See's Candies, Inc.
BMB Machine Enterprises, Inc.Jazwares Canada LP See's Candy Shops, Incorporated
BN Leasing Corporation Johns Manville China, Ltd.Seventeenth Street Realty, Inc.
BNSF Communications, Inc.Johns Manville Corporation SFEG Corp.
BNSF Logistics, LLC Johns Manville, Inc.Shaw Asia Pacific Holdings, LLC
BNSF Railway Company Jordan's Furniture, Inc.Shaw Contract Flooring Services, Inc.
BNSF Spectrum, Inc.Joyce Steel Erection LLC Shaw Diversified Services, Inc.
Boat America Corporation Justin Brands, Inc.Shaw Floors, Inc.
Boat Owners Association of the United States Kahn Ventures, Inc.Shaw Funding Company
Boat/U.S, Inc.KEN'S SPRAY EQUIPMENT, INC.Shaw Industries Group, Inc.
Borsheim Jewelry Company, Inc Kinexo, Inc.Shaw Industries, Inc.
Bourn & Koch, Inc.KITCO Fiber Optics, Inc.Shaw Integrated and Turf Solutions, Inc.
BR Agency, Inc.KLUNE HOLDINGS INC Shaw International Services, Inc.
Brainy Toys, Inc.KLUNE INDUSTRIES INC Shaw Retail Properties, Inc.
Brilliant National Services, Inc.L.A. Terminals, Inc.Shaw Sports Turf California, Inc.
BRITTAIN MACHINE INC LAKELAND MANUFACTURING, INC.Shaw Transport, Inc.
Brooks Sports, Inc.Landmark American Insurance Company Shaw Watershed Holdings, LLC.
Burlington Northern Railroad Holdings, Inc.Larson-Juhl International LLC Shultz Steel Company
Burlington Northern Santa Fe, LLC LeachGarner, Inc.SHX Flooring, Inc.
Business Wire, Inc.Lipotec USA, Inc.SidePlate Systems, Inc.
CALEDONIAN ALLOYS INC LiquidPower Specialty Products, Inc.Smilemakers Canada Inc.
Camp Manufacturing Company LJ AERO HOLDINGS INC Smilemakers, Inc.
Cannon Equipment LLC LJ SYNCH HOLDINGS INC SN Management, Inc.
CANNON MUSKEGON CORPORATION LMG Ventures, LLC Soco West, Inc.
Capitol Facilities Corporation (Wisconsin)Loch Vale Logistics, Inc.Solve Tools
Capitol Indemnity Corporation Los Angeles Junction Railway Company Sonnax Transmission Company
Capitol Specialty Insurance Corporation LSPI Holdings Inc.Southern Energy Homes, Inc.
CapSpecialty, Inc.Lubrizol Advanced Materials Holding Corporation SOUTHWEST UNITED INDUSTRIES INC
Carefree/Scott Fetzer Company Lubrizol Advanced Materials, Inc.SPECIAL METALS CORPORATION
CARLTON FORGE WORKS Lubrizol Global Management, Inc.SPS INTERNATIONAL INVESTMENT COMPANY
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CATA Services Company Lubrizol Inter-Americas Corporation SPS TECHNOLOGIES LLC
Cavalier Homes, Inc.Lubrizol International, Inc.SPS Technologies Mexico LLC
Central States Indemnity Co. of Omaha Lubrizol Life Science, Inc.SSP-SiMatrix Inc.
Central States of Omaha Companies, Inc.Lubrizol Overseas Trading Corporation Stahl/Scott Fetzer Company
CH Industries, Inc.M & C Products, Inc.Star Lake Railroad Company
Charter Brokerage Holdings Corp.M&M Manufacturing, Inc.Summit Distribution Services, Inc.
Chemtool Incorporated M2 Liability Solutions, Inc.SXP SCHULZ XTRUDED PRODUCTS LLC
CJE II Mapletree Transportation, Inc.TBS USA, Inc.
Claims Services, Inc.Marathon Suspension Systems, Inc.Tenn-Tex Plastics, Inc.
Clayton Education Corp.Marmon Beverage Technologies, Inc.TEXAS HONING INC
Clayton Homes, Inc.Marmon Crane Services, Inc.The Ben Bridge Corporation
Clayton Properties Group II, Inc.Marmon Distribution Services, Inc.The BVD Licensing Corporation
Clayton Properties Group, Inc.Marmon Energy Services Company The Duracell Company
Clayton Supply, Inc.Marmon Engineered Components Company The Fechheimer Brothers Co.
Clayton, Inc.Marmon Foodservice Technologies, Inc.The Indecor Group, Inc.
CMH Capital, Inc.Marmon Holdings, Inc.The Lubrizol Corporation
CMH Homes, Inc.Marmon Link Inc The Medical Protective Company
CMH Manufacturing West, Inc.Marmon Railroad Services LLC The Pampered Chef, Ltd.
CMH Manufacturing, Inc.Marmon Renew, Inc.The Scott Fetzer Company
CMH Services Aviation, Inc.Marmon Retail & Highway Technologies Company LLC The Zia Company
CMH Services, Inc.Marmon Retail Products, Inc.Thermoform Plastics, Inc.
CMH Transport, Inc.Marmon Retail Store Equipment LLC THI ACQUISITION INC
Coil Master Corporation Marmon Retail Technologies Company TIMET REAL ESTATE CORPORATION
Columbia Insurance Company Marmon Tubing, Fittings & Wire Products, Inc.TITANIUM METALS CORPORATION
Complementary Coatings Corporation Marmon Water, Inc.TM City Leasing Inc.
Composites Horizons LLC Marmon Wire & Cable, Inc.Tool-Flo Manufacturing, Inc.
Consumer Value Products, Inc.Marmon-Herrington Company Top Five Club, Inc.
Continental Divide Insurance Company Maryland Ventures, Inc..Total Quality Apparel Resources
Cort Business Services Corporation McCarty-Hull Cigar Company, Inc.TPC European Holdings, LTD.
Covington Specialty Insurance Company McLane Beverage Distribution, Inc.TPC North America, Ltd.
CPM Development, LLC McLane Beverage Holding, Inc.Transatlantic Holdings, Inc.
Criterion Insurance Agency McLane Company, Inc.Transatlantic Reinsurance Company
Crown Holdco One, Inc.McLane Eastern, Inc.Transco Railcar Repair Inc
Crown Holdco Two, Inc.McLane Express, Inc.Transco Railway Products Inc.
Crown Parent, Inc.McLane Foods, Inc.Transco, Inc.
CSI Life Insurance Company McLane Foodservice Distribution, Inc.Transportation Technology Services, Inc.
CTB Credit Corp McLane Foodservice, Inc.TransRe Underwriting Managers Agency Ltd.
CTB Inc.McLane Mid-Atlantic, Inc.TRH Holding Corp.
CTB International Corp McLane Midwest, Inc.Triangle Suspension Systems, Inc.
CTB IW INC McLane Minnesota, Inc.Tricycle, Inc.
CTB Midwest Inc McLane Network Solutions, Inc.TS City Leasing Inc
CTB MN Investments McLane New Jersey, Inc.TSE Brakes, Inc.
CTB Technology Holding Inc.McLane Ohio, Inc.TTI JV 1
CTMS North America, Inc.McLane Southern, Inc.TTI JV 2
Cumberland Asset Management, Inc.McLane Suneast, Inc.TTI, Inc.
Cypress Insurance Company McLane Tri-States, Inc.Tucker Safety Products, Inc.
D.I. Properties Inc.McLane Western, Inc.TXFM, Inc.
Daniels-Head General Agency, Inc.MCWILLIAMS FORGE COMPANY U.S. Investment Corporation
Daniels-Head Insurance Agency, Inc. (CA)Medical Protective Finance Corporation U.S. Underwriters Insurance Co.
Daniels-Head Insurance Agency, Inc. (TX)MedPro Group, Inc UCFS Europe Company
Daniels-Head Management Corp.MedPro Risk Retention Services, Inc.UCFS International Holding Company
DCI Marketing Inc.Memorial Monuments & Vaults, Inc.Unified Supply Chain, Inc.
Denver Brick Company Merit Distribution Services, Inc.Uni-Form Components Co.
DESIGNED METAL CONNECTIONS, INC.METALAC FASTENERS INC Union Tank Car Company
Diamond Technology Innovations, Inc.Meyn LLC Union Underwear Co., Inc
DICKSON TESTING CO INC MFS Fleet, Inc.United Consumer Financial Services Company
DL Trading Holdings I, Inc.MH Site Construction, Inc.United Direct Finance, Inc.
DQF, Inc.Midwest Northwest Properties, Inc.United States Aviation Underwriters, Incorporated
DQGC, Inc.Miller Sage Holdings, Inc.United States Liability Insurance Company
Duracell Industrial Operations, Inc.Miller-Sage, Inc.UNIVERSITY SWAGING CORPORATION
Duracell U.S. Operations Inc Mindware Corporation UTLX Company
Easley Custom Plastics, Inc.MiTek Holdings, Inc.Van Enterprises, Inc.
EastGUARD Insurance Company MiTek Inc.Vanderbilt ABS Corp.
Eco Color Company MiTek Industries, Inc.Vanderbilt Mortgage and Finance, Inc.
Ecodyne Corporation MLMIC Insurance Company Vanity Fair, Inc.
Ellis & Watts Global Industries, Inc.MLMIC Services, Inc.Veritas Insurance Group, Inc.
Elm Street Corporation Morgantown-National Supply, Inc.Vesta Intermediate Funding, Inc.
Empire Distributors of Colorado, Inc.Mount Vernon Fire Insurance Company VFI-Mexico, Inc.
Empire Distributors of North Carolina, Inc.Mount Vernon Specialty Insurance Company Visilinx, Inc.
Empire Distributors of Tennessee, Inc.Mouser Electronics, Inc.Vision Retailing, Inc.
Empire Distributors, Inc.Mouser JV 1, Inc VT Insurance Acquisition Sub Inc.
ENVIRONMENT ONE CORPORATION Mouser JV 2 W&W Steel Company
EXACTA AEROSPACE INC MPP Co., Inc.Wayne/Scott Fetzer Company
Executive Jet Management, Inc.MPP Pipeline Corporation WEAVER MANUFACTURING INC
Exponential Technology Group, Inc.MS Property Company Webb Wheel Products, Inc.
Exsif Worldwide, Inc.MW Wholesale, Inc.Wellfleet Insurance Company
ExtruMed, Inc.National Fire & Marine Insurance Company Wellfleet New York Insurance Company
Fair American Insurance and Reinsurance Company National Indemnity Company Western Builders Supply, Inc.
Fair American Select Insurance Company National Indemnity Company of Mid-America Western Fruit Express Company
FATIGUE TECHNOLOGY INC National Indemnity Company of the South Western/Scott Fetzer Company
Financial Services Plus, Inc.National Liability & Fire Insurance Company WestGUARD Insurance Company
Finial Holdings, Inc.Nationwide Uniforms Whittaker, Clark & Daniels, Inc.
Finial Reinsurance Company Nebraska Furniture Mart, Inc.Wilbert Funeral Services, Inc.
First Berkshire Hathaway Life Insurance Company NetJets Aviation, Inc.Wilbert, Inc.
FlightSafety Capital Corp.NetJets Card Holdings, Inc.World Book Encyclopedia, Inc.
FlightSafety Defense Corporation NetJets Card Partners, Inc.World Book, Inc.
FlightSafety Development Corp.NetJets Europe Holdings, LLC World Book/Scott Fetzer Company
FlightSafety International Inc.NetJets Financial Holdings LLC World Investments, Inc.
FlightSafety International Middle East Inc.NetJets Inc.Worldwide Containers, Inc.
FlightSafety New York, Inc.NetJets International, Inc.WPLG, Inc.
FlightSafety Properties, Inc.NetJets Sales, Inc.WWEPL Holdings Corp.
Floors, Inc.NetJets Services, Inc.WYMAN GORDON COMPANY
Focused Technology Solutions, Inc.NetJets U.S., Inc.WYMAN GORDON FORGINGS CLEVELAND INC
Fontaine Commercial Trailer, Inc.New England Asset Management, Inc.WYMAN GORDON FORGINGS INC
Fontaine Engineered Products, Inc.NewCo D&W LLC WYMAN GORDON INVESTMENT CASTINGS INC
Fontaine Fifth Wheel Company NFM Custom Countertops, LLC WYMAN GORDON PENNSYLVANIA LLC
Fontaine Modification Company NFM of Kansas, Inc.Xelix Distribution, Inc.
Fontaine Spray Suppression Company NFM SERVICES, LLC X-L-Co., Inc.
Fontaine Trailer Company LLC NJE Holdings, LLC XTRA Companies, Inc.
Forest River Holdings, Inc.NJI Sales, Inc.XTRA Corporation
Forest River, Inc.Noranco Manufacturing (USA) Ltd.XTRA Finance Corporation
Frasca International, Inc.NorGUARD Insurance Company XTRA Intermodal, Inc.
FERC FORM NO. 1 (ED. 12-96)Page 261
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 have been charged 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 by the inclusion 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 current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts.4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.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 to Accounts 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 sheetaccounts.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 ATBEGINNING OF YEAR BALANCE AT END OFYEAR DISTRIBUTION OF TAXES CHARGED
Line
No.(a)(b)(c)(d)
(e)(f)
(g)(h)(i)
(j)(k)
(l)(m)(n)
(o)
1 0 0 0
2 Subtotal Federal Tax 0 0 0 0
3 Subtotal State Tax 0 0 0 0
4 Subtotal Local Tax 0 0 0 0
5 Subtotal Other Tax 0 0 0 0
6 Property Tax Property Tax Arizona 1,197,572 0 29,263 1,212,203 14,632 0 29,263
7 Property Tax Property Tax California 0 0 3,360,987 3,360,987 0 0 2,997,876 (m)363,111
8 Property Tax Property Tax Colorado 2,240,000 0 1,767,781 2,257,781 1,750,000 0 1,766,738 (n)1,043
9 Property Tax Property Tax Idaho 3,547,708 0 5,042,046 5,623,456 2,966,298 0 4,977,371 (o)64,675
10 Property Tax Property Tax Montana 3,233,042 0 6,391,926 6,437,103 3,187,865 0 6,391,926
11 Property Tax Property Tax New Mexico 0 0 18,903 18,903 0 0 18,903
12 Property Tax Property Tax Oregon 0 20,070,575 42,880,097 45,550,878 0 22,741,356 40,415,212 (p)2,464,885
13 Property Tax Property Tax Utah 869,652 0 53,585,245 64,221,345 548,955 10,315,403 54,077,120 (q)(491,875)
14 Property Tax Property Tax Washington 9,700,000 0 8,645,391 9,345,391 9,000,000 0 8,441,493 (r)203,898
15 Property Tax Property Tax Wyoming 10,382,252 0 23,068,433 21,916,436 11,534,249 0 22,850,693 (s)217,740
16 Goshute Possessory Interest Property Tax Idaho 0 0 31,415 31,415 0 0 31,415
17 Sho-Ban Possessory Interest Property Tax Utah 0 0 298,571 298,571 0 0 298,571
18 Navajo Possessory Interest Property Tax Utah 7,727 0 15,000 7,727 15,000 0 15,000
19 Ute Possessory Interest Property Tax Colorado 0 0 46,678 46,678 0 0 46,678
20 Crow Possessory Tax Property Tax Montana 79,000 0 85,646 164,646 0 0 85,646
21 Umatilla Possessory Interest Property Tax Oregon 0 0 126,065 126,065 0 0 126,065
22 Subtotal Property Tax 31,256,953 20,070,575 145,393,447 160,619,585 0 29,016,999 33,056,759 142,569,970 0 0 2,823,477
23 Subtotal Real Estate Tax 0 0 0 0
24 Federal Unemployment Tax Unemployment Tax 5,852 0 220,477 201,062 25,267 0 (t)220,477
25 Federal Unemployment Tax Unemployment Tax Arizona 0 0 140 141 (1)0 (u)140
26 Unemployment Tax Unemployment Tax California 469 0 13,872 13,983 358 0 (v)13,872
27 Unemployment Tax Unemployment Tax Colorado 0 0 225 633 (408)0 (w)225
28 Unemployment Tax Unemployment Tax Florida 0 0 189 378 (189)0 (x)189
29 Unemployment Tax Unemployment Tax Idaho 747 0 15,936 18,400 (1,717)0 (y)15,936
30 Unemployment Tax Unemployment Tax Nevada 0 0 2,420 2,804 (384)0 (z)2,420
31 Unemployment Tax Unemployment Tax Oregon 54,361 4,497 1,364,325 1,122,978 295,708 4,497 (aa)1,364,325
32 Unemployment Tax Unemployment Tax Texas (7)0 130 191 (68)0 (ab)130
33 Unemployment Tax Unemployment Tax Utah 4,686 0 228,214 251,801 (18,901)0 (ac)228,214
Kind of Tax (See Instruction 5)Type of Tax State Tax Year
TaxesAccrued(Account236)
PrepaidTaxes
(Include in
Account165)
Taxes
Charged
During Year
Taxes PaidDuring Year Adjustments
TaxesAccrued(Account236)
Prepaid
Taxes(IncludedinAccount165)
Electric
(Account
408.1, 409.1)
ExtraordinaryItems(Account409.3)
Adjustmentto Ret.
Earnings
(Account439)
Other
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34 Unemployment Tax Unemployment Tax Washington 14,068 0 68,208 (135,069)217,345 0 (ad)68,208
35 Unemployment Tax Unemployment Tax Minnesota 0 0 5 5 0 (ae)5
36 Unemployment Tax Unemployment Tax Montana 0 0 480 840 (360)0 (af)480
37 Unemployment Tax Unemployment Tax Missouri 0 0 145 145 0 0 (ag)145
38 Unemployment Tax Unemployment Tax South Carolina 0 0 8 27 (19)0 (ah)8
39 Unemployment Tax Unemployment Tax Wyoming 3,674 0 31,680 32,031 3,323 0 (ai)31,680
40 Subtotal Unemployment Tax 83,850 4,497 1,946,454 1,510,345 519,959 4,497 1,946,454
41 Use Tax Sales And Use Tax California 53,471 0 981,561 937,073 97,959 (aj)981,561
42 Use Tax Sales And Use Tax Idaho 4,727 0 191,212 164,205 31,734 (ak)191,212
43 Use Tax A Sales And Use Tax Utah 232,908 0 6,426,483 5,986,814 672,577 (al)6,426,483
44 Use Tax B Sales And Use Tax Utah 0 0 1,056,186 1,056,186 (am)1,056,186
45 Use Tax Sales And Use Tax Washington 33,506 0 592,842 537,945 88,403 (an)592,842
46 Use Tax Sales And Use Tax Wyoming 46,216 0 949,780 883,471 112,525 (ao)949,780
47 Subtotal Sales And Use Tax 370,828 0 10,198,064 8,509,508 0 2,059,384 0 0 0 0 10,198,064
48 Federal Income Tax Income Tax 0 0 (220,127,552) (204,121,999)(a)16,005,553 0 0 (227,053,116)(ap)6,925,564
49 Income Tax Income Tax Arizona 0 0 46,522 33,368 (b)(13,154)0 0 35,694 (aq)10,828
50 Franchise - Income Tax Income Tax California 0 0 (724,136)90,800 (c)814,936 0 0 (815,507)(ar)91,371
51 Income Tax Income Tax Colorado 0 0 (263)(d)263 0 0 (444)(as)181
52 Income Tax Income Tax Idaho 0 0 (455,412)(20)(e)455,392 0 0 (547,008)(at)91,596
53 Corporate License - Income Tax Income Tax Montana 0 0 (74,832)43,966 (f)118,798 0 0 (87,613)(au)12,781
54 Income Tax Income Tax New Mexico 0 0 (25,299)6,197 (g)31,496 0 0 (30,065)(av)4,766
55 Excise - Income Tax Income Tax Oregon 0 0 (3,479,627)319,900 (h)3,799,527 0 0 (4,131,803)(aw)652,176
56 City of Portland - Income Tax Income Tax Oregon 0 0 (9,670)13,200 (i)22,870 0 0 (12,436)(ax)2,766
57 Corporate Activity Tax Income Tax Oregon 0 0 6,713,065 5,869,102 (j)(843,963)0 0 6,713,065
58 Metro Business Income Tax Income Tax Oregon 0 0 (4,302)6,100 (k)10,402 0 0 (4,302)
59 Public Utility Tax Income Tax South Carolina 0 0 25 25 0 0 25
60 Income Tax Income Tax Utah 0 0 (3,079,741)1,162,234 (l)4,241,975 0 0 (3,781,725)(ay)701,984
61 Subtotal Income Tax 0 0 (221,221,222) (196,577,127)24,644,095 0 0 (229,715,235)8,494,013
62 Natural Gas Use Tax Excise Tax Washington 482,922 0 5,964,101 4,554,194 1,892,829 0 (az)5,964,101
63 Forest Excise Tax Excise Tax Washington 0 0 36,675 36,675 0 0 (ba)36,675
64 Subtotal Excise Tax 482,922 0 6,000,776 4,590,869 1,892,829 0 6,000,776
65 Subtotal Fuel Tax 0 0 0 0
66 Subtotal Federal Insurance Tax 0 0 0 0
67 Local Franchise Tax Franchise Tax California 1,376,900 0 1,533,785 1,418,485 1,492,200 1,533,785
68 Local Franchise Tax Franchise Tax Oregon 4,975,359 0 28,407,493 28,095,837 5,287,015 28,407,493
69 Local Franchise Tax Franchise Tax Utah 0 0 7,930 7,930 0 7,930
70 Local Franchise Tax Franchise Tax Washington 0 0 800 800 0 800
71 Local Franchise Tax Franchise Tax Wyoming 287,700 0 1,864,053 1,865,853 285,900 1,864,053
72 Subtotal Franchise Tax 6,639,959 0 31,814,061 31,388,905 7,065,115 31,814,061
73 Subtotal Miscellaneous Other Tax 0 0 0 0
74 Subtotal Other Federal Tax 0 0 0 0
75 KWh Other State Tax Idaho 16,861 0 40,064 38,731 18,194 0 40,064
76 Wholesale Energy Other State Tax Montana 54,000 0 274,079 263,079 65,000 0 274,079
77 Energy License Other State Tax Montana 75,000 0 379,219 369,219 85,000 0 379,219
78 Commerce Tax Other State Tax Nevada 15,000 0 15,714 18,714 12,000 0 15,714
79 Department of Energy Other State Tax Oregon 860,083 1,617,118 1,514,071 0 757,036 1,617,118
80 Public Utility Tax Other State Tax Washington 1,440,000 0 15,481,343 15,321,343 1,600,000 0 15,481,343
81 Business and Occupation Tax Other State Tax Washington 4,000 0 18,970 19,770 3,200 0 18,970
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82 Wind Generation Tax Other State Tax Wyoming 2,091,960 0 2,229,076 2,113,305 2,207,731 0 2,229,076
83 Annual Report Other State Tax Wyoming 0 0 105,475 105,475 0 0 105,475
84 Subtotal Other State Tax 3,696,821 860,083 20,161,058 19,763,707 3,991,125 757,036 20,161,058
85 Subtotal Other Property Tax 0 0 0 0
86 Subtotal Other Use Tax 0 0 0 0
87 Subtotal Other Advalorem Tax 0 0 0 0
88 Subtotal Other License And Fees Tax 0 0 0 0
89 Federal FICA Tax Payroll Tax 13,293,562 24,707 39,590,689 52,256,328 627,923 24,707 (bb)39,590,689
90 Tri-Met Transit Tax Payroll Tax Oregon 411,626 0 1,168,226 1,967,052 (387,200)0 (bc)1,168,226
91 Lane Transit Tax Payroll Tax Oregon 0 0 1,482 1,482 0 0 (bd)1,482
92 Family and Medical Leave Payroll Tax Washington 9,429 0 48,043 56,846 626 0 (be)48,043
93 Subtotal Payroll Tax 13,714,617 24,707 40,808,440 54,281,708 241,349 24,707 40,808,440
94 Subtotal Advalorem Tax 0 0 0 0
95 Subtotal Other Allocated Tax 0 0 0 0
96 Subtotal Severance Tax 0 0 0 0
97 Subtotal Penalty Tax 0 0 0 0
98 Subtotal Other Taxes And Fees 0 0 0 0
40 TOTAL 56,245,950 20,959,862 35,101,078 84,087,500 24,644,095 44,786,760 33,842,999 (35,170,146)70,271,224
FERC FORM NO. 1 (ED. 12-96)
Page 262-263
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
$ (29,425) Account 146, Accounts receivable from other associated companies (814,538) Account 182.3, Other Regulatory Assets, which represents a reclassification of the balance$ (843,963)
(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
$ 143,719 Account 408.2, Taxes other than income taxes, other income and deductions 219,392 Account 107, Construction work in progress$ 363,111
(n) Concept: TaxesIncurredOther
Account 408.2, Taxes other than income taxes, other income and deductions
(o) Concept: TaxesIncurredOther
$ 242 Account 408.2, Taxes other than income taxes, other income and deductions 64,433 Account 107, Construction work in progress$ 64,675
(p) Concept: TaxesIncurredOther
$ 24,998 Account 408.2, Taxes other than income taxes, other income and deductions 178,975 Account 589, Rents 2,260,912 Account 107, Construction work in progress$ 2,464,885
(q) Concept: TaxesIncurredOther
$ 50,183 Account 408.2, Taxes other than income taxes, other income and deductions 304,883 Account 107, Construction work in progress (846,941) Account 419, Interest and Dividend Income$ (491,875)
(r) Concept: TaxesIncurredOther
$ 41,297 Account 408.2, Taxes other than income taxes, other income and deductions 162.601 Account 107, Construction work in progress$ 203,898
(s) Concept: TaxesIncurredOther
$ 2,561 Account 408.2, Taxes other than income taxes, other income and deductions 16,451 Account 589, Rents 198,728 Account 107, Construction work in progress$ 217,740
(t) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(u) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(v) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(w) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(x) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(y) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(z) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(aa) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(ab) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(ac) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(ad) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(ae) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
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(af) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(ag) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(ah) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(ai) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(aj) Concept: TaxesIncurredOther
Charged to same account as related goods.
(ak) Concept: TaxesIncurredOther
Charged to same account as related goods.
(al) Concept: TaxesIncurredOther
Charged to same account as related goods.
(am) Concept: TaxesIncurredOther
$ 706,767 Account 107, Construction work in progress 294,486 Account 589, Rents 54,933 Account 431, Other interest expense$ 1,056,186
(an) Concept: TaxesIncurredOther
Charged to same account as related goods.
(ao) Concept: TaxesIncurredOther
Charged to same account as related goods.
(ap) Concept: TaxesIncurredOther
Account 409.2, Income Taxes - Federal, which represents income tax applicable to other income and deductions.
(aq) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(ar) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(as) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(at) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(au) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(av) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(aw) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(ax) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state 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 151, Fuel stock
(ba) Concept: TaxesIncurredOther
Account 408.2, Taxes other than income taxes, other income and deductions
(bb) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(bc) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(bd) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(be) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.FERC FORM NO. 1 (ED. 12-96)Page 262-263
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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)
AveragePeriod ofAllocationto Income(i)
ADJUSTMENTEXPLANATION(j)
1 Electric Utility
2 3%
3 4%
4 7%
5 10%2,515,150 (a)411.4 1,050,016 1,465,134 39.3 years
6 30 2,472,239 (b)420 153,688 2,318,551 24.0 years
7 Idaho (Pre-2013)19,491 (c)411.4 5,710 13,781 39.3 years
8 Idaho 24,871 (d)420 3,951 20,920 30.0 years
8 TOTAL Electric (Enter Total of lines 2 thru 7)5,031,751 1,213,365 3,818,386
9 Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10 `
11 Idaho (nonutility)6,913,905 190 1,489,376 420 2,343,756 (e)(145,472)5,914,053 30.0 years
47 OTHER TOTAL 6,913,905 1,489,376 2,343,756 (145,472)5,914,053
48 GRAND TOTAL 11,945,656 1,489,376 3,557,121 (145,472)9,732,439
FERC FORM NO. 1 (ED. 12-89)
Page 266-267
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
LineNo.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 5,754,523 131 83,489 374,000 6,045,034
2 Reclamation Costs - Trapper Mine 8,351,853 131 1,074,776 3,752,289 11,029,366
3 Western Coal Carriers Benefits Obligation 8,402,000 131, 557 2,657,747 578,747 6,323,000
4 Deferred Compensation Plans 8,681,202 131 2,761,024 718,491 6,638,669
5 Long-Term Incentive Plan 25,936,127 131 4,126,535 1,898,575 23,708,167
6 Regulated Environmental Liabilities 75,321,198 131, 182.3 16,382,988 4,819,734 63,757,944
7 Non-Regulated Environmental Liabilities 1,600,135 131, 426.5 63,173 74,366 1,611,328
8 (a)Unearned Joint Use Pole Contact Revenue 3,368,763 454 7,550,697 7,805,628 3,623,694
9 Miscellaneous Security Deposits 100,169 100,169
10 (b)Lease Incentives 62,124 931 31,062 31,062
11 Cowlitz/Lewis River Operations and Maintenance (1)133,109 539 330,572 338,509 141,046
12 Employee Housing Security Deposits 21,200 131 2,100 2,500 21,600
13 Cogeneration Bonds - Sunnyside 413,417 413,417
14 Transmission Security Deposits 13,920,990 131 6,836,500 27,382,330 34,466,820
15 Transmission Service Deposits 2,283,559 131, 228.4, 235, 456 1,129,493 2,473,760 3,627,826
16 MCI F.O.G. Wire Lease (1)559,520 454 3,356,946 3,356,912 559,486
17 Unamortized Contract Values 18,314,273 242 18,314,273
18 Accrued Right-of-Way Obligations 1,853,251 120,391 1,973,642
19 (c)Facility Use Fee 741,798 451, 456 163,340 118,136 696,594
20 IT Software Licenses 131 352,754 2,980,865 2,628,111
21 Deer Creek Accrued Royalties 14,848,926 182.3 27,745 626,622 15,447,803
22 Deferred Revenue - Other 16,439 185 155,676 140,535 1,298
23 Vendor Retention 68,708,063 68,708,063
24 Klamath Settlement Obligation 2,377,939 131, 545 2,668,738 290,799
25 Transmission Study Deposits for Financial Security 44,379,660 131 18,250,640 80,204,070 106,333,090
26 Transmission Study Deposits for Site Control 260,000 131 70,000 1,270,000 1,460,000
27 Transmission Deposits for Cluster Studies 131, 456, 561.7 4,492,595 38,211,000 33,718,405
47 TOTAL 237,702,175 90,882,863 246,246,322 393,065,634
FERC FORM NO. 1 (ED. 12-94)
Page 269
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionOfOtherDeferredCredits
The weighted average remaining life is one year.
(b) Concept: DescriptionOfOtherDeferredCredits
The weighted average remaining life is one year.
(c) Concept: DescriptionOfOtherDeferredCredits
The weighted average remaining life is nine years.
FERC FORM NO. 1 (ED. 12-94)Page 269
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023
Year/Period of Report
End of: 2022/ 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
LineNo.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)
AccountCredited
(g)
Amount(h)
AccountDebited
(i)
Amount(j)
Balance atEnd of Year
(k)
1 Accelerated Amortization (Account 281)
2 Electric
3 Defense Facilities
4 Pollution Control Facilities 143,583,856 1,770,913 11,200,225 134,154,544
5 Other
5.1 Other:
8 TOTAL Electric (Enter Total of lines 3 thru 7)143,583,856 1,770,913 11,200,225 134,154,544
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)143,583,856 1,770,913 11,200,225 134,154,544
18 Classification of TOTAL
19 Federal Income Tax 117,070,605 438,204 8,126,361 109,382,448
20 State Income Tax 26,513,251 1,332,709 3,073,864 24,772,096
21 Local Income Tax
FERC FORM NO. 1 (ED. 12-96)
Page 272-273
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
LineNo.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)
AccountCredited
(g)
Amount(h)
AccountDebited
(i)
Amount(j)
Balance atEnd of Year
(k)
1 Account 282
2 Electric 3,054,144,040 621,547,313 501,202,107 182.3,254 3,199,918 182.3,254 9,056,729 3,180,346,057
3 Gas
4 Other (Specify)
5 Total (Total of lines 2 thru 4)3,054,144,040 621,547,313 501,202,107 3,199,918 9,056,729 3,180,346,057
6
7
8
9 TOTAL Account 282 (Total of Lines 5 thru 8)3,054,144,040 621,547,313 501,202,107 3,199,918 9,056,729 3,180,346,057
10 Classification of TOTAL
11 Federal Income Tax 2,508,289,527 432,483,780 332,829,950 1,385,962 6,198,662 2,612,756,057
12 State Income Tax 545,854,513 189,063,533 168,372,157 1,813,956 2,858,067 567,590,000
13 Local Income Tax
FERC FORM NO. 1 (ED. 12-96)Page 274-275
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
LineNo.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 332,001,087 172,679,436 42,908,460 269,402 4,727,790 182.3,
190, 283 2,370,377 182.3,
190, 283 6,464,002 461,407,300
4 Other 50,540,917 12,421,237 7,774,052 257,259,214 204,423,785 190, 283 6,462,857 190, 283 2,363,073 103,923,747
9 TOTAL Electric (Total of lines 3 thru 8)382,542,004 185,100,673 50,682,512 257,528,616 209,151,575 8,833,234 8,827,075 565,331,047
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)382,542,004 185,100,673 50,682,512 257,528,616 209,151,575 8,833,234 8,827,075 565,331,047
20 Classification of TOTAL
21 Federal Income Tax 312,127,790 149,803,681 40,206,294 212,140,773 172,699,471 7,282,452 7,277,430 461,161,457
22 State Income Tax 70,414,214 35,296,992 10,476,218 45,387,843 36,452,104 1,550,782 1,549,645 104,169,590
23 Local Income Tax
NOTES
FERC FORM NO. 1 (ED. 12-96)Page 276-277
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
LineNo.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 DSM Balancing Account - ID 180,721 440, 442, 444 4,144,282 5,173,306 1,209,745
2 DSM Balancing Account - WA 3,349,563 440, 442, 444 13,714,526 13,733,421 3,368,458
3 Oregon Energy Conservation Charge 3,879,268 440, 442, 444 55,312,943 58,532,393 7,098,718
4 (a)Deferred Excess Net Power Costs - CA 2,337,036 555.0 346,153 1,990,883
5 (b)Deferred Excess Net Power Costs - WA 2,765,908 555, 419, 431 5,315,791 2,549,883
6 (c)Deferred Excess RECs in Rates - UT 1,325,405 456 1,422,130 1,138,791 1,042,066
7 Deferred Excess RECs in Rates - WA 39,819 79,201 119,020
8 (d)Deferred Excess RECs in Rates - WY 441,206 456 165,065 20,167 296,308
9 Decoupling Mechanism - WA 331,751 3,209,814 3,541,565
10 (e)Investment Tax Credit 674,938 190 281,115 135 393,958
11 (f)Deferred Income Tax Electric 1,306,118,856 190, 282, 411.1 152,016,415 9,070,979 1,163,173,420
12 Corporate Activity Tax - OR 409.1 761,825 935,846 174,021
13 (g)Excess Income Tax Deferral 19,158,352 440, 442, 444 13,290,673 3,439,873 9,307,552
14 Tax on Bonus Depreciation - WY 344,484 32,317 376,801
15 (h)Other Postretirement 26,296,471 128 30,317 9,050,907 35,317,061
16 (i)Postemployment Costs 8,555,713 1,421,128 9,976,841
17 Revenues Subject to Refund - WA 2,847,187 440, 442, 444 2,145,161 702,026
18 Bridger Mine Depreciation and Reclamation - OR 3,639,439 3,639,439 7,278,878
19 Bridger Mine Depreciation and Reclamation - WA 2,549,408 2,549,408 5,098,816
20 Cholla Unit No. 4 Closure and Decommissioning Costs - ID 2,518,308 131 87,881 2,430,427
21 Cholla Plant Unit No. 4 Decommissioning Costs - OR 8,357,894 131 386,916 7,970,978
22 Cholla Plant Unit No. 4 Decommissioning Costs - UT 19,048,498 131 654,278 18,394,220
23 Cholla Plant Unit No. 4 Decommissioning Costs - WY 131 372,907 617,828 244,921
24 Deferral of Coal Plant Closure Costs - WA 1,355,736 1,355,736 2,711,472
25 Klamath Hydro Dam Removal - CA 261,298 232 237 261,061
26 (j)Unrealized Gain on Derivative Contracts 53,042,179 217,381,809 270,423,988
27 (k)Greenhouse Gas Allowance Compliance Costs - CA 6,204,855 456 71,527 1,718,591 7,851,919
28 Emergency Service Resiliency Program - CA 614,181 908 376,221 237,960
29 Solar Incentive Program - UT 1,448,448 440, 442, 444 627,325 35,375 856,498
30 STEP Pilot Program - UT 10,862,491 598 3,499 542,308 11,401,300
31 Renewable Portfolio Standards Compliance - OR (1)287,530 555 827,192 693,901 154,239
32 Deferred Independent Evaluator Costs - UT 349,745 131 349,745
33 Alternative Rate For Energy (CARE) - CA 625,982 921, 922, 923, 909 597,764 4,181 32,399
34 Utah Home Energy Lifeline 1,370,303 142, 232 1,632,473 1,359,942 1,097,772
35 California Energy Savings Assistance Program 602,947 908, 909, 929 589,915 18,484 31,516
36 FERC Rate True-up - OR (3)7,940,350 456 4,075,388 157,361 4,022,323
37 BPA Balancing Account - WA 835,010 143.0 1,007,621 172,611
38 BPA Balancing Account - ID 27,912 143.0 27,912
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39 Blue Sky - CA 134,326 440, 442 62,596 91,161 162,891
40 Blue Sky - OR 2,238,078 440, 442, 456 6,972,427 6,369,038 1,634,689
41 Blue Sky - ID 149,565 440, 442 38,174 69,626 181,017
42 Blue Sky - UT 5,654,685 440, 442 3,604,954 3,332,530 5,382,261
43 Blue Sky - WA 500,146 440, 442 282,838 334,858 552,166
44 Blue Sky - WY 658,079 440, 442 283,549 242,167 616,697
45 Depreciation Study Deferral - OR (3)5,357,364 440, 442, 444 2,767,922 201,816 2,791,258
46 Deferred Steam Accelerated Depreciation - WA (3)34,836,222 440, 442, 444 17,418,111 17,418,111
47 Direct Access 5-Year Opt Out - OR (10)6,807,764 442 1,769,316 175,414 5,213,862
48 Transportation Electrification Program - CA 219,797 10,163 229,960
49 (l)Transportation Electrification Pilot - UT 908 643,898 5,688,047 5,044,149
50 Oregon Clean Fuels Program 4,969,428 131 1,176,546 5,824,566 9,617,448
51 Wildland Fire Mitigation Balancing Account - UT 997,769 440, 442, 444, 921 997,769
52 Pryor Mountain - OR 142,788 221,339 364,127
53 Fly Ash Sales - OR 1,700,000 1,700,000
54 Arrearage Payments Program - WA 234,000 234,000
41 TOTAL 1,563,255,203 296,653,297 363,129,860 1,629,731,766
FERC FORM NO. 1 (REV 02-04)
Page 278
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average life is approximately one year.
(b) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average life is approximately one year.
(c) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average life is approximately one year.
(d) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average life is approximately one year.
(e) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average remaining life is 39 years.
(f) 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.
(g) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average remaining life is approximately three years.
(h) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average remaining life of portion being amortized is 13 years. Substantially represents amounts not yet recognized as a component of net periodic benefit cost.
(i) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average remaining life is approximately five years.
(j) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average remaining life is one year.
(k) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Includes California Solar on Multifamily Affordable Housing.
(l) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average remaining life is approximately five years.
FERC FORM NO. 1 (REV 02-04)
Page 278
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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.
LineNo.Title of Account(a)Operating Revenues Year to Date Quarterly/Annual(b)Operating Revenues Previous year (no Quarterly)(c)
MEGAWATT HOURS SOLD Year to DateQuarterly/Annual
(d)
MEGAWATT HOURS SOLD Amount Previous year (noQuarterly)
(e)
AVG.NO. CUSTOMERS PER MONTH CurrentYear (no Quarterly)
(f)
AVG.NO.CUSTOMERSPER MONTHPrevious
Year (no
Quarterly)(g)
1
2 2,078,412,458 1,958,953,927 18,425,415 17,904,789 1,775,303 1,744,648
3
4 1,678,840,782 1,593,558,298 19,570,243 18,839,074 225,281 221,531
5 1,324,779,894 1,277,511,464 19,058,783 19,415,943 32,930 33,024
6 14,513,894 14,615,254 109,655 114,128 3,534 3,577
7
8
9
10 5,096,547,028 4,844,638,943 57,164,096 56,273,934 2,037,048 2,002,780
11 (a)293,666,727 (d)193,761,115 4,836,292 5,112,797
12 5,390,213,755 5,038,400,058 62,000,388 61,386,731 2,037,048 2,002,780
13 (3,239,918)
14 5,393,453,673 5,038,400,058 62,000,388 61,386,731 2,037,048 2,002,780
15
16 8,373,236 6,408,701
17 (b)7,685,047 8,632,229
18 4,980 9,345
19 19,493,725 18,185,617
20
21 (c)50,383,628 59,425,166
22 187,147,115 161,828,009
23
24
25
26 273,087,731 254,489,067
27 5,666,541,404 5,292,889,125
Line12, column (b) includes $ 300,524,000 of unbilled revenues.
Line12, column (d) includes 3,281,322 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: SalesForResale
For a complete list of the number of customers during 2022 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, 2021 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:
2022 2021
Account service charges - application fees, disconnects, reconnects and returned check charges $6,710,656 $6,887,413
Customer contract flat rate billings and facility buyout charges $969,666 $1,737,897
(c) Concept: OtherElectricRevenue
Account 456, Other electric revenues, includes the following items that were $250,000 or greater during the years ended December 31:
2022 2021
Renewable energy credit sales, net of deferrals and amortization $14,283,978 $13,757,319
Fly-ash and by-product sales $13,842,399 $15,364,905
Amortization of California greenhouse gas allowance revenue $11,984,507 $7,660,217
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 $6,845,756
Amortization of Oregon clean fuels program credits $1,168,860 $1,036,986
Revenues from generation interconnection and transmission service request studies $1,402,859 $1,580,721
Timber sales $1,022,015 $762,608
Steam sales $999,434 $363,351
Phase shifting equipment fee from Western Electricity Coordinating Council $345,847 $588,884
Wind-based ancillary services $282,834 $10,429,829
Maintenance charges for work on joint-owned transmission facilities (a)$593,004
(a) Amount is less than $250,000.
(d) Concept: SalesForResale
For a complete list of the number of customers during 2022 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, 2021 Form No. 1.FERC FORM NO. 1 (REV. 12-05)Page 300-301
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
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43
44
45
46 TOTAL
FERC FORM NO. 1 (NEW. 12-05)Page 302
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 (1)0.0000
2 CALIFORNIA - 06CHCK000R-CA RES CHECK M 1 0.0000
3 CALIFORNIA - 06LNX00311 - LINE EXT 80% GUARANTEE 3,409 0.0000
4 CALIFORNIA - 06NBDDL136-NET BL LOW INC RES DEL NORTE 26 2,269 3 8,667 0.0873
5 CALIFORNIA - 06NBLDL136-NET BILLING LOW INC-RES 91 9,500 9 10,111 0.1044
6 CALIFORNIA - 06NBLDN136-NET BLNG LOW INC-RES DELNORTE 226 22,399 25 9,040 0.0991
7 CALIFORNIA - 06NETBL136-CALIFORNIA NET BILLING RES 653 65,110 62 10,532 0.0997
8 CALIFORNIA - 06NETMT135 - CA RES NET METERING 3,189 353,273 540 5,906 0.1108
9 CALIFORNIA - 06OALT015R-OUTD AR LGT SR 242 62,657 257 942 0.2589
10 CALIFORNIA - 06RESD000D-RES SRVC 182,389 22,691,177 17,459 10,447 0.1244
11 CALIFORNIA - 06RESDDL06-CA LOW INCOME 123,288 15,251,000 11,103 11,104 0.1237
12 CALIFORNIA - 06RGNSV025-CA SMALL GENERAL SVC-RES 1,382 174,392 476 2,903 0.1262
13 CALIFORNIA - 06RNM25135 - CA NET MTR, GEN SVC-RES (78)1 0.0000
14 CALIFORNIA - 06RESD0DM9 - MULTI FAMILY 226 25,591 6 37,667 0.1132
15 CALIFORNIA - 06RESD0DS8-MULT FAM SBMET 1,944 170,541 19 102,316 0.0877
16 CALIFORNIA - INCOME TAX DEFERRAL ADJUSTMENTS 1,247,606 0.0000
17 CALIFORNIA - REVENUE_ACCOUNTING ADJUSTMENTS (539,281)0.0000
18 CALIFORNIA - 06RESD00DN - CA RES SRVC - DEL NORTE CTY 80,616 10,049,657 7,081 11,385 0.1247
19 CALIFORNIA - DSM REVENUE-RESIDENTIAL 879,277 0.0000
20 CALIFORNIA - BLUE SKY REVENUE-RESIDENTIAL 57,411 0.0000
21 CALIFORNIA - OTHER CUSTOMER RETAIL REVENUE 183,746 0.0000
22 IDAHO - 07BLSKY01R-BLUESKY ENERGY (1)0.0000
23 IDAHO - 07LNX00010-MNTHLY 80%GUAR 1,197 0.0000
24 IDAHO - 07LNX00035-ADV 80%MO GUAR 178 0.0000
25 IDAHO - 07NBL36136-ID TOU RES NET BILLING 663 37,335 65 10,045 0.0563
26 IDAHO - 07NETBL136-ID RES NET BILLING 2,381 210,985 393 6,059 0.0886
27 IDAHO - 07NETMT135 - ID RESIDENTIAL NET METERING 8,938 920,401 1,130 7,910 0.1030
28 IDAHO - 07NMT36135-IDAHO TIME-OF-DAY RES NET MTR 3,749 253,467 268 13,989 0.0676
29 IDAHO - 07OALT07AR-SECURITY AR LG 88 21,237 110 800 0.2413
30 IDAHO - 07RESD0001-RES SRVC 611,618 71,993,105 58,625 10,433 0.1177
31 IDAHO - 07RESD0036-RES SRVC-OPTIO 179,736 18,524,391 10,037 17,907 0.1031
32 IDAHO - 07RGNSV06A-ID LRG GENERAL SVC-RES 350 30,035 4 87,500 0.0858
33 IDAHO - 07RGNSV23A-ID SMALL GENERAL SVC-RES 10,624 1,189,866 1,156 9,190 0.1120
34 IDAHO - 07RN23A136-RES NET BILLING SMALL GEN SVC 4 (40)1 4,000 (0.0100)
35 IDAHO - 07RNM23135-RES USE NET MTR SMALL GEN SVC 330 27,102 9 36,667 0.0821
36 IDAHO - 07UPPL000R-BASE SCH FALL 2 0.0000
37 IDAHO - REVENUE_ACCOUNTING ADJUSTMENTS 573,143 0.0000
38 IDAHO - DSM REVENUE-RESIDENTIAL 1,957,315 0.0000
39 IDAHO - BLUE SKY REVENUE-RESIDENTIAL 34,906 0.0000
40 OREGON - 01CHCK000R-RES CHECK MTR 1 0.0000
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41 OREGON - 01COST0004 - 01RESD0004 5,387,045 276,717,598 0.0514
42 OREGON - 01COST0006 - 01RESD0006 1,908 80,610 0.0422
43 OREGON - 01COSTR023, OR RES GEN SRV, COST BASED 97,259 4,878,404 0.0502
44 OREGON - 01COSTR028, OR RES GEN SVC>30KW CST BSD 46,323 2,258,769 0.0488
45 OREGON - 01FXRENEWR - Fixed Renewable Blue Sky (2)0.0000
46 OREGON - 01HABIT004 - 01RESD0004 65,611 3,329,247 0.0507
47 OREGON - 01HABTR023-RES GEN SVC HABITAT BLND 188 9,652 0.0513
48 OREGON - 01LNX00102-LINE EXT 80% G 391 0.0000
49 OREGON - 01LNX00109-REF/NREF ADV +9,769 0.0000
50 OREGON - 01NETMT135-NET METERING 4,655,264 11,099 0.0000
51 OREGON - 01NMT06135-RES TOU PILOT NET METERING 4,457 8 0.0000
52 OREGON - 01NMT07135-OR RES NET METERING LOW INC 15,000 29 0.0000
53 OREGON - 01NMTOU135-TOU NET METERING 29,441 58 0.0000
54 OREGON - 01OALTB15R-OR OUTD AR LGT RES 1,891 285,163 2,236 846 0.1508
55 OREGON - 01PTOU0004 - 01RESD0004 13,355 698,005 0.0523
56 OREGON - 01PTOURB23-RES GEN SVC; TOU SUPPLY SVC 27 1,387 0.0514
57 OREGON - 01RENEW004 - 01RESD0004 510,574 25,674,524 0.0503
58 OREGON - 01RENWR023-RENEW USAGE SPLY SVC-GEN SVC 621 31,727 0.0511
59 OREGON - 01RESD0004-RES SRVC 324,391,512 511,680 0.0000
60 OREGON - 01RESD0006-RES TIME-OF-DA 99,698 142 0.0000
61 OREGON - 01RESD0007-OR RESIDENTIAL LOW INCOME 3,563,637 5,397 0.0000
62 OREGON - 01RESD004T - RES Time Option 691,192 914 0.0000
63 OREGON - 01RESD007T-OR TOU RESIDENTIAL LOW INCOME 6,331 9 0.0000
64 OREGON - 01RESD0607-OR RES TOU PILOT LOW INC 638 1 0.0000
65 OREGON - 01RGNSB023-SMALL GENERAL SVC-RES 7,839,603 16,946 0.0000
66 OREGON - 01RGNSB028 - GENERAL SVC > 30 KW - RES 1,491,824 215 0.0000
67 OREGON - 01RGNSB029-OR RES GEN SVC TOU PILOT 0.0000
68 OREGON - 01RGNSB23T-RES GEN SVC TOU PORTFOLIO 1,854 3 0.0000
69 OREGON - 01RNETM023-NET METER RESIDENTIAL GEN SVC 106,217 262 0.0000
70 OREGON - 01RNETM028-NET METER RESIDENTIAL GEN SVC 73,830 5 0.0000
71 OREGON - 01UPPL000R-BASE SCH FALL 2 0.0000
72 OREGON - 01VIR04136-OR RES VOLUME INCENTIVE 415,681 466 0.0000
73 OREGON - 01VIR06136-OR RES VOLUME INCENTIVE 373 1 0.0000
74 OREGON - 01VIR07136-OR RES VOLUME INCNTV LOW INC 1,112 1 0.0000
75 OREGON - OR GAIN ON SALE OF ASSET (17,606)0.0000
76 OREGON - INCOME TAX DEFERRAL ADJUSTMENTS 2,990,611 0.0000
77 OREGON - REVENUE_ACCOUNTING ADJUSTMENTS (1,129,026)0.0000
78 OREGON - SOLAR FEED-IN REVENUE 1,896,436 0.0000
79 OREGON - OTHER CUSTOMER RETAIL REVENUE 354,816 0.0000
80 OREGON - COMMUNITY SOLAR REVENUE 239,865 0.0000
81 OREGON - DSM REVENUE-RESIDENTIAL 25,097,709 0.0000
82 OREGON - BLUE SKY REVENUE-RESIDENTIAL 855,293 0.0000
83 UTAH - 08BLSKY01R-BLUESKY ENERGY (4)0.0000
84 UTAH - 08CFR00001-MTH FACILITY S 735 0.0000
85 UTAH - 08CGENR136-UT RES TRANSITION GENERATION 688 77,118 80 8,600 0.1121
86 UTAH - 08CGNSL136-UT RES TRANSITION GEN-SOLEIL 2,706 277,670 600 4,508 0.1027
87 UTAH - 08CGR01136-UTAH RESIDENTIAL TRANS GEN 149,110 16,101,271 17,213 8,663 0.1080
88 UTAH - 08CGR01137-UT RES CUST GENERATION 137 75,782 8,233,828 9,854 7,690 0.1087
89 UTAH - 08CGR02136-UT RES TOU TRANSITION GEN 235 24,686 23 10,217 0.1050
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90 UTAH - 08CGR02137-UT RES TOU CUST GEN 137 136 14,322 15 9,067 0.1053
91 UTAH - 08CGR03136-UTAH LOW INC RES TRANS GEN 775 83,693 93 8,333 0.1080
92 UTAH - 08CGR03137-UT LOW INC RES CUST GEN 137 320 34,676 41 7,805 0.1084
93 UTAH - 08CGR06136-RES USE, GEN SVC RATE, MANUAL 229 23,143 2 114,500 0.1011
94 UTAH - 08CGR23136-RESIDENTIAL SMALL GEN SVC 558 49,503 9 62,000 0.0887
95 UTAH - 08CGR23137-RES SM GEN SVC - CUST GEN 137 33 3,172 2 16,500 0.0961
96 UTAH - 08CGR2E136-UT RES EV TOU PILOT-TRAN GEN 14 1,083 1 14,000 0.0774
97 UTAH - 08CGR2E137-UT RES EV TOU PILOT CUST GEN 29 2,292 4 7,250 0.0790
98 UTAH - 08CGRA1137-UT RES CUST GEN AGGEGATED 146 15,746 22 6,636 0.1078
99 UTAH - 08CGRW1136-UT RES TRANS GEN-WATTSMART 63 6,837 9 7,000 0.1085
100 UTAH - 08CGRW1137-UT RES CUST GEN 137-WATTSMART 1,365 151,305 224 6,094 0.1108
101 UTAH - 08CGS23136-RES SMALL GEN SVC MANUAL 567 61,796 51 11,118 0.1090
102 UTAH - 08CHCK000R-UT RES CHECK M 1 0.0000
103 UTAH - 08COOLKPRR - Utah Cool Keeper Program 19 0.0000
104 UTAH - 08CRA23137-UT RES SML GEN SVC 137 AGGREG 1 157 0.1574
105 UTAH - 08LNX00001-MTHLY 80% GUAR 6,719 0.0000
106 UTAH - 08LNX00013-80% MNTHLY MIN 27,163 0.0000
107 UTAH - 08LNX00108-ANN COST MTHLY 1,187 0.0000
108 UTAH - 08MHTP0006-MOBILE HOME & TRAILER 12,009 911,684 9 1,334,333 0.0759
109 UTAH - 08MHTP0023-MOBILE HOME & TRAILER 138 10,706 1 138,000 0.0776
110 UTAH - 08NETAGFEE-> 6 NET METER AGGREGATION FEE 900 3 0.0000
111 UTAH - 08NETMT135 - Net Metering 149,126 17,688,544 29,598 5,038 0.1186
112 UTAH - 08NETMW135-UT RES NET METER-WATTSMART 2 273 1 2,000 0.1365
113 UTAH - 08NMT03135-LOW INCOME RES NET METERING 1,389 148,871 198 7,015 0.1072
114 UTAH - 08OALT007R-SECURITY AR LG 2,077 346,828 2,154 964 0.1670
115 UTAH - 08PTLD000R-POST TOP LIGHT 1 105 2 500 0.1046
116 UTAH - 08RCG23136-RES NET METER, SMALL GEN SVC 219 20,986 15 14,600 0.0958
117 UTAH - 08RCG23137-RES SMALL GEN SVC, CUST GEN 225 22,386 15 15,000 0.0995
118 UTAH - 08RESD0001-RES SRVC 7,400,302 798,019,919 811,149 9,123 0.1078
119 UTAH - 08RESD0002-RES SRVC-OPTIO 3,834 409,600 409 9,374 0.1068
120 UTAH - 08RESD0003-LIFELINE PRGRM 154,789 16,403,971 19,961 7,755 0.1060
121 UTAH - 08RESD002E-RES ELCTRC VEHICLE TOU PILOT 7,525 675,498 479 15,710 0.0898
122 UTAH - 08RESD003E-UT RES LOW INC ELEC V TOU PLT 19 1,978 2 9,500 0.1041
123 UTAH - 08RGNSV006-GEN SRVC-RES 128,356 9,535,425 309 415,392 0.0743
124 UTAH - 08RGNSV008-UT RESIDENTIAL GENERAL SVC 750 52,610 1 750,000 0.0701
125 UTAH - 08RGNSV023-GEN SRVC-RES 105,936 11,162,779 14,506 7,303 0.1054
126 UTAH - 08RGNSV06A-UT SMALL GENERAL SVC-RES-TOU 8,411 661,574 30 280,367 0.0787
127 UTAH - 08RNM06135 - UT NET MTR, GEN SVC-RES 3,621 293,322 11 329,182 0.0810
128 UTAH - 08RNM23135 - UT NET MTR, GEN SVC-RES 1,411 172,559 421 3,352 0.1223
129 UTAH - 08RNM6A135-RES GEN SVC NET METERING 22 3,898 3 7,333 0.1772
130 UTAH - 08RTCVLNGA-TCV LNX GAR 2,341 0.0000
131 UTAH - 08SSLR0001 - RESIDENTIAL SUBSCRB SOLAR 28,856 3,388,866 0.1174
132 UTAH - 08SSLR0003-RES LOW INC SUBSCR SOLAR 284 33,814 24 11,833 0.1191
133 UTAH - 08SSLRRG23-RES SMALL GEN SV SUBSCR SOLAR 55 7,740 17 3,235 0.1407
134 UTAH - 08UPPL000R-BASE SCH FALL 3 0.0000
135 UTAH - REVENUE_ACCOUNTING ADJUSTMENTS (160,143)0.0000
136 UTAH - REVENUE ADJUSTMENT - DEFERRED NPC 20,252,439 0.0000
137 UTAH - SOLAR FEED-IN REVENUE 237,585 0.0000
138 UTAH - OTHER CUSTOMER RETAIL REVENUE 86,375 0.0000
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139 UTAH - DSM REVENUE-RESIDENTIAL 9,692,053 0.0000
140 UTAH - BLUE SKY REVENUE-RESIDENTIAL 2,624,988 0.0000
141 WASHINGTON - 02BLSKY01R-BLUESKY ENERGY 1 0.0000
142 WASHINGTON - 02CHCK000R-WA RES CHECK M 1 0.0000
143 WASHINGTON - 02LNX00109-REF/NREF ADV +1,253 0.0000
144 WASHINGTON - 02NETMT135 - WA RES NET METERING 19,437 2,084,299 1,869 10,400 0.1072
145 WASHINGTON - 02OALTB15R-WA OUTD AR LGT RES 874 101,426 962 909 0.1160
146 WASHINGTON - 02RESD0016-WA RES SRVC 1,565,461 160,040,410 102,963 15,204 0.1022
147 WASHINGTON - 02RESD0017-BILL ASSISTANC 104,580 10,709,403 6,384 16,382 0.1024
148 WASHINGTON - 02RESD0018-WA 3 PHASE RES 2,011 226,991 74 27,176 0.1129
149 WASHINGTON - 02RESD018X-WA 3 PHASE RES 268 29,100 11 24,364 0.1086
150 WASHINGTON - 02RESD019T-WA RESIDENTIAL TOU PILOT 121 11,860 8 15,000 0.0988
151 WASHINGTON - 02RGNSB024-WA SMALL GENERAL SVC-RES 21,897 2,761,438 3,440 6,365 0.1261
152 WASHINGTON - 02RGNSB036-RES LRG GEN SVC < 1000 KW 2,648 223,814 5 529,600 0.0845
153 WASHINGTON - 02RNM24135-RES NET METER SMALL GEN SVC 312 39,426 57 5,474 0.1264
154 WASHINGTON - RESIDENTIAL CUSTOMER BILL CREDITS (144,457)0.0000
155 WASHINGTON - INCOME TAX DEFERRAL ADJUSTMENTS 801,150 0.0000
156 WASHINGTON - REVENUE ADJUSTMENT - DEFERRED NPC 39,463 0.0000
157 WASHINGTON - REVENUE_ACCOUNTING ADJUSTMENTS (2,516,791)0.0000
158 WASHINGTON - DSM REVENUE-RESIDENTIAL 6,104,997 0.0000
159 WASHINGTON - BLUE SKY REVENUE-RESIDENTIAL 259,731 0.0000
160 WASHINGTON - ALT REVENUE PROGRAM ADJUSTMENTS 18,028,989 0.0000
161 WYOMING - 05BLSKY01R-BLUESKY ENERGY - A 0.0000
162 WYOMING - 05LNX00102-LINE EXT 80% G 690 0.0000
163 WYOMING - 05NETMT135 - EXPERIMENTAL PARTIAL REQ - A 2,798 329,434 374 7,479 0.1178
164 WYOMING - 05OALT015R-OUTD AR LGT SR - A 775 87,186 921 841 0.1125
165 WYOMING - 05RESD0002-WY RES SRVC - A 930,026 99,463,793 103,559 8,981 0.1069
166 WYOMING - 05RESD0019-WY RES TOU PILOT 103 9,593 7 14,714 0.0931
167 WYOMING - 05RGNSV025-WY SMALL GENERAL SVC-RES - A 9,976 1,198,159 1,569 6,358 0.1201
168 WYOMING - 05RNM25135-WY RES SMALL GEN SVC NET MTR 267 1 0.0000
169 WYOMING - INCOME TAX DEFERRAL ADJUSTMENTS 250,332 0.0000
170 WYOMING - REVENUE ADJUSTMENT - DEFERRED NPC (216,060)0.0000
171 WYOMING - REVENUE_ACCOUNTING ADJUSTMENTS (30,021)0.0000
172 WYOMING - DSM REVENUE-RESIDENTIAL - A 678,444 0.0000
173 WYOMING - DSM REVENUE-RESIDENTIAL GEN SVC - A 37,107 0.0000
174 WYOMING - BLUE SKY REVENUE-RESIDENTIAL - A 240,638 0.0000
175 WYOMING - 05BLSKY01R-BLUESKY ENERGY - B 0.0000
176 WYOMING - 05RESD0002-WY RES SRVC - B 118,129 12,701,432 12,788 9,237 0.1075
177 WYOMING - 05RGNSV025-WY SMALL GENERAL SVC-RES - B 589 88,057 153 3,850 0.1495
178 WYOMING - 05LNX00109-REF/NREF ADV +5,587 0.0000
179 WYOMING - 05NETMT135 - EXPERIMENTAL PARTIAL REQ - B 921 114,555 145 6,352 0.1244
180 WYOMING - 05OALT015R-OUTD AR LGT SR - B 67 8,880 82 817 0.1325
181 WYOMING - 09RES00002 1 0.0000
182 WYOMING - 09RESD0002 4 0.0000
183 WYOMING - DSM REVENUE-RESIDENTIAL - B 87,318 0.0000
184 WYOMING - DSM REVENUE-RESIDENTIAL GEN SVC - B 1,675 0.0000
185 WYOMING - BLUE SKY REVENUE-RESIDENTIAL - B 21,015 0.0000
186 LESS MULTIPLE BILLINGS (25,957)
41 TOTAL Billed Residential Sales 18,360,662 2,065,924,458 1,775,303 10,379 0.1121
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42 TOTAL Unbilled Rev. (See Instr. 6)64,753 12,488,000 0.0007
43 TOTAL 18,425,415 2,078,412,458 1,775,303 10,379 0.1128
FERC FORM NO. 1 (ED. 12-95)Page 304
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 53,502 7,706,414 6,511 8,217 0.1440
2 CALIFORNIA - 06GNSV025F-GEN SRVC-< 20 919 158,956 84 10,940 0.1730
3 CALIFORNIA - 06GNSV0A32-GEN SRVC-20 KW 92,848 13,126,496 1,153 80,527 0.1414
4 CALIFORNIA - 06LGSV048T-LRG GEN SERV 26,960 2,518,446 9 2,995,556 0.0934
5 CALIFORNIA - 06NMT48135-CA GEN SVC NET MTR->500 KW 2,476 215,458 1 2,476,000 0.0870
6 CALIFORNIA - 06LGSV0A36-LRG GEN SRVC-O 55,446 6,611,774 138 401,783 0.1192
7 CALIFORNIA - 06LNX00102-LINE EXT 80% G 16,586 0 0.0000
8 CALIFORNIA - 06LNX00109-REF/NREF ADV +95,928 0 0.0000
9 CALIFORNIA - 06LNX00110-REF/NREF ADV +1,879 0 0.0000
10 CALIFORNIA - 06LNX00300 - 80% MONTHLY MIN GUAR + 80%2,487 0 0.0000
11 CALIFORNIA - 06LNX00311 - LINE EXT 80% GUARANTEE 15,388 0 0.0000
12 CALIFORNIA - 06LNX00312 - CA IRG LINE EXT 7,477 0 0.0000
13 CALIFORNIA - 06NBL25136-CA NET BILL GEN SVC < 20 KW 25 2,796 6 4,167 0.1119
14 CALIFORNIA - 06NBL32136-CA NET BILL GEN SVC >= 20 KW 181 25,125 1 90,000 0.1396
15 CALIFORNIA - 06NMT36135-CA GEN SVC NET MTR->100 KW 3,057 397,342 7 436,714 0.1300
16 CALIFORNIA - 06OALT015N-OUTD AR LGT SR 596 155,923 438 1,361 0.2616
17 CALIFORNIA - 06RCFL0042-AIRWAY & ATHLE 156 32,310 37 4,216 0.2071
18 CALIFORNIA - 06NMT25135-CA GEN SVC NET MTR<20KW 192 26,875 43 4,465 0.1400
19 CALIFORNIA - 06NMT32135-CA GEN SVC NET MTR>20KW 3,059 466,823 36 84,972 0.1526
20 CALIFORNIA - INCOME TAX DEFERRAL ADJUSTMENTS 755,209 0 0.0000
21 CALIFORNIA - REVENUE_ACCOUNTING ADJUSTMENTS (313,743)0 0.0000
22 CALIFORNIA - DSM REVENUE-COMMERCIAL 519,492 0 0.0000
23 CALIFORNIA - BLUE SKY REVENUE-COMMERCIAL 4,156 0 0.0000
24 CALIFORNIA - OTHER CUSTOMER RETAIL REVENUE 111,180 0 0.0000
25 IDAHO - 07CISH0019-COMM & IND SPA 325 24,427 0 0.0752
26 IDAHO - 07GNSV0006-GEN SRVC-LRG P 237,744 20,387,162 1,025 231,945 0.0858
27 IDAHO - 07GNSV0009-GEN SRVC-HI VO 52,484 3,396,468 3 17,494,667 0.0647
28 IDAHO - 07GNSV0023-GEN SRVC-SML P 193,616 19,065,353 8,060 24,022 0.0985
29 IDAHO - 07GNSV0035-GEN SRVCOPTION 324 34,945 2 107,667 0.1082
30 IDAHO - 07GNSV006A-GEN SRVC-LRG P 19,012 1,702,849 161 118,087 0.0896
31 IDAHO - 07GNSV023A-GEN SRVC-SML P 26,965 2,665,339 1,267 21,283 0.0988
32 IDAHO - 07GNSV023F-GEN SRVC SML P 6 1,851 4 1,500 0.3085
33 IDAHO - 07GNSV035A-GEN SRVCOPTION 55 8,005 1 55,000 0.1456
34 IDAHO - 07LNX00010-MNTHLY 80%GUAR 22,288 0 0.0000
35 IDAHO - 07LNX00035-ADV 80%MO GUAR 210,549 0 0.0000
36 IDAHO - 07LNX00040-ADV+REFCHG+80%27,431 0 0.0000
37 IDAHO - 07OALT007N-SECURITY AR LG 212 42,417 165 1,285 0.2001
38 IDAHO - 07OALT07AN-SECURITY AR LG 9 2,118 10 900 0.2354
39 IDAHO - 07TCVLNAGN-TCV LNX ANNUAL GAR-NON RES 408 0 0.0000
40 IDAHO - 07TCVLNXGN-TCV LNX - 80% GAR - NON RES 1,122 0 0.0000
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41 IDAHO - 07LNX00312 - ID LINE EXT 19,028 0 0.0000
42 IDAHO - 07NBL23136-ID NET BILLING SML GEN SVC 166 12,987 12 13,833 0.0782
43 IDAHO - 07NBL6A136-ID NET BILLING LRG GEN SVC 225 20,693 1 225,000 0.0920
44 IDAHO - 07NMT06135 - ID NET MTR - LARGE GEN SVC 3,003 280,819 8 375,375 0.0935
45 IDAHO - 07NMT23135 - ID NET MTR - SMALL GEN SVC 1,239 105,542 41 30,220 0.0852
46 IDAHO - 07NMT6A135-NET METERING LARGE GEN SVC 83 6,069 1 83,000 0.0731
47 IDAHO - 07LNX00015-ANNUAL 80%GUAR 521 0 0.0000
48 IDAHO - 07LNX00311 - LINE EXT 80% GUARANTEE 29,876 0 0.0000
49 IDAHO - 07LNX00300 - 80% MONTHLY MIN GUAR + 80%3,390 0 0.0000
50 IDAHO - REVENUE_ACCOUNTING ADJUSTMENTS 337,228 0 0.0000
51 IDAHO - DSM REVENUE-COMMERCIAL 960,601 0 0.0000
52 IDAHO - BLUE SKY REVENUE-COMMERCIAL 3,203 1 0.0000
53 OREGON - 01COST0023, OR GEN SRV, COST BASED 1,036,085 49,970,368 0 0.0482
54 OREGON - 01COST0048 - 01LGSV0048 1,543,336 63,487,854 0 0.0411
55 OREGON - 01COST023F - OR GEN SRV - COST-BASED 2,943 150,507 0 0.0511
56 OREGON - 01COST23MT-OR GEN SVC COST TOU MTR 180 7,237 0 0.0404
57 OREGON - 01COST28MT-OR GEN SVC>30KW COST TOU MTR 450 21,921 0 0.0487
58 OREGON - 01COST30MT-LG GEN SVC>200KW COST TOU MTR 76,851 2,927,021 0 0.0381
59 OREGON - 01COSTB023 - OR GEN SRV, CST-BSD SPLY 22,959 1,127,760 0 0.0491
60 OREGON - 01COSTEV45-ELECT VEHICLE DC FAST CHG SVC 7,127 347,119 0 0.0487
61 OREGON - 01COSTL030 - OR LRG GEN SRV, CST >200 kW 1,006,521 38,361,936 0 0.0381
62 OREGON - 01COSTS028, OR GEN SERV, COST > 30kW 1,928,858 94,032,468 0 0.0488
63 OREGON - 01COSTS029-OR GEN SVC TOU PILOT COS>30KW (4)(178)0 0.0445
64 OREGON - 01FXRENEWN - Fixed Renewable Blue Sky 0 0.0000
65 OREGON - 01GNCEL23F-OR SMALL CELL FLAT RATE 2,893 2 0.0000
66 OREGON - 01GNSB0023, OR GEN SRV, BPA, < 30 kW 1,650,586 2,735 0.0000
67 OREGON - 01GNSB0028, OR GEN SRV, BPA, > 30 kW 1,963,452 257 0.0000
68 OREGON - 01GNSB023T - OR GEN SRV - TOU - BPA 17,014 33 0.0000
69 OREGON - 01GNSB0723-OR GEN SVC DIR ACCESS <= 30KW 17,133 27 0.0000
70 OREGON - 01GNSB0728 - OR GEN SVC DIR ACCESS >30KW 11,071 1 0.0000
71 OREGON - 01GNSEV45T-ELECT VEHICLE DC FAST CHG<1MW 529,777 28 0.0000
72 OREGON - 01GNSV0023, OR GEN SRV, < 30 KW 61,273,992 61,673 0.0000
73 OREGON - 01GNSV0028, OR GEN SRV > 30 kW 65,712,802 9,054 0.0000
74 OREGON - 01GNSV0029-OR GEN SVC TOU PILOT > 30 KW (531)0 0.0000
75 OREGON - 01GNSV023F - OR GEN SRV - FLAT RATE 10,527 1,589,396 788 13,359 0.1510
76 OREGON - 01GNSV023M - OR GEN SRV, MANUAL BILL 79 7,506 2 39,500 0.0950
77 OREGON - 01GNSV023T, OR GEN SRV, TOU Option 139,238 167 0.0000
78 OREGON - 01HABT0023, OR HABITAT BLENDED SPLY SRV 2,944 143,960 0 0.0489
79 OREGON - 01HABTB023 - OR HABITAT BLENDED 9 482 0 0.0536
80 OREGON - 01LGSB0030, GEN DEL SRV, > 200 kW(R)1,143,969 21 0.0000
81 OREGON - 01LGSBT030-OR LG GEN SVC>200 TOU METER 88,158 1 0.0000
82 OREGON - 01LGSV0030 - OR LRG GEN SRV, > 1000 kW 35,028,923 606 0.0000
83 OREGON - 01LGSV0048-1000KW AND OVR 22,983,361 83 0.0000
84 OREGON - 01LGSV048M-LRG GEN SRVC 1 53,888 3,008,216 1 53,888,000 0.0558
85 OREGON - 01LGSVT030-OR LG GEN SVC>200KW TOU MTR 2,515,534 29 0.0000
86 OREGON - 01LNX00100-LINE EXT 60% G 9,531 0 0.0000
87 OREGON - 01LNX00102-LINE EXT 80% G 1,297,535 0 0.0000
88 OREGON - 01LNX00103-LINE EXT 80% G 5,773 0 0.0000
89 OREGON - 01LNX00105-CNTRCT $ MIN G 12,778 0 0.0000
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90 OREGON - 01LNX00109-REF/NREF ADV +1,606,736 0 0.0000
91 OREGON - 01LNX00110-REF/NREF ADV +13,445 0 0.0000
92 OREGON - 01LNX00311 - LINE EXT 80% G 196,763 0 0.0000
93 OREGON - 01LNX00312 - OR IRG LINE EXT 2,662 0 0.0000
94 OREGON - 01LNX00314 - LINE EXT 60% GUARANTEE 1,161 0 0.0000
95 OREGON - 01LNX00120 - Line Extension 60% Gar 295,273 0 0.0000
96 OREGON - 01LNX00300 - LINE EXT 80% GUARANTEE 374,760 0 0.0000
97 OREGON - 01LNX00310-LINE EXTENSION CONTRACT 2,566 0 0.0000
98 OREGON - 01LPRS047M-PART REQ SRVC 47,204 4,442,551 5 9,440,800 0.0941
99 OREGON - 01NM23T135-OR NET MTR TOU GEN SVC<30 KW 2,483 2 0.0000
100 OREGON - 01NMB23135-OR NET MTR GEN SVC <= 30 KW 19,422 55 0.0000
101 OREGON - 01NMB28135-OR NET MTR GEN SVC > 30 KW 45,697 5 0.0000
102 OREGON - 01NMT23135 - OR NET MTR, GEN, < 30 kW 523,125 539 0.0000
103 OREGON - 01NMT28135 - OR NET MTR, GEN, > 30 kW 2,633,269 313 0.0000
104 OREGON - 01NMT30135 - OR NET MTR, GEN, > 200 kW 2,202,960 38 0.0000
105 OREGON - 01NMT48135-NET METERING GEN SVC => 1000 579,322 4 0.0000
106 OREGON - 01NMTEV45T-OR NET MTR, EV DC FAST CHG ST 192 1 0.0000
107 OREGON - 01OALT015N-OUTD AR LGT NR 4,876 515,322 2,644 1,844 0.1057
108 OREGON - 01OALTB15N-OR OUTD AR LGT NR 1,272 185,336 958 1,328 0.1457
109 OREGON - 01PTOU0023, OR GEN SRV, TOU ENG SPLY SRV 2,278 112,868 0 0.0495
110 OREGON - 01PTOUB023, OR GEN SRV, TOU SPLY SRV 231 11,944 0 0.0517
111 OREGON - 01RCFL0054-REC FIELD LGT 1,361 127,494 99 13,747 0.0937
112 OREGON - 01RENW0023, OR RENW USAGE SPLY SRV 13,223 651,273 0 0.0493
113 OREGON - 01RENWB023 - OR RENEWABLE USAGE 64 3,275 0 0.0512
114 OREGON - 01STDAY023 - OR DAY STD OFR, SCH 23 3,562 279,376 0 0.0784
115 OREGON - 01STDAY028 - OR DAY STD OFF, SCH 28 10,743 844,859 0 0.0786
116 OREGON - 01STDAY030 - OR STD DAY OFF, SCH 27 3,150 223,427 0 0.0709
117 OREGON - 01VIR23136-OR VOLUME INCENTIVE <= 30 KW 193,427 122 0.0000
118 OREGON - 01VIR28136-OR VOLUME INCENTIVE > 30 KW 680,598 91 0.0000
119 OREGON - 01VIR30136-OR VOLUME INCENTIVE > 200 kW 187,402 3 0.0000
120 OREGON - 01VIR48136-OR VOLUME INCENTIVE > 1000 KW 110,402 1 0.0000
121 OREGON - 01ZZMERGCR-MERGER CREDITS 0 0.0000
122 OREGON - CUSTOMER COUNT - REGULAR 0 0.0000
123 OREGON - 01LGSB0048 - LG GEN SVC > 1000KW (R)798,791 2 0.0000
124 OREGON - 01LGSV028M - OR LGSV, <1000 kW, Manual 434 43,443 1 434,000 0.1001
125 OREGON - 01GNSV0728 - OR GEN SVC DIR ACCESS >30KW 295,928 17 0.0000
126 OREGON - 01GNSV0730 -OR GEN SVC DIR ACCESS >200KW 2,139,042 19 0.0000
127 OREGON - 01GNSV0748 LG GEN SVC DIR ACCESS 1000KW+1,134,205 3 0.0000
128 OREGON - 01GNSV0848-LG GEN SVC > 1000 DA DEL 1,645,394 1 0.0000
129 OREGON - 01GNSVT023-OR GEN SVC <=30 KW TOU MTR 8,090 3 0.0000
130 OREGON - 01GNSVT028-OR GEN SVC>30KW TOU MTR 32,938 6 0.0000
131 OREGON - OR GAIN ON SALE OF ASSET (16,501)0 0.0000
132 OREGON - INCOME TAX DEFERRAL ADJUSTMENTS 2,803,269 0 0.0000
133 OREGON - REVENUE_ACCOUNTING ADJUSTMENTS (2,454,179)0 0.0000
134 OREGON - SOLAR FEED-IN REVENUE 1,701,278 0 0.0000
135 OREGON - OTHER CUSTOMER RETAIL REVENUE 388,699 0 0.0000
136 OREGON - COMMUNITY SOLAR REVENUE 175,285 0 0.0000
137 OREGON - DSM REVENUE-COMMERCIAL 23,191,038 0 0.0000
138 OREGON - BLUE SKY REVENUE-COMMERCIAL 921,289 101 0.0000
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139 UTAH - 08ABL-NRES - APPLICANT BUILT LINE 1,303 0 0.0000
140 UTAH - 08ABTCLXGN-LINE EXT 80% CONTRACT MIN 22,686 0 0.0000
141 UTAH - 08CFR00051-MTH FAC SRVCHG 23,964 0 0.0000
142 UTAH - 08CFR00052-ANN FAC SVCCHG 2 0 0.0000
143 UTAH - 08CGA06137-UT GEN SVC CUST GEN 137 68 10,037 1 68,000 0.1476
144 UTAH - 08CGA23137-UT NET MTR SMALL GEN SVC 252 24,666 11 22,909 0.0979
145 UTAH - 08CGM06136-UT NET METERING GENERAL SVC 6,313 584,916 11 573,909 0.0927
146 UTAH - 08CGM23136-UTAH NET METER SM GEN SVC 882 92,724 52 16,962 0.1051
147 UTAH - 08CGM6A136-UTAH GEN SVC TRANS GEN TOU 3,910 351,836 18 217,222 0.0900
148 UTAH - 08CGM6A137-UT GEN SVC TRANS TOU MAN 137 225 21,426 2 112,500 0.0952
149 UTAH - 08CGN08136-UT NET MTR GEN SVC > 1000 KW 9,313 800,835 2 4,656,500 0.0860
150 UTAH - 08CGN06136-UT GEN SVC TRANSITION GEN 42,291 3,826,959 86 491,756 0.0905
151 UTAH - 08CGN06137-UT GEN SVC CUST GEN 137 11,787 1,086,586 29 406,448 0.0922
152 UTAH - 08CGN23136-UTAH NET METER SMALL GEN SVC 3,000 303,691 143 20,833 0.1012
153 UTAH - 08CGN23137-UT NET MTR SMALL GEN SVC 955 99,080 41 23,293 0.1037
154 UTAH - 08COOLKPRN - A/C DIRECT LOAD CONTROL (1)0 0.0000
155 UTAH - 08GNSV0006-GEN SRVC-DISTR 5,156,727 422,561,479 11,582 445,236 0.0819
156 UTAH - 08GNSV0009-GEN SRVC-HI VO 907,145 49,737,876 48 18,898,854 0.0548
157 UTAH - 08GNSV0023-GEN SRVC-DISTR 1,341,200 128,423,779 80,384 16,685 0.0958
158 UTAH - 08GNSV006A-GEN SRVC-ENERG 281,328 32,751,364 1,994 141,087 0.1164
159 UTAH - 08GNSV006M-MNL DIST VOLTG 1 0.0000
160 UTAH - 08GNSV009A-GEN SRVC HI VO 26,899 1,241,456 2 13,449,500 0.0462
161 UTAH - 08GNSV009M-MANL HIGH VOLT 221,254 12,623,058 1 221,254,000 0.0571
162 UTAH - 08GNSV023F-GEN SRVC FIXED 1,312 182,076 129 10,171 0.1388
163 UTAH - 08GNSV06AM-MNL ENERGY TOD 365 29,479 1 365,000 0.0808
164 UTAH - 08GNSV06MN-GNSV DIST VOLT 32,492 2,539,512 571 56,904 0.0782
165 UTAH - 08GNSVDWY6-UT GEN SVC W WYO DEDUCT MTR 636 1 0.0000
166 UTAH - 08LNX00002-MTHLY 80% GUAR 2,641,745 0 0.0000
167 UTAH - 08LNX00004-ANNUAL 80%GUAR 264,629 0 0.0000
168 UTAH - 08LNX00006-FIXD MTHLY MIN 2,882 0 0.0000
169 UTAH - 08LNX00014-80% MIN MNTHLY 2,239,567 0 0.0000
170 UTAH - 08LNX00017-ADV/REF&80%ANN 184,731 0 0.0000
171 UTAH - 08LNX00158-ANNUALCOST MTH 28,232 0 0.0000
172 UTAH - 08LNX00300 - LINE EXT 80% PLUS MONTHLY 225,173 0 0.0000
173 UTAH - 08LNX00310 - IRR, 80% ANNUAL MIN + 80% ?42,844 0 0.0000
174 UTAH - 08LNX00312 UT IRG LINE EXT 4,151 0 0.0000
175 UTAH - 08NMT06135-UT NET METERING GEN SVC 114,853 9,782,165 267 430,161 0.0852
176 UTAH - 08NMT08135 - NET METERING GEN SVC 51,468 3,873,740 11 4,678,909 0.0753
177 UTAH - 08NMT23135 - UT NET MTR, GEN, < 25 KW 10,149 1,037,800 809 12,545 0.1023
178 UTAH - 08NMT6A135-NET METERING GEN SVC TOU 12,868 1,290,283 90 142,978 0.1003
179 UTAH - 08NMT8135M - NET METERING GEN SVC MANUAL 8,506 774,450 1 8,506,000 0.0910
180 UTAH - 08OALT007N-SECURITY AR LG 6,847 851,936 3,708 1,847 0.1244
181 UTAH - 08PRSV031M-BKUP MNT&SUPPL 204,565 11,450,691 4 51,141,250 0.0560
182 UTAH - 08PTLD000N-POST TOP LIGHT 6 452 2 3,000 0.0754
183 UTAH - 08REFP034M-RENEWABLE QUAL CUST > 5000 KW 480,568 18,344,997 1 480,568,000 0.0382
184 UTAH - 08REFS032M-UT RENEWABLE FAC & SUPP PWR 167,795 11,998,218 3 55,931,667 0.0715
185 UTAH - 08SSLR0006-GENERAL SVC SUBSCR SOLAR 4,158 509,750 14 297,000 0.1226
186 UTAH - 08SSLR0023-SMALL GEN SVC SUBSCR SOLAR 3,766 411,234 0 0.1092
187 UTAH - 08SSLR06AM-GEN SVC TOU SOLAR SUBSCR MAN 5,129,720 353 0.0000
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188 UTAH - 08TCVLNAGN-UTAH LNX ANNUAL GAR NON RES 6,829 0 0.0000
189 UTAH - 08TCVLNXGN-TCV LNX - 80% GAR - NON RES 271,602 0 0.0000
190 UTAH - 08TCVLXACN-GAR ADDED CAPACITY NON RES 21,410 0 0.0000
191 UTAH - 08TOSS015F-TRAFFIC SIG NM 171 15,000 20 8,550 0.0877
192 UTAH - 08TOSS0015-TRAF & OTHER S 3,373 340,008 1,140 2,959 0.1008
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194 UTAH - REVENUE_ACCOUNTING ADJUSTMENTS 1,200,445 0 0.0000
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196 UTAH - SOLAR FEED-IN REVENUE 283,715 0 0.0000
197 UTAH - OTHER CUSTOMER RETAIL REVENUE 103,913 0 0.0000
198 UTAH - 08LNX00311 - LINE EXT 80% GUARANTEE 299,537 0 0.0000
199 UTAH - 08GNSV0008 - UT GEN SVC TOU > 1000KW 870,984 62,204,614 117 7,444,308 0.0714
200 UTAH - 08GNSV008M - UT GEN SVC TOU > 1000KW 6,806 438,115 2 3,403,000 0.0644
201 UTAH - DSM REVENUE-COMMERCIAL 11,661,292 0 0.0000
202 UTAH - BLUE SKY REVENUE-COMMERCIAL 820,935 0 0.0000
203 WASHINGTON - 02GN24EV45-WA ELECTRIC VEHICLE FAST CHG 158 23,670 3 52,667 0.1498
204 WASHINGTON - 02GNSB0024-WA GEN SRVC DO 27,682 2,963,211 1,500 18,442 0.1070
205 WASHINGTON - 02GNSB024F-GEN SRVC DOM/F 1 220 1 1,000 0.2198
206 WASHINGTON - 02GNSB24FP-WA GEN SVC SEASONAL 378 89,352 63 6,000 0.2364
207 WASHINGTON - 02GNSV0024-WA GEN SRVC 478,679 48,650,438 14,976 31,963 0.1016
208 WASHINGTON - 02GNSV0029-WA NON RES TOU PILOT 142 25,734 1 142,000 0.1812
209 WASHINGTON - 02GNSV024F-WA GEN SRVC-FL 1,227 179,683 107 11,467 0.1464
210 WASHINGTON - 02LGSB0036-LRG GEN SVC IRG 38,334 3,419,136 72 532,417 0.0892
211 WASHINGTON - 02LGSV0036-WA LRG GEN SRV 776,211 66,626,223 883 879,061 0.0858
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214 WASHINGTON - 02LNX00103-LINE EXT 80% G 28,707 0 0.0000
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217 WASHINGTON - 02LNX00110-REF/NREF ADV +22,541 0 0.0000
218 WASHINGTON - 02LNX00112-YR INCURRED CH 669 0 0.0000
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224 WASHINGTON - 02OALT015N-WA OUTD AR LGT 1,358 115,453 744 1,825 0.0850
225 WASHINGTON - 02OALTB15N-WA OUTD AR LGT NR 471 53,541 442 1,066 0.1137
226 WASHINGTON - 02RCFL0054-WA REC FIELD L 339 20,535 25 13,560 0.0606
227 WASHINGTON - 02NMT24135, Net metering, WA 5,922 626,125 148 40,014 0.1057
228 WASHINGTON - 02NMT36135-WA NET METER LRG SVC < 1000KW 13,651 1,257,244 20 682,550 0.0921
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232 WASHINGTON - REVENUE_ACCOUNTING ADJUSTMENTS (407,663)0 0.0000
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239 WYOMING - 05GNSV0028-GEN SVC > 15 KW - A 802,494 66,802,531 3,067 261,654 0.0832
240 WYOMING - 05GNSV0029-WY GEN SVC TOU PILOT - A 1,065 221,102 4 266,250 0.2076
241 WYOMING - 05GNSV025F-GEN SRVC-FL RA - A 987 155,552 171 5,772 0.1576
242 WYOMING - 05LGSV0046-WY LRG GEN SRV 229,817 15,243,817 21 10,943,667 0.0663
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250 WYOMING - 05LNX00114-TEMP SVC 12MO>322 0 0.0000
251 WYOMING - 05NMT25135 - WY NET MTR, GEN, < 25 KW - A 585 55,770 44 13,295 0.0953
252 WYOMING - 05NMT28135-NET MTR SMALL GEN SVC > 15 KW - A 9,993 894,133 29 344,586 0.0895
253 WYOMING - 05OALT015N-OUTD AR LGT SR - A 2,435 230,423 1,504 1,619 0.0946
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255 WYOMING - 05LNX00300 - LINE EXT 80% GUARANTEE 114,063 0 0.0000
256 WYOMING - 05LNX00310-LINE EXTENSION CONTRACT 307 0 0.0000
257 WYOMING - 05LNX00311 - LINE EXT 80% GUARANTEE - A 36,422 0 0.0000
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259 WYOMING - REVENUE ADJUSTMENT - DEFERRED NPC (280,300)0 0.0000
260 WYOMING - REVENUE_ACCOUNTING ADJUSTMENTS (38,947)0 0.0000
261 WYOMING - DSM REVENUE-SMALL COMMERCIAL - A 2,704,460 0 0.0000
262 WYOMING - DSM REVENUE-LARGE COMMERCIAL 121,289 0 0.0000
263 WYOMING - BLUE SKY REVENUE-COMMERCIAL - A 20,462 1 0.0000
264 WYOMING - 05GNSV0025-WY GEN SRVC - B 31,527 3,101,746 2,546 12,388 0.0984
265 WYOMING - 05GNSV0028-GEN SVC > 15 KW - B 90,259 7,423,655 385 234,439 0.0822
266 WYOMING - 05GNSV0029-WY GEN SVC TOU PILOT - B 401 85,845 2 200,500 0.2141
267 WYOMING - 05GNSV025F-GEN SRVC-FL RA - B 199 24,979 33 6,030 0.1255
268 WYOMING - 05LNX00102-LINE EXT 80% G - B 120,090 0 0.0000
269 WYOMING - 05LNX00103-LINE EXT 80% G - B 585 0 0.0000
270 WYOMING - 05LNX00109-REF/NREF ADV + - B 127,359 0 0.0000
271 WYOMING - 05LNX00110-REF/NREF ADV + - B 5,118 0 0.0000
272 WYOMING - 05NMT25135 - WY NET MTR, GEN, < 25 KW - B 93 8,300 6 15,500 0.0892
273 WYOMING - 05NMT28135-NET MTR SMALL GEN SVC > 15 KW - B 414 33,412 2 207,000 0.0807
274 WYOMING - 05OALT015N-OUTD AR LGT SR - B 254 26,512 139 1,827 0.1044
275 WYOMING - 05RCFL0054-WY REC FIELD L - B 237 10,674 13 18,231 0.0450
276 WYOMING - 05LNX00311 - LINE EXT 80% GUARANTEE - B 2,753 0 0.0000
277 WYOMING - DSM REVENUE-SMALL COMMERCIAL - B 187,267 0 0.0000
278 WYOMING - BLUE SKY REVENUE-COMMERCIAL - B 796 0 0.0000
279 LESS MULTIPLE BILLINGS (22,373)
41 TOTAL Billed Small or Commercial 19,502,876 1,668,981,782 225,281 86,871 0.0853
42 TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)67,367 9,859,000 0.0005
43 TOTAL Small or Commercial 19,570,243 1,678,840,782 225,281 86,871 0.0858
FERC FORM NO. 1 (ED. 12-95)
Page 304
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 525 76,190 79 6,646 0.1451
2 CALIFORNIA - 06GNSV0A32-GEN SRVC-20 KW 3,787 539,093 22 172,136 0.1424
3 CALIFORNIA - 06LGSV048T-LRG GEN SERV - A 56,003 5,182,546 9 6,222,556 0.0925
4 CALIFORNIA - 06LGSV0A36-LRG GEN SRVC-O 5,452 738,786 12 454,333 0.1355
5 CALIFORNIA - INCOME TAX DEFERRAL ADJUSTMENTS - A 188,835 0.0000
6 CALIFORNIA - REVENUE_ACCOUNTING ADJUSTMENTS - A (60,670)0.0000
7 CALIFORNIA - DSM REVENUE-INDUSTRIAL 112,118 0.0000
8 CALIFORNIA - BLUE SKY REVENUE-INDUSTRIAL 981 0.0000
9 CALIFORNIA - OTHER CUSTOMER RETAIL REVENUE - A 27,804 0.0000
10 IDAHO - 07CFR00001-MTH FACILITY S 2,217 0.0000
11 IDAHO - 07CISH0019-COMM & IND SPA 1 112 0.1118
12 IDAHO - 07GNSV0006-GEN SRVC-LRG P 75,262 5,699,017 101 745,168 0.0757
13 IDAHO - 07GNSV0009-GEN SRVC-HI VO 63,770 4,354,614 14 4,555,000 0.0683
14 IDAHO - 07GNSV0023-GEN SRVC-SML P 16,447 1,549,453 304 54,102 0.0942
15 IDAHO - 07GNSV006A-GEN SRVC-LRG P 2,218 205,719 21 105,619 0.0927
16 IDAHO - 07GNSV009M-MANL HIGH VOLT 102,556 6,203,547 1 102,556,000 0.0605
17 IDAHO - 07GNSV023A-GEN SRVC-SML P - A 1,829 192,383 132 13,856 0.1052
18 IDAHO - 07GNSV023S-IDAHO TRAFFIC SIGNALS 4 567 1 4,000 0.1417
19 IDAHO - 07LNX00108-ANN COST MTHLY 1,996 0.0000
20 IDAHO - 07LNX00311 - LINE EXT 80% GUARANTEE 17 0.0000
21 IDAHO - 07NMT23135 - ID NET MTR - SMALL GEN SVC 30 2,832 1 30,000 0.0944
22 IDAHO - 07OALT007N-SECURITY AR LG 13 2,895 16 813 0.2227
23 IDAHO - 07OALT07AN-SECURITY AR LG 146 1 0.0000
24 IDAHO - 07SPCL0001 1,409,500 88,650,250 1 1,409,500,000 0.0629
25 IDAHO - 07SPCL0002 20,538 1,120,155 0.0545
26 IDAHO - REVENUE_ACCOUNTING ADJUSTMENTS - A 118,681 0.0000
27 IDAHO - DSM REVENUE-INDUSTRIAL (42,137)0.0000
28 IDAHO - BLUE SKY REVENUE-INDUSTRIAL 13 0.0000
29 OREGON - 01COST0023, OR GEN SRV, COST BASED 17,947 870,417 0.0485
30 OREGON - 01COST0048 - 01LGSV0048 - A 1,234,258 51,988,574 0.0421
31 OREGON - 01COST023F - OR GEN SRV - COST-BASED 1 53 0.0530
32 OREGON - 01COST30MT-LG GEN SVC>200KW COST TOU MTR 27,999 1,065,699 0.0381
33 OREGON - 01COSTB023 - OR GEN SRV, CST-BSD SPLY 137 6,423 0.0469
34 OREGON - 01COSTL030 - OR LRG GEN SRV, CST >200 kW 152,008 5,794,040 0.0381
35 OREGON - 01COSTS028, OR GEN SERV, COST > 30kW 76,872 3,745,103 0.0487
36 OREGON - 01GNSB0023, OR GEN SRV, BPA, < 30 kW 9,852 12 0.0000
37 OREGON - 01GNSB0028, OR GEN SRV, BPA, > 30 kW 5,094 1 0.0000
38 OREGON - 01GNSV0023, OR GEN SRV, < 30 KW 1,090,107 951 0.0000
39 OREGON - 01GNSV0028, OR GEN SRV > 30 kW 3,272,502 378 0.0000
40 OREGON - 01GNSV023F - OR GEN SRV - FLAT RATE 2 673 2 1,000 0.3366
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41 OREGON - 01GNSV023M - OR GEN SRV, MANUAL BILL 306 1 0.0000
42 OREGON - 01GNSV023T, OR GEN SRV, TOU Option - A 2,682 3 0.0000
43 OREGON - 01GNSV0728 - OR GEN SVC DIR ACCESS >30KW 0.0000
44 OREGON - 01GNSV0730 -OR GEN SVC DIR ACCESS >200KW 44,927 1 0.0000
45 OREGON - 01GNSV0748 LG GEN SVC DIR ACCESS 1000KW+1,221,749 2 0.0000
46 OREGON - 01LGSV0030 - OR LRG GEN SRV, > 1000 kW 7,322,578 111 0.0000
47 OREGON - 01LGSV0048-1000KW AND OVR - A 24,723,797 77 0.0000
48 OREGON - 01LGSV048M-LRG GEN SRVC 1 42,396 2,722,242 3 14,132,000 0.0642
49 OREGON - 01LGSV30MN-OR LG GEN SVC>200 KW NO AUTO 34,543 1 0.0000
50 OREGON - 01LGSVT030-OR LG GEN SVC>200KW TOU MTR 1,165,934 10 0.0000
51 OREGON - 01LNX00102-LINE EXT 80% G 95,278 0.0000
52 OREGON - 01LNX00109-REF/NREF ADV + A 295 0.0000
53 OREGON - 01LNX00300 - LINE EXT 80% GUARANTEE 15,181 0.0000
54 OREGON - 01LPRS047M-PART REQ SRVC 792 675,500 1 792,000 0.8529
55 OREGON - 01NMT23135 - OR NET MTR, GEN, < 30 kW 3,533 5 0.0000
56 OREGON - 01NMT28135 - OR NET MTR, GEN, > 30 kW 90,671 8 0.0000
57 OREGON - 01NMT30135 - OR NET MTR, GEN, > 200 kW 80,271 2 0.0000
58 OREGON - 01OALT015N-OUTD AR LGT NR 244 22,886 113 2,159 0.0938
59 OREGON - 01OALTB15N-OR OUTD AR LGT NR 3 370 3 1,000 0.1233
60 OREGON - 01PTOU0023, OR GEN SRV, TOU ENG SPLY SRV - A 42 2,069 0.0493
61 OREGON - 01RENW0023, OR RENW USAGE SPLY SRV 132 6,447 0.0488
62 OREGON - 01VIR23136-OR VOLUME INCENTIVE <= 30 KW 1,126 1 0.0000
63 OREGON - 01VIR28136-OR VOLUME INCENTIVE > 30 KW 15,744 2 0.0000
64 OREGON - 01VIR30136-OR VOLUME INCENTIVE > 200 kW 84,954 1 0.0000
65 OREGON - INCOME TAX DEFERRAL ADJUSTMENTS - A 757,916 0.0000
66 OREGON - OR GAIN ON SALE OF ASSET - A (4,461)0.0000
67 OREGON - REVENUE_ACCOUNTING ADJUSTMENTS - A 287,228 0.0000
68 OREGON - SOLAR FEED-IN REVENUE - A 437,383 0.0000
69 OREGON - OTHER CUSTOMER RETAIL REVENUE - A 89,922 0.0000
70 OREGON - COMMUNITY SOLAR REVENUE - A 47,913 0.0000
71 OREGON - DSM REVENUE-INDUSTRIAL 6,126,070 0.0000
72 OREGON - BLUE SKY REVENUE-INDUSTRIAL 462,786 4 0.0000
73 UTAH - 08CFR00051-MTH FAC SRVCHG 15,065 0.0000
74 UTAH - 08CGM23136-UTAH NET METER SM GEN SVC 13 1,558 1 13,000 0.1199
75 UTAH - 08CGN06136-UT GEN SVC TRANSITION GEN 1,402 114,073 1 1,402,000 0.0814
76 UTAH - 08CGN06137-UT GEN SVC CUST GEN 137 88 11,499 1 88,000 0.1307
77 UTAH - 08CGN23136-UTAH NET METER SMALL GEN SVC 44 4,175 1 44,000 0.0949
78 UTAH - 08CGN23137-UT NET MTR SMALL GEN SVC 34 3,347 1 34,000 0.0984
79 UTAH - 08GNSV0006-GEN SRVC-DISTR 577,971 48,625,396 886 652,337 0.0841
80 UTAH - 08GNSV0009-GEN SRVC-HI VO 2,789,237 153,981,375 98 28,461,602 0.0552
81 UTAH - 08GNSV0023-GEN SRVC-DISTR 52,956 5,047,783 3,056 17,329 0.0953
82 UTAH - 08GNSV006A-GEN SRVC-ENERG 52,978 6,121,210 230 230,339 0.1155
83 UTAH - 08GNSV006M-MNL DIST VOLTG 23 7,564 0.3289
84 UTAH - 08GNSV009A-GEN SRVC HI VO 15,058 1,241,675 6 2,509,667 0.0825
85 UTAH - 08GNSV009M-MANL HIGH VOLT 688,073 35,991,694 11 62,552,091 0.0523
86 UTAH - 08GNSV023F-GEN SRVC FIXED 4 2,763 1 4,000 0.6908
87 UTAH - 08GNSV06MN-GNSV DIST VOLT 568 54,455 16 35,500 0.0959
88 UTAH - 08LNX00002-MTHLY 80% GUAR - A 726,892 0.0000
89 UTAH - 08LNX00014-80% MIN MNTHLY - A 13,702 0.0000
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90 UTAH - 08LNX00017-ADV/REF&80%ANN - A 640 0.0000
91 UTAH - 08LNX00300 - LINE EXT 80% PLUS MONTHLY 112,690 0.0000
92 UTAH - 08OALT007N-SECURITY AR LG 819 88,663 367 2,232 0.1083
93 UTAH - 08TOSS0015-TRAF & OTHER S 64 5,725 11 5,818 0.0895
94 UTAH - 08MONL0015-MTR OUTDONIGHT 21 1,590 6 3,500 0.0757
95 UTAH - 08NMT06135-UT NET METERING GEN SVC 2,355 216,471 6 392,500 0.0919
96 UTAH - 08NMT23135 - UT NET MTR, GEN, < 25 KW 123 15,152 17 7,235 0.1232
97 UTAH - 08NMT6A135-NET METERING GEN SVC TOU 5,936 672,460 13 456,615 0.1133
98 UTAH - 08PRSV031M-BKUP MNT&SUPPL 55,879 4,068,556 3 18,626,333 0.0728
99 UTAH - 08SPCL0001 641,262 35,089,290 1 641,262,000 0.0547
100 UTAH - 08SPCL0002 306,200 15,458,579 1 306,200,000 0.0505
101 UTAH - 08SPCL0003 1,285,246 93,586,499 1 1,285,246,000 0.0728
102 UTAH - 08SSLR0006-GENERAL SVC SUBSCR SOLAR 262 28,736 2 131,000 0.1097
103 UTAH - 08SSLR0023-SMALL GEN SVC SUBSCR SOLAR 189 22,419 27 7,000 0.1186
104 UTAH - 08SSLR06AM-GEN SVC TOU SOLAR SUBSCR MAN 982,076 31 0.0000
105 UTAH - 08TCVLNXGN-TCV LNX - 80% GAR - NON RES - A 20,319 0.0000
106 UTAH - REVENUE_ACCOUNTING ADJUSTMENTS - A (160,313)0.0000
107 UTAH - REVENUE ADJUSTMENT - DEFERRED NPC - A 20,273,988 0.0000
108 UTAH - 08GNSV06AM-MNL ENERGY TOD 404 64,276 3 134,667 0.1591
109 UTAH - 08GNSV0008 - UT GEN SVC TOU > 1000KW 959,040 69,623,136 92 10,424,348 0.0726
110 UTAH - 08GNSV008M - UT GEN SVC TOU > 1000KW 25,348 1,970,553 4 6,337,000 0.0777
111 UTAH - SOLAR FEED-IN REVENUE - A 241,546 0.0000
112 UTAH - OTHER CUSTOMER RETAIL REVENUE - A 86,467 0.0000
113 UTAH - DSM REVENUE-INDUSTRIAL 9,704,636 0.0000
114 UTAH - BLUE SKY REVENUE-INDUSTRIAL 158,868 6 0.0000
115 WASHINGTON - 02GNSB0024-WA GEN SRVC DO 923 109,907 41 22,512 0.1191
116 WASHINGTON - 02GNSB24FP-WA GEN SVC SEASONAL 4 1,692 1 4,000 0.4229
117 WASHINGTON - 02GNSV0024-WA GEN SRVC 14,422 1,476,714 322 44,789 0.1024
118 WASHINGTON - 02GNSV024F-WA GEN SRVC-FL 33 9,032 4 8,250 0.2737
119 WASHINGTON - 02LGSV0036-WA LRG GEN SRV 84,788 7,661,323 88 963,500 0.0904
120 WASHINGTON - 02LGSV048M-WA LRG GEN SRV 463,568 30,682,636 1 463,568,000 0.0662
121 WASHINGTON - 02LGSV048T-LRG GEN SRVC 1 194,358 15,347,387 29 6,702,000 0.0790
122 WASHINGTON - 02LNX00103-LINE EXT 80% G - A 11,579 0.0000
123 WASHINGTON - 02NMB24135-WA NET METERING 59 1 0.0000
124 WASHINGTON - 02NMT24135, Net metering, WA 27 3,817 3 9,000 0.1414
125 WASHINGTON - 02NMT36135-WA NET METER LRG SVC < 1000KW 11,002 1 0.0000
126 WASHINGTON - 02OALT015N-WA OUTD AR LGT 96 6,786 37 2,595 0.0707
127 WASHINGTON - 02OALTB15N-WA OUTD AR LGT NR 27 2,726 14 1,929 0.1010
128 WASHINGTON - 02PRSV47TM-LRG PART REQMT 2,139 341,445 1 2,139,000 0.1596
129 WASHINGTON - 02LGSB0036-LRG GEN SVC IRG 772 113,629 6 128,667 0.1472
130 WASHINGTON - INCOME TAX DEFERRAL ADJUSTMENTS - A 406,788 0.0000
131 WASHINGTON - REVENUE ADJUSTMENT - DEFERRED NPC - A 19,992 0.0000
132 WASHINGTON - REVENUE_ACCOUNTING ADJUSTMENTS - A 1,035,615 0.0000
133 WASHINGTON - BLUE SKY REVENUE-INDUSTRIAL 20 0.0000
134 WASHINGTON - DSM REVENUE-INDUSTRIAL 1,996,302 0.0000
135 WASHINGTON - ALT REVENUE PROGRAM ADJUSTMENTS - A 172,949 0.0000
136 WYOMING - 05GNSV0025-WY GEN SRVC - A 20,178 1,843,823 1,107 18,228 0.0914
137 WYOMING - 05GNSV0028-GEN SVC > 15 KW - A 228,488 16,098,123 393 581,394 0.0705
138 WYOMING - 05GNSV0029-WY GEN SVC TOU PILOT 307 26,854 3 102,333 0.0875
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139 WYOMING - 05GNSV025F-GEN SRVC-FL RA 26 4,222 8 3,250 0.1624
140 WYOMING - 05LGSV0046-WY LRG GEN SRV - A 1,550,437 97,105,673 57 27,200,649 0.0626
141 WYOMING - 05LGSV046M-WY LRG GEN SRV 7,147 580,915 1 7,147,000 0.0813
142 WYOMING - 05LGSV048M-TOU>1000KW MAN - A 347,580 18,492,695 1 347,580,000 0.0532
143 WYOMING - 05LGSV048T-LRG GENSRV TIM -A 2,054,477 108,411,240 11 186,770,636 0.0528
144 WYOMING - 05LNX00100-LINE EXT 60% G 90,440 0.0000
145 WYOMING - 05LNX00102-LINE EXT 80% G - A 365,732 0.0000
146 WYOMING - 05LNX00105-CNTRCT $ MIN G 30,474 0.0000
147 WYOMING - 05LNX00109-REF/NREF ADV + A 107,444 0.0000
148 WYOMING - 05LNX00300 - LINE EXT 80% GUARANTEE 148,899 0.0000
149 WYOMING - 05LNX00311 - LINE EXT 80% GUARANTEE 15,188 0.0000
150 WYOMING - 05OALT015N-OUTD AR LGT SR - A 67 5,123 38 1,763 0.0765
151 WYOMING - 05PRSV033M-PART SERV REQ - A 1,093,319 72,298,521 10 109,331,900 0.0661
152 WYOMING - INCOME TAX DEFERRAL ADJUSTMENTS - B 1,456,100 0.0000
153 WYOMING - REVENUE ADJUSTMENT - DEFERRED NPC - A (1,256,753)0.0000
154 WYOMING - REVENUE_ACCOUNTING ADJUSTMENTS - A (174,623)0.0000
155 WYOMING - DSM REVENUE-SMALL INDUSTRIAL - A 561,018 0.0000
156 WYOMING - DSM REVENUE-LARGE INDUSTRIAL - A 2,114,548 0.0000
157 WYOMING - BLUE SKY REVENUE-INDUSTRIAL - A 440 0.0000
158 WYOMING - 05GNSV0025-WY GEN SRVC - B 4,803 444,263 289 16,619 0.0925
159 WYOMING - 05GNSV0028-GEN SVC > 15 KW - B 54,243 3,814,179 61 889,230 0.0703
160 WYOMING - 05GNSV028M-GEN SVC > 15 KW MANUAL BILL 4,229 243,017 3 1,409,667 0.0575
161 WYOMING - 05LGSV0046-WY LRG GEN SRV - B 9,798 637,179 2 4,899,000 0.0650
162 WYOMING - 05LGSV048M-TOU>1000KW MAN - B 104,270 6,486,995 2 52,135,000 0.0622
163 WYOMING - 05LGSV048T-LRG GENSRV TIM - B 748,645 45,028,043 14 53,474,643 0.0601
164 WYOMING - 05LNX00102-LINE EXT 80% G - B 2,418,105 0.0000
165 WYOMING - 05LNX00109-REF/NREF ADV + B 26,490 0.0000
166 WYOMING - 05NMT25135 - WY NET MTR, GEN, < 25 KW 36 3,014 1 36,000 0.0837
167 WYOMING - 05OALT015N-OUTD AR LGT SR - B 7 500 4 1,750 0.0714
168 WYOMING - 05PRSV033M-PART SERV REQ - B 1,178 298,933 1 1,178,000 0.2538
169 WYOMING - DSM REVENUE-SMALL INDUSTRIAL - B 79,385 0.0000
170 WYOMING - DSM REVENUE-LARGE INDUSTRIAL - B 495,382 0.0000
171 WYOMING - BLUE SKY REVENUE-INDUSTRIAL - B 140 0.0000
172 LESS MULTIPLE BILLINGS (807)
173 CALIFORNIA - 06APSV0020-AG PMP SRVC 9,296 1,122,338 759 12,248 0.1207
174 CALIFORNIA - 06APSV0115-CA AGRI PUMP TOU PILOT,GHG CR 19 5,066 5 3,800 0.2667
175 CALIFORNIA - 06APSV020L-AG PMP SRVC-NO GHG CREDIT 58,425 7,615,212 574 101,786 0.1303
176 CALIFORNIA - 06APSV115L-CA AGRI PUMP TOU, NO GHG CR 797 88,602 6 132,833 0.1112
177 CALIFORNIA - 06LGSV048T-LRG GEN SERV - B 5,612 1 0.0000
178 CALIFORNIA - 06LNX00103-LINE EXT 80% G 1,292 0.0000
179 CALIFORNIA - 06LNX00110-REF/NREF ADV +15,127 0.0000
180 CALIFORNIA - 06LNX00310 - IRG, 80% ANNUAL MIN + 80%14 0.0000
181 CALIFORNIA - 06LNX00312 - CA IRG LINE EXT 11,026 0.0000
182 CALIFORNIA - 06NB20L136-CA IRG NET BILL NO GHG CR 108 10,560 1 108,000 0.0978
183 CALIFORNIA - 06NBL20136-CA IRG NET BILLING 193 20,326 0.1053
184 CALIFORNIA - 06NML20135-AGRI PUMP-NET MTR NO GHG CR 2,597 459,217 40 64,925 0.1768
185 CALIFORNIA - 06NMT20135-AGRICULTURAL PUMP-NET METER 151 25,883 20 7,550 0.1714
186 CALIFORNIA - 06USBR0020-KLAM IRG ONPRJ 3,435 491,374 305 11,262 0.1430
187 CALIFORNIA - 06USBR0115-CA AGR PMP TOU PLT USBR GHG 30 3,999 5 6,000 0.1333
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188 CALIFORNIA - 06USBR020L-KLAM IRG ONPRJ-NO CHG CREDIT 26,730 3,678,315 301 88,804 0.1376
189 CALIFORNIA - 06USBR115L-CA AGR PMP TOU PLT USBR NOGHG 416 55,158 3 138,667 0.1326
190 CALIFORNIA - DSM REVENUE-IRRIGATION 226,786 0.0000
191 CALIFORNIA - BLUE SKY REVENUE-IRRIGATION 49 0.0000
192 CALIFORNIA - OTHER CUSTOMER RETAIL REVENUE - B 49,161 0.0000
193 CALIFORNIA - INCOME TAX DEFERRAL ADJUSTMENTS - B 333,776 0.0000
194 CALIFORNIA - REVENUE_ACCOUNTING ADJUSTMENTS - B (135,810)0.0000
195 IDAHO - 07APSA010L - IRG & Pump Large Load 333,268 31,384,149 2,155 154,649 0.0942
196 IDAHO - 07APSA010S - IRG & Pump Small Load 5,949 640,281 315 18,886 0.1076
197 IDAHO - 07APSAL10X - IRG & PUMP - Large load 279,262 26,497,051 2,070 134,909 0.0949
198 IDAHO - 07APSAS10X - IRG & PUMP - Small load 9,622 1,082,452 610 15,774 0.1125
199 IDAHO - 07APSV006A-LRG POWER OPTIONAL SVC - IRG 607 47,097 1 607,000 0.0776
200 IDAHO - 07APSV023A-SMALL POWER OPTIONAL SVC-IRG 250 25,783 4 62,500 0.1031
201 IDAHO - 07APSVCNLL-LRG LOAD CANAL 13,733 1,181,830 36 381,472 0.0861
202 IDAHO - 07APSVCNLS-SML LOAD CANAL 53 6,771 11 4,818 0.1277
203 IDAHO - 07GNSV023A-GEN SRVC-SML P - B 171 15,356 1 171,000 0.0898
204 IDAHO - 07LNX00015-ANNUAL 80%GUAR 59,810 0.0000
205 IDAHO - 07LNX00035-ADV 80%MO GUAR 1,404 0.0000
206 IDAHO - 07LNX00040-ADV+REFCHG+80%76,030 0.0000
207 IDAHO - 07LNX00310 80% ANNUAL GUARANTEE 3,122 0.0000
208 IDAHO - 07LNX00312 - ID LINE EXT 12,810 0.0000
209 IDAHO - 07NBL10136-ID IRG LRG LOAD NET BILLING 173 1 0.0000
210 IDAHO - 07NM10X135-ID NET METERING - IRG 139 14,331 3 46,333 0.1031
211 IDAHO - 07APSN010L - ID LG IRR & PUMP 13,014 1,164,028 42 309,857 0.0894
212 IDAHO - 07APSN010S - IRRIGATION, SMALL, 3 PH 87 9,117 3 29,000 0.1048
213 IDAHO - 07APSNS10X - IRRIGATION, SMALL, 3 PHASE 313 36,865 20 15,650 0.1178
214 IDAHO - REVENUE_ACCOUNTING ADJUSTMENTS - B 412,489 0.0000
215 IDAHO - DSM REVENUE-IRRIGATION 1,245,505 0.0000
216 IDAHO - BLUE SKY REVENUE-IRRIGATION 51 0.0000
217 OREGON - 01APSBA41T-OR IRR TOU OPT A - 2PM-6PM 63,298 43 0.0000
218 OREGON - 01APSBB41T-OR IRR TOU OPT B - 6PM-10PM 6,475 23 0.0000
219 OREGON - 01APSBT041-OR IRG TOU METER 622 2 0.0000
220 OREGON - 01APSV0041-AG PMP SRVC BP 1,046,636 2,198 0.0000
221 OREGON - 01APSV0215-OR IRRIGATION TOU PILOT 4 0.0000
222 OREGON - 01APSV041L-OR Pumping Serv >30KW 1,598,930 550 0.0000
223 OREGON - 01APSV041T - AGR PUMP SRV-TOU OPTION 16,854 37 0.0000
224 OREGON - 01APSV041X-AG PMP SRVC<30 kW 1,232,681 2,707 0.0000
225 OREGON - 01APSV41TA-OR IRG PUMPING TOU OPT-A 33,881 34 0.0000
226 OREGON - 01APSV41TB-OR IRG PUMPING TOU OPT-B 5,282 15 0.0000
227 OREGON - 01APSV41XL-OR Pumping Serv no BPA >30KW 1,964,514 502 0.0000
228 OREGON - 01APSVT041-OR IRG TOU METER 1,834 2 0.0000
229 OREGON - 01APSVT41L-OR AGRICULTUARL PUMPING>30 KW 4,185 1 0.0000
230 OREGON - 01COST0041 -01APSV0041-01APSV041X AG PMP 108,589 5,004,413 0.0461
231 OREGON - 01COST0048 - 01LGSV0048 - B 19,051 795,182 0.0417
232 OREGON - 01COST0215-OR TOU PILOT COST BASED SPPLY 2,602 119,927 0.0461
233 OREGON - 01COST041T- AG IRG TOU ENERGY SUPPLY SVC 2,002 87,419 0.0437
234 OREGON - 01COST41MT-OR IRG COST SUPPLY TOU MTR 91 4,202 0.0462
235 OREGON - 01CSTU41MT-USBR IRG COST SUPPLY SVC TOU 626 28,870 0.0461
236 OREGON - 01CSTUSB41-USBR IRRIGATION CONTRACTS CSS 72,494 3,340,446 0.0461
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237 OREGON - 01GNSV023T, OR GEN SRV, TOU Option - B 304 1 0.0000
238 OREGON - 01HABIT041 - 01APSV0041 AG PMP SRVC 2 97 0.0487
239 OREGON - 01LGSB0048 - LG GEN SVC > 1000KW (R)(11,097)0.0000
240 OREGON - 01LGSV0048-1000KW AND OVR - B 510,146 2 0.0000
241 OREGON - 01LNX00103-LINE EXT 80% G 35,704 0.0000
242 OREGON - 01LNX00109-REF/NREF ADV + B 151 0.0000
243 OREGON - 01LNX00110-REF/NREF ADV +112,457 0.0000
244 OREGON - 01LNX00310-LINE EXTENSION CONTRACT 13,901 0.0000
245 OREGON - 01PTOU0023, OR GEN SRV, TOU ENG SPLY SRV - B 2 123 0.0615
246 OREGON - 01PTOU0041 - 01APSV0041 AG PMP SRVC 262 12,118 0.0463
247 OREGON - 01RENEW041 - 01APSV0041 AG PMP SRVC 75 3,442 0.0459
248 OREGON - 01STDAY041 - Daily Standard Offer Sch 25 164 13,256 0.0808
249 OREGON - 01USBOFT41-OR USBR IRG OFF PRJCT LND TOU 32,740 9 0.0000
250 OREGON - 01USBONT41-USBR IRG CONTR-PRJCT LND TOU 26,499 7 0.0000
251 OREGON - 01USBR0215-OR IRG TOU PILOT USBR CUST 66,408 31 0.0000
252 OREGON - 01USBRGV41-IRG TOU W/O BPA 10,941 9 0.0000
253 OREGON - 01USBROF41-KLAMATH BASIN IRG OFF PRJ LND 1,433,103 464 0.0000
254 OREGON - 01USBRON41-KLAMATH BASIN IRG ON PJT LND 1,747,998 1,090 0.0000
255 OREGON - 01VIR41136-OR VOLUME INCENTIVE-AGRI PUMP 53,414 26 0.0000
256 OREGON - 01VRU41136-OR VOL INCENTIVE USB CONTRACT 401,700 105 0.0000
257 OREGON - 01VRU41215-OR VOL INCENTIVE USB TOU PLT 35,242 5 0.0000
258 OREGON - SOLAR FEED-IN REVENUE - B 54,566 0.0000
259 OREGON - OTHER CUSTOMER RETAIL REVENUE - B 13,416 0.0000
260 OREGON - COMMUNITY SOLAR REVENUE - B 6,162 0.0000
261 OREGON - INCOME TAX DEFERRAL ADJUSTMENTS - B 113,075 0.0000
262 OREGON - OR GAIN ON SALE OF ASSET - B (102)0.0000
263 OREGON - DSM REVENUE-IRRIGATION 903,087 0.0000
264 OREGON - BLUE SKY REVENUE-IRRIGATION 535 0.0000
265 OREGON - 01LNX00312 - OR IRG LINE EXT 34,071 0.0000
266 OREGON - 01LNX00316-LINE EXTENTION 121 0.0000
267 OREGON - 01NMB41135-OREGON NET METER IRRIGATION 22,502 24 0.0000
268 OREGON - 01NMO41135-OR USBR IRG NT MTR OFF PJ LND 1,765 1 0.0000
269 OREGON - 01NMT41135 - NETMTR AG PMP SVC 26,471 31 0.0000
270 OREGON - 01NMU41135 - OR NET MTR - PROJECT LAND 35,869 12 0.0000
271 OREGON - REVENUE_ACCOUNTING ADJUSTMENTS - B (9,590)0.0000
272 UTAH - 08APSV0010-IRR & SOIL DRA 198,271 14,736,269 3,110 63,753 0.0743
273 UTAH - 08APSV10NS- Irg Soil Drain Pump Non Seas 53,775 3,663,344 327 164,453 0.0681
274 UTAH - 08CGM10136-UT IRG NET METER MANUAL 585 42,119 2 292,500 0.0720
275 UTAH - 08CGN10136-UT IRG AND SOIL DRAIN NET MTR 6 806 1 6,000 0.1343
276 UTAH - 08CGN10137-UT IRRIGATION - NET METER 137 239 16,932 1 239,000 0.0708
277 UTAH - 08LNX00002-MTHLY 80% GUAR - B 427 0.0000
278 UTAH - 08LNX00004-ANNUAL 80%GUAR 7,890 0.0000
279 UTAH - 08LNX00014-80% MIN MNTHLY - B 6,778 0.0000
280 UTAH - 08LNX00017-ADV/REF&80%ANN - B 134,459 0.0000
281 UTAH - 08LNX00310 - IRR, 80% ANNUAL MIN + 80% ?11,740 0.0000
282 UTAH - 08LNX00311 - LINE EXT 80% GUARANTEE 2,386 0.0000
283 UTAH - 08LNX00312 UT IRG LINE EXT 17,147 0.0000
284 UTAH - 08NMT010NS-IRR & SOIL DRAIN NON SEASONAL 248 24,935 5 49,600 0.1005
285 UTAH - 08NMT10135-UT IRR_SOIL DRNG NET MTR SVC 7,089 602,065 75 94,520 0.0849
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286 UTAH - 08TCVLAACN-UTAH TCV LNX ANNUAL GAR 3,191 0.0000
287 UTAH - 08TCVLNAGN-UTAH LNX ANNUAL GAR NON RES 24,430 0.0000
288 UTAH - 08TCVLNXGN-TCV LNX - 80% GAR - NON RES - B 131 0.0000
289 UTAH - REVENUE_ACCOUNTING ADJUSTMENTS - B (5,429)0.0000
290 UTAH - REVENUE ADJUSTMENT - DEFERRED NPC - B 686,518 0.0000
291 UTAH - SOLAR FEED-IN REVENUE - B 8,156 0.0000
292 UTAH - OTHER CUSTOMER RETAIL REVENUE - B 2,928 0.0000
293 UTAH - DSM REVENUE-IRRIGATION 327,158 0.0000
294 UTAH - BLUE SKY REVENUE-IRRIGATION 162 0.0000
295 WASHINGTON - 02APSV0040-WA AG PMP SRVC 84,951 8,201,147 2,377 35,740 0.0965
296 WASHINGTON - 02APSV040X-WA AG PMP SRVC 75,667 7,410,333 2,715 27,870 0.0979
297 WASHINGTON - 02LNX00103-LINE EXT 80% G - B 24,391 0.0000
298 WASHINGTON - 02LNX00105-CNTRCT $ MIN G 77 0.0000
299 WASHINGTON - 02LNX00109-REF/NREF ADV +979 0.0000
300 WASHINGTON - 02LNX00110-REF/NREF ADV +80,381 0.0000
301 WASHINGTON - 02LNX00310 - IRG, 80% ANNUAL MIN + 80%12,880 0.0000
302 WASHINGTON - 02LNX00312 - WA IRG LINE EXT 21,624 0.0000
303 WASHINGTON - 02NMT40135-WA NET METERING-IRG 325 39,209 10 32,500 0.1206
304 WASHINGTON - 02NMX40135-WA NET METERING-IRG 83 14,361 13 6,385 0.1730
305 WASHINGTON - REVENUE ADJUSTMENT - DEFERRED NPC - B (125,532)0.0000
306 WASHINGTON - REVENUE_ACCOUNTING ADJUSTMENTS - B 140,919 0.0000
307 WASHINGTON - INCOME TAX DEFERRAL ADJUSTMENTS - B 82,002 0.0000
308 WASHINGTON - DSM REVENUE-IRRIGATION 618,161 0.0000
309 WASHINGTON - BLUE SKY REVENUE-IRRIGATION 2,022 0.0000
310 WASHINGTON - ALT REVENUE PROGRAM ADJUSTMENTS - B (79,608)0.0000
311 WYOMING - 05APS00040-AG PUMPING SVC - A 22,196 1,941,696 757 29,321 0.0875
312 WYOMING - 05APS0040T-WY IRG TOU PILOT 31 3,579 4 7,750 0.1155
313 WYOMING - 05APSNS040-AG PUMPING SVC - NON SEASON 1,822 158,273 34 53,588 0.0869
314 WYOMING - 05LNX00103-LINE EXT 80% G 3,149 0.0000
315 WYOMING - 05LNX00109-REF/NREF ADV + AA 40 0.0000
316 WYOMING - 05LNX00110-REF/NREF ADV + A 41,879 0.0000
317 WYOMING - 05LNX00312 - WY IRG LINE EXT - A 1,205 0.0000
318 WYOMING - 09APSNS210-IRR & SOIL DRA - NON SEASON - A 9 1,186 1 9,000 0.1317
319 WYOMING - INCOME TAX DEFERRAL ADJUSTMENTS - A 8,053 0.0000
320 WYOMING - REVENUE_ACCOUNTING ADJUSTMENTS - B (966)0.0000
321 WYOMING - REVENUE ADJUSTMENT - DEFERRED NPC - B (6,950)0.0000
322 WYOMING - DSM REVENUE-IRRIGATION - A 71,652 0.0000
323 WYOMING - BLUE SKY REVENUE-IRRIGATION - A 40 0.0000
324 WYOMING - 05APS00040-AG PUMPING SVC - B 548 44,813 11 49,818 0.0818
325 WYOMING - 05LNX00109-REF/NREF ADV + BB 138 0.0000
326 WYOMING - 05LNX00110-REF/NREF ADV + B 3,631 0.0000
327 WYOMING - 05LNX00312 - WY IRG LINE EXT - B 147 0.0000
328 WYOMING - 09APSNS210-IRR & SOIL DRA - NON SEASON - B 536 48,378 6 89,333 0.0903
329 WYOMING - 09APSV0210-IRR & SOIL DRA 7,492 587,338 100 74,920 0.0784
330 WYOMING - DSM REVENUE-IRRIGATION - B 11,962 0.0000
331 WYOMING - BLUE SKY REVENUE-IRRIGATION - B 19 0.0000
332 LESS MULTIPLE BILLINGS IRRIGATION (898)
41 TOTAL Billed Large (or Ind.) Sales 19,181,255 1,309,997,894 32,930 2,006,030 0.1630
42 TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)(122,472)14,782,000 0.0021
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43 TOTAL Large (or Ind.)19,058,783 1,324,779,894 32,930 2,006,030 0.1651
FERC FORM NO. 1 (ED. 12-95)Page 304
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
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7
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9
10
11
12
13
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40
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41 TOTAL Billed Commercial and Industrial Sales
42 TOTAL Unbilled Rev. (See Instr. 6)
43 TOTAL
FERC FORM NO. 1 (ED. 12-95)Page 304
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 1,017 152,746 109 9,330 0.1502
2 CALIFORNIA - 06CUSL058F-CUST OWND STR 41 7,440 19 2,158 0.1815
3 CALIFORNIA - 06SLCO0051-COMPANY OWNED STREET LIGHTING 698 213,729 82 8,512 0.3062
4 CALIFORNIA - 06OALT015N-OUTD AR LGT SR 1 408 2 500 0.4079
5 CALIFORNIA - DSM REVENUE-PSHL 5,172 0.0000
6 CALIFORNIA - OTHER CUSTOMER RETAIL REVENUE 820 0.0000
7 CALIFORNIA - INCOME TAX DEFERRAL ADJUSTMENTS 5,471 0.0000
8 CALIFORNIA - REVENUE_ACCOUNTING ADJUSTMENTS (3,645)0.0000
9 IDAHO - 07GNSV023S-IDAHO TRAFFIC SIGNALS 145 17,690 23 6,261 0.1228
10 IDAHO - 07SLCO0011-STR LGT CO-OWN 187 80,079 60 3,117 0.4282
11 IDAHO - 07SLCU012E-ENGY STR LGT-CUST OWN 490 50,241 64 7,656 0.1025
12 IDAHO - 07SLCU012F-FULL MNT STR LGT-CUST OWN 1,775 313,663 191 9,293 0.1767
13 IDAHO - 07SLCU012P-PART MNT STR LGT CUST OWN 193 24,840 16 12,063 0.1287
14 IDAHO - REVENUE_ACCOUNTING ADJUSTMENTS 5,789 0.0000
15 IDAHO - DSM REVENUE-PSHL 10,446 0.0000
16 OREGON - 01COST023F - OR GEN SRV - COST-BASED 603 30,935 0.0513
17 OREGON - 01CUSL0053-CUS-OWNED MTRD 458 34,699 71 6,451 0.0758
18 OREGON - 01GNSV023F - OR GEN SRV - FLAT RATE 108,182 14 0.0000
19 OREGON - 01CUSL053E-STR LGT SVC 6,819 515,923 211 32,318 0.0757
20 OREGON - 01CUSL053F-STR LGT SRVC C 67 5,500 5 13,400 0.0821
21 OREGON - 01CUSL53E2-STR LGT SVC 664 50,229 8 83,000 0.0756
22 OREGON - 01HPSV0051-HI PRESSURE SO 16,014 2,660,709 714 22,429 0.1661
23 OREGON - 01OALT015N-OUTD AR LGT NR 40 5,655 26 1,538 0.1414
24 OREGON - 01OALTB15N-OR OUTD AR LGT NR 12 2,035 12 1,000 0.1696
25 OREGON - 01SLCO0051-OR COMPANY OWNED STREET LIGHT 7,887 1,390,454 438 18,007 0.1763
26 OREGON - COMMUNITY SOLAR REVENUE 274 0.0000
27 OREGON - DSM REVENUE-PSHL 142,516 0.0000
28 OREGON - INCOME TAX DEFERRAL ADJUSTMENTS 17,696 0.0000
29 OREGON - OR GAIN ON SALE OF ASSET (665)0.0000
30 OREGON - REVENUE_ACCOUNTING ADJUSTMENTS 9,812 0.0000
31 OREGON - SOLAR FEED-IN REVENUE (1,684)0.0000
32 OREGON - OTHER CUSTOMER RETAIL REVENUE 2,100 0.0000
33 UTAH - 08CFR00012-STR LGTS (CONV 54 0.0000
34 UTAH - 08CFR00051-MTH FAC SRVCHG 4,529 0.0000
35 UTAH - 08CFR00062-STREET LIGHTS 79 0.0000
36 UTAH - 08OALT007N-SECURITY AR LG 464 65,744 246 1,886 0.1417
37 UTAH - 08TOSS015F-TRAFFIC SIG NM 1,155 99,651 121 9,545 0.0863
38 UTAH - 08SLCO0011-STR LGT CO-OWN 13,333 3,720,392 771 17,293 0.2790
39 UTAH - 08TOSS0015-TRAF & OTHER S 3,320 355,059 1,416 2,345 0.1069
40 UTAH - 08MONL0015-MTR OUTDONIGHT 901 49,274 108 8,343 0.0547
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41 UTAH - 08SLCU012P-STR LGT CUST-O 1,562 134,615 142 11,000 0.0862
42 UTAH - 08SLCU012F-STR LGT CUST-O 748 74,851 58 12,897 0.1001
43 UTAH - 08SLCU012E-DECOR CUST-OWN 36,295 1,663,006 1,104 32,876 0.0458
44 UTAH - DSM REVENUE-PSHL 72,352 0.0000
45 UTAH - REVENUE_ACCOUNTING ADJUSTMENTS (1,177)0.0000
46 UTAH - REVENUE ADJUSTMENT - DEFERRED NPC 148,851 0.0000
47 UTAH - SOLAR FEED-IN REVENUE 1,810 0.0000
48 UTAH - OTHER CUSTOMER RETAIL REVENUE 635 0.0000
49 WASHINGTON - 02CFR00012-STR LGTS (CONV 92 0.0000
50 WASHINGTON - 02CUSL053F-WA STR LGT SRV 1,396 69,113 119 11,731 0.0495
51 WASHINGTON - 02CUSL053M-WA STR LGT SRV 718 35,089 114 6,298 0.0489
52 WASHINGTON - 02SLCO0051-WA COMPANY STREET LIGHTING 1,968 485,284 227 8,670 0.2466
53 WASHINGTON - INCOME TAX DEFERRAL ADJUSTMENTS 1,916 0.0000
54 WASHINGTON - DSM REVENUE-PSHL 21,720 0.0000
55 WASHINGTON - REVENUE_ACCOUNTING ADJUSTMENTS (7,774)0.0000
56 WYOMING - 05CUSL0058-CUST OWND STR 37 1,549 9 4,111 0.0418
57 WYOMING - 05CUSL0E58-WY CUST OWNED STREET LIGHT 1,094 45,588 34 32,176 0.0417
58 WYOMING - 05CUSL0M58-CUST OWNED STREET LT W/MAIT - A 44 2,457 4 11,000 0.0558
59 WYOMING - 05OALT015N-OUTD AR LGT SR 36 2,262 5 7,200 0.0628
60 WYOMING - 05SLCO0051-WY STREET LIGHT COMPANY OWNED - A 9,756 1,545,450 433 22,531 0.1584
61 WYOMING - DSM REVENUE-PSHL - A 46,209 0.0000
62 WYOMING - INCOME TAX DEFERRAL ADJUSTMENTS 3,035 0.0000
63 WYOMING - REVENUE_ACCOUNTING ADJUSTMENTS (364)0.0000
64 WYOMING - REVENUE ADJUSTMENT - DEFERRED NPC (2,620)0.0000
65 WYOMING - 05CUSL0M58-CUST OWNED STREET LT W/MAIT - B 34 4,457 5 6,800 0.1311
66 WYOMING - 05RCFL0054-WY REC FIELD L 88 5,085 17 5,176 0.0578
67 WYOMING - 05SLCO0051-WY STREET LIGHT COMPANY OWNED - B 1,628 260,630 46 35,391 0.1601
68 WYOMING - DSM REVENUE-PSHL - B 4,732 0.0000
69 LESS MULTIPLE BILLINGS (3,510)
41 TOTAL Billed Public Street and Highway Lighting 111,688 14,772,894 3,534 31,033 0.1347
42 TOTAL Unbilled Rev. (See Instr. 6)(2,033)(259,000)(0.0023)
43 TOTAL 109,655 14,513,894 3,534 31,033 0.1324
FERC FORM NO. 1 (ED. 12-95)Page 304
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
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41 TOTAL Billed Provision For Rate Refunds
42 TOTAL Unbilled Rev. (See Instr. 6)
43 TOTAL (3,239,918)
FERC FORM NO. 1 (ED. 12-95)Page 304
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 57,156,481 5,059,677,028 2,037,048
42 TOTAL Unbilled Rev. (See Instr. 6) - All Accounts 7,615 36,870,000
43 TOTAL - All Accounts 57,164,096 5,096,547,028 2,037,048 28,098 0.0907
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
LineNo.Name of Company or Public Authority (Footnote Affiliations)(a)Statistical Classification(b)
FERC Rate Schedule or TariffNumber(c)
Average Monthly Billing Demand (MW)(d)Average Monthly NCP Demand(e)Average Monthly CP Demand(f)Megawatt Hours Sold(g)
Demand
Charges($)(h)
EnergyCharges ($)(i)
OtherCharges ($)(j)
Total ($)(h+i+j)(k)
1 Requirement Sales:
2 Helper City RQ T-6 1 1 1 7,673 136,210 135,578 271,788
3 Helper City Annex RQ T-6 1 1 1 6,454 114,086 114,046 228,132
4 Navajo Tribal Utility Authority RQ T-12 31 31 29 250,114 5,694,270 7,223,748 (q)(215,678)12,702,340
5 Navajo Tribal Utility Authority (Mexican Hat)RQ T-6 0 0 0 905 15,183 15,764 30,947
6 Navajo Tribal Utility Authority (Red Mesa)RQ T-6 2 2 1 9,594 160,862 167,134 327,996
7 Accrual RQ (1,470)(r)(59,569) (59,569)
8 Non-Requirement Sales:
9 Arizona Electric Power Cooperative, Inc.SF T-12 4,395 339,191 339,191
10 Arizona Public Service Company (c)AD T-12 (s)(16,000) (16,000)
11 Arizona Public Service Company SF T-12 21,060 1,687,565 1,687,565
12 Avangrid Renewables, LLC (d)AD T-12 (t)(60,000) (60,000)
13 Avangrid Renewables, LLC SF T-12 137,517 12,234,729 12,234,729
14 Avangrid Renewables, LLC SF T-13 78 (u)7,970 7,970
15 Avista Corporation SF T-12 7,125 592,171 592,171
16 Avista Corporation SF T-13 37 (v)4,697 4,697
17 Avista Corporation SF WSPP-Q 100 1,000 1,000
18 Basin Electric Power Cooperative SF T-12 19,957 2,208,470 2,208,470
19 Black Hills Power, Inc.(e)LF 441 50 50 50 342,102 1,041,262 8,800,028 9,841,290
20 Black Hills Power, Inc.SF T-12 109,876 6,703,038 6,703,038
21 Black Hills Power, Inc.SF WSPP-Q 131 10,645 10,645
22 Bonneville Power Administration SF T-12 241,463 16,068,828 16,068,828
23 Bonneville Power Administration SF T-13 78 (w)4,060 4,060
24 Bonneville Power Administration SF WSPP-Q 24,496 1,745,652 (x)(170)1,745,482
25 BP Energy Company (f)AD T-12 (y)37,740 37,740
26 BP Energy Company SF T-12 65,128 4,582,996 4,582,996
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27 British Columbia Hydro and Power Authority SF T-13 84 (z)5,255 5,255
28 Brookfield Renewable Trading and Marketing LP SF T-12 44,723 3,348,382 3,348,382
29 California Independent System Operator Corporation (g)AD T-12 1 (aa)16 16
30 Calpine Energy Services, L.P.SF T-12 3,173 186,007 186,007
31 Citigroup Energy Inc.(h)AD T-12 (ab)(8,000) (8,000)
32 Citigroup Energy Inc.SF T-12 695,403 29,426,574 29,426,574
33 City of Burbank SF T-12 3,912 398,620 398,620
34 City of Glendale SF T-12 28 2,750 2,750
35 City of Hurricane IF 560 270 22,855 22,855
36 City of Redding SF T-12 2,758 200,570 200,570
37 City of Roseville SF T-12 41,882 3,950,799 3,950,799
38 City of Santa Clara SF T-12 398 20,199 20,199
39 City of St. George, Utah SF T-12 690 31,050 31,050
40 Clatskanie People's Utility District SF T-12 301 21,025 21,025
41 ConocoPhillips Company SF T-12 32,104 1,479,289 1,479,289
42 ConocoPhillips Company SF WSPP-Q 280 16,700 16,700
43 Constellation Energy Generation, LLC (i)AD T-12 166 (ac)9,858 9,858
44 Constellation Energy Generation, LLC SF T-12 102,500 5,873,335 5,873,335
45 Dynasty Power Inc.SF T-12 47,283 6,359,070 6,359,070
46 EDF Trading North America, LLC (j)AD T-12 (ad)(4,965) (4,965)
47 EDF Trading North America, LLC SF T-12 33,102 1,996,708 1,996,708
48 El Paso Electric Company SF T-12 13,222 775,329 775,329
49 Energy Keepers, Inc.SF WSPP-Q 600 43,000 43,000
50 Eugene Water & Electric Board SF T-12 4,503 297,013 297,013
51 Gridforce Energy Management, LLC SF T-13 575 (ae)34,969 34,969
52 Guzman Energy, LLC SF T-12 24,355 1,534,698 1,534,698
53 Idaho Power Company SF T-13 246 (af)33,132 33,132
54 Idaho Power Company SF WSPP-Q 12,200 540,824 540,824
55 Imperial Irrigation District SF T-12 400 35,912 35,912
56 Los Angeles Department of Water and Power SF T-12 9,217 876,673 876,673
57 Macquarie Energy LLC (k)AD T-12 11 (ag)8,410 8,410
58 Macquarie Energy LLC SF T-12 116,548 8,834,680 8,834,680
59 Macquarie Energy LLC SF WSPP-Q 182 14,510 14,510
60 Mercuria Energy America, LLC SF T-12 142,236 12,922,898 12,922,898
61 Modesto Irrigation District SF T-12 30,318 2,897,555 2,897,555
62 Morgan Stanley Capital Group Inc.(l)AD T-12 9 (ah)250 250
63 Morgan Stanley Capital Group Inc.SF T-12 111,075 7,224,809 7,224,809
64 Morgan Stanley Capital Group Inc.SF WSPP-Q 655 79,800 79,800
65 NaturEner Power Watch, LLC SF T-13 48 (ai)1,516 1,516
66 (a)Nevada Power Company SF WSPP-Q 375 46,750 46,750
67 NextEra Energy Marketing, LLC SF T-12 12,779 685,537 685,537
68 Northern California Power Agency SF T-12 400 87,980 87,980
69 NorthWestern Energy SF T-13 112 (aj)9,326 9,326
70 NorthWestern Energy SF WSPP-Q 1,441 90,965 90,965
71 Portland General Electric Company SF T-12 21,336 1,289,518 1,289,518
72 Portland General Electric Company SF T-13 34 (ak)1,703 1,703
73 Powerex Corporation SF T-12 98,051 6,978,027 6,978,027
74 Public Service Company of Colorado IF T-12 57,474 1,298,880 1,298,880
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75 Public Service Company of Colorado (m)AD T-12 207 (al)20,323 20,323
76 Public Service Company of Colorado SF T-12 54,312 3,440,438 3,440,438
77 Public Service Company of Colorado SF T-13 364 (am)21,710 21,710
78 Public Service Company of New Mexico SF T-12 11,699 840,384 840,384
79 Public Utility District No. 1 of Chelan County SF T-13 11 (an)458 458
80 Public Utility District No. 1 of Snohomish County SF T-12 3,045 292,693 292,693
81 Puget Sound Energy, Inc.SF T-12 12,921 983,899 983,899
82 Puget Sound Energy, Inc.SF T-13 21 (ao)2,893 2,893
83 Rainbow Energy Marketing Corporation SF T-12 5,746 423,874 423,874
84 Rainbow Energy Marketing Corporation SF WSPP-Q 13,600 945,600 945,600
85 Sacramento Municipal Utility District SF T-12 163,565 27,347,678 27,347,678
86 Sacramento Municipal Utility District SF T-13 21 (ap)1,080 1,080
87 Salt River Project (n)AD T-12 (aq)(33,010) (33,010)
88 Salt River Project SF T-12 30,012 1,818,854 1,818,854
89 Seattle City Light SF T-12 4,745 535,150 535,150
90 Shell Energy North America (US), L.P.SF T-12 643,141 34,245,332 34,245,332
91 Shell Energy North America (US), L.P.SF WSPP-Q 424,482 22,094,556 22,094,556
92 (b)Sierra Pacific Power Company SF T-13 95 (ar)7,824 7,824
93 Tacoma Power SF T-12 1,072 97,725 97,725
94 Tenaska Power Services Co.(o)AD T-12 (as)(320) (320)
95 Tenaska Power Services Co.SF T-12 224,993 11,043,693 11,043,693
96 Tenaska Power Services Co.SF WSPP-Q 131,454 7,257,690 7,257,690
97 The Energy Authority, Inc.SF T-12 53,221 2,918,650 2,918,650
98 TransAlta Energy Marketing (U.S.) Inc.SF T-12 69,197 7,252,961 7,252,961
99 Tri-State Generation and Transmission Association, Inc.SF T-12 31,530 1,857,956 1,857,956
100 Tri-State Generation and Transmission Association, Inc.SF WSPP-Q 120 9,000 9,000
101 Tucson Electric Power Company SF T-12 18,117 1,181,490 1,181,490
102 Tucson Electric Power Company SF WSPP-Q 510 45,575 45,575
103 Turlock Irrigation District SF T-12 82,638 6,023,964 6,023,964
104 Uniper Global Commodities North America LLC SF T-12 146,095 9,782,389 9,782,389
105 UNS Electric, Inc.SF T-12 11,992 789,566 789,566
106 Utah Associated Municipal Power Systems SF T-12 35 7,350 7,350
107 Utah Associated Municipal Power Systems SF WSPP-Q 11,724 809,498 809,498
108 Utah Municipal Power Agency SF T-12 3,864 61,824 61,824
109 Utah Municipal Power Agency SF WSPP-Q 7,973 382,041 382,041
110 Vitol Inc.SF T-12 378,223 16,898,920 16,898,920
111 Vitol Inc.SF WSPP-Q 7,564 518,383 518,383
112 Western Area Power Administration - SW Region SF T-12 1,000 84,000 84,000
113 Western Area Power Administration - Colorado Missouri SF T-12 302,571 21,102,217 21,102,217
114 Western Area Power Administration - Colorado Missouri SF T-13 949 (at)84,570 84,570
115 Western Area Power Administration - Lower Colorado SF T-12 200 8,400 8,400
116 Western Area Power Administration - Sierra Nevada SF T-12 44,319 2,640,721 2,640,721
117 Western Area Power Administration - Upper Colorado SF T-12 118,682 12,183,538 12,183,538
118 Western Area Power Administration - Upper Colorado SF WSPP-Q 15 1,500 1,500
119 Transmission Loss Sales Revenue (p)AD T-11 124,134 (au)3,663,428 3,663,428
120 Transmission Loss Sales Revenue OS T-11 367,386 (av)23,781,969 23,781,969
121 Netting-Bookouts NA (1,557,053)(aw)(93,805,625)(93,805,625)
122 Netting-Trading NA (ax)(3,711,472)(3,711,472)
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123 Accrual NA (28,493)(ay)(1,770,877)(1,770,877)
15 Subtotal - RQ 273,270 6,120,611 7,656,270 (275,247)13,501,634
16 Subtotal-Non-RQ 4,563,022 1,041,262 350,791,113 (71,667,282)280,165,093
17 Total 4,836,292 7,161,873 358,447,383 (71,942,529)(az)293,666,727
FERC FORM NO. 1 (ED. 12-90)Page 310-311
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
Settlement adjustment.
(d) Concept: StatisticalClassificationCode
Settlement adjustment.
(e) Concept: StatisticalClassificationCode
Black Hills Power, Inc. - contract termination date: December 31, 2023.
(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: OtherChargesRevenueSalesForResale
Load retention payment $(750,002)
Customer service charges related to:534,324
- 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
$(215,678)
(r) 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.
(s) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(t) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(u) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(v) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(w) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(x) Concept: OtherChargesRevenueSalesForResale
Liquidated damages.
(y) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(z) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(aa) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(ab) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(ac) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
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(ad) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(ae) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(af) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ag) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(ah) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(ai) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(aj) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ak) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(al) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(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
Reserve share.
(as) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(at) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(au) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(av) Concept: OtherChargesRevenueSalesForResale
Transmission loss sales revenues collected from PacifiCorp's third-party transmission service customers.
(aw) Concept: OtherChargesRevenueSalesForResale
Reflects transactions that did not physically settle.
(ax) Concept: OtherChargesRevenueSalesForResale
Reflects transactions that were categorized as trading activities.
(ay) 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.
(az) Concept: SalesForResale
For a complete list of the number of customers during 2022 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, 2021 Form No. 1.FERC FORM NO. 1 (ED. 12-90)Page 310-311
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 13,620,311 13,702,637
5 669,378,298 681,733,834
6 81,215,880 74,176,098
7 6,037,863 5,403,741
8
9 726,226 916,105
10 35,516,373 30,859,783
11 412,916 462,521
12
13 806,907,867 807,254,719
14
15 4,940,219 5,275,696
16 21,967,025 19,593,314
17 87,554,667 66,310,145
18 45,590,218 31,198,027
19 13,641,562 11,830,404
20 173,693,691 134,207,586
21 980,601,558 941,462,305
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
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)
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42
43
44 11,944,971 10,210,632
45 342,132 236,861
46 4,545,360 4,546,533
47
48 18,320,087 17,346,302
49 1,840,856 1,890,597
50 36,993,406 34,230,925
51
52
53 381 384
54 751,998 961,454
55 1,254,804 909,945
56 1,697,404 1,821,792
57 (a)(3,200,022)(21,144,614)
58 504,565 (17,451,039)
59 37,497,971 16,779,886
60
61
62 470,211 315,815
63 562,162,331 333,859,748
64 21,750,565 17,000,142
64.1
65 9,956,030 8,840,800
66 11,209,398 10,234,559
67 605,548,535 370,251,064
68
69
70 3,017,477 3,041,462
71 24,419,168 21,376,958
71.1
72 3,540,853 3,197,336
73 30,977,498 27,615,756
74 636,526,033 397,866,820
75
76 601,324,862 682,349,483
76.1 0
77 1,682,317 474,524
78 44,289,596 39,466,614
79 647,296,775 722,290,621
80 2,301,922,337 2,078,399,632
81
82
83 10,931,628 10,250,114
85
86 7,448,335 6,922,647
87
C. Hydraulic Power Generation
Operation
(535) Operation Supervision and Engineering
(536) Water for Power
(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
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88 884,337 998,544
89 2,516,573 2,388,711
90 137,750 61,696
91 1,557,787 1,551,212
92 5,576,135 5,672,396
93 3,905,171 3,332,703
93.1
94 1,227,690 1,246,724
95
96 163,235,255 159,058,497
97 3,619,002 2,330,928
98 2,595,723 2,688,993
99 203,635,386 196,503,165
100
101 1,214,070 851,471
102 89,870 84,542
103 23,548
104 133,217 936,999
105 5,920,439 4,951,310
106
107 13,778,397 11,669,287
107.1
108 14,478,129 17,140,571
109 140,445 70,738
110 120,543 93,758
111 35,898,658 35,798,676
112 239,534,044 232,301,841
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
(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
(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
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134 15,162,245 9,002,354
135 15,291,590 13,698,661
136 4,834,720 4,524,018
137 9,790,876 9,627,966
138
138.1
139 278,823 310,424
140 2,761,700 2,840,278
141 19,851,739 17,375,269
142 1,031,506 546,692
143 3,208,385 3,341,252
144 72,211,584 61,266,914
145
146 (b)(120,037)6,141,981
147 2,031,776 1,955,273
148 8,874,412 9,046,758
148.1
149 98,222,980 116,547,834
150 35,886,919 31,879,531
151 963,955 1,195,363
152 2,451,203 1,947,397
153 616,630 552,196
154 4,797,944 6,796,973
155 153,725,782 176,063,306
156 225,937,366 237,330,220
157
158
159 2,854,050 2,250,883
160 13,510,987 13,919,083
161 40,915,077 41,365,509
162 17,701,894 12,679,848
163 381 2,669
164 74,982,389 70,217,992
165
166
167 1,581 (535)
168 138,037,944 110,137,782
169 4,393,603 3,873,160
170 4,002 1,265
171 142,437,130 114,011,672
172
173
174
175
176 293
177
178 293
179
(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)
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
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180
181 74,576,063 76,127,716
182 16,284,032 9,793,857
183 42,850,057 38,091,540
184 41,115,943 27,252,619
185 (c)16,635,876 16,033,171
186 102,109,509 27,218,326
187 (d)130,712,787 124,791,272
188
189 26,166,699 26,427,417
190 (e)132,843,856 125,437,524
191 15,720 8,074
192 2,440,023 2,520,116
193 (278,308)944,893
194 234,084,431 147,588,397
195
196 (f)26,105,037 26,057,380
197 (g)260,189,468 173,645,777
198 3,245,002,734 2,905,907,427
FERC FORM NO. 1 (ED. 12-93)Page 320-323
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
(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)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: MaintenanceOfMiscellaneousHydraulicPlant
Primarily represents changes in how obligations associated with the implementation of the Klamath Hydroelectric Settlement Agreement will be met.
(b) Concept: MaintenanceSupervisionAndEngineering
Primarily represents wildfire mitigation cost deferrals.
(c) 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)$16,635,876
Less: Situs property loss reserves, net of reimbursements 12,117,542
Revised (924) Property Insurance $4,518,334
To adjust PacifiCorp's formula rate, per FERC Docket No. FA16-4-000 for situs property loss reserves, net of reimbursements.
(d) 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, 2022, pension and postretirement regulatory asset amortization and deferrals were $(16,599,937).
(e) Concept: DuplicateChargesCredit
Includes the offset of pensions and benefits in Account 926, Employee pensions and benefits, pursuant to FERC Docket No. FA16-4-000.
(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)$26,105,037
Less: Write-off of assets under construction 30,175
Revised (935) Maintenance of General Plant $26,074,862
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.
(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)$260,189,468
Less: Situs property loss reserves, net of reimbursements 12,117,542
Less: Pension and postretirement regulatory asset deferrals, net of amortization (16,599,937)
Less: Write-off of assets under construction 30,175
Revised TOTAL Administrative & General Expenses $264,641,688
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 935, Maintenance of General Plant. Refer to footnote on Page 320, Line No. 196, Column (b).
FERC FORM NO. 1 (ED. 12-93)
Page 320-323
(1)
(1)
(1)
(1)
(1)
(2)
(3)
(1)
(2)
(3)
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 ofenergy. 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
LineNo.(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)(l)(m)
(n)
1 Adams Solar Center, LLC (d)AD 0 (at)14,136 14,136
2 Adams Solar Center, LLC LU 22,069 1,598,706 (au)13,909 1,612,615
3 Airport Solar, LLC (e)OS 0 (av)376,250 376,250
4 Amor IX LLC LU 127,386 7,347,934 7,347,934
5 Apple, Inc.LU 3,054 272,159 272,159
6 Arizona Electric Power Cooperative, Inc.SF 3,926 402,926 402,926
7 Arizona Public Service Company SF 67,787 11,559,276 11,559,276
8 Arizona Public Service Company (f)AD 0 (aw)1,763 1,763
9 Avangrid Renewables, LLC SF 1,219,560 105,757,079 (ax)910 105,757,989
10 Avista Corporation SF 146,442 9,021,066 (ay)4,329 9,025,395
11 Basin Electric Power Cooperative, Inc.SF 39,018 9,983,063 9,983,063
12 BC Solar, LLC LU 18,369 1,335,146 1,335,146
13 Bear Creek Solar Center, LLC (g)AD 0 (az)15,354 15,354
14 Bear Creek Solar Center, LLC LU 23,024 1,671,568 (ba)16,437 1,688,005
15 Beaver City Corporation LF 21 2,486 2,486
16 Bell Mountain Hydro, LLC LU 469 46,860 46,860
17 Beryl Solar, LLC LU 3 3 1 6,376 453,711 358,320 812,031
18 Big Top, LLC LU 3,156 251,162 251,162
19 Biomass One, L.P.LU 187,222 16,484,147 2,174,002 18,658,149
20 Biomass One, L.P.(h)AD 0 (bb)(151,378) (151,378)
21 Biomass One, L.P.OS 0 (bc)235,738 235,738
22 Biomass One, L.P.(i)AD 0 (bd)182,202 182,202
23 Birch Power Company, Inc.LU 11,170 653,426 653,426
24 (a)Black Cap Solar, LLC LU 561 50,438 50,438
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 HoursPurchased (Excludingfor Energy Storage)
MegaWattHoursPurchasedfor EnergyStorage
MegaWattHoursReceived
MegaWattHoursDelivered
DemandCharges($)
Energy
Charges ($)
Other
Charges ($)
Total (k+l+m)
of
Settlement($)
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25 Black Hills Power, Inc.SF 8,423 587,376 587,376
26 Bly Solar Center, LLC (j)AD 0 (be)12,547 12,547
27 Bly Solar Center, LLC LU 20,259 1,472,081 14,736 1,486,817
28 Bonneville Power Administration (k)LF 0 183,690 183,690
29 Bonneville Power Administration SF 1,174,490 108,072,551 (bf)24,480 108,097,031
30 Bonneville Power Administration (l)AD 0 (bg)248,561 248,561
31 Bourdet, Peter M LU 288 22,800 22,800
32 Box Canyon Limited Partnership LU 0 1 1 6,170 170,249 170,249
33 BP Energy Company SF 264,649 17,800,957 17,800,957
34 BP Energy Company (m)AD 0 (bh)2,072 2,072
35 Brigham Young University - Idaho IU 37,356 2,184,941 2,184,941
36 Brookfield Renewable Trading and Marketing LP SF 81,823 6,726,224 6,726,224
37 Buckhorn Solar, LLC LU 3 3 1 5,900 454,908 331,562 786,470
38 Butter Creek Power, LLC LU 10,377 819,976 819,976
39 California Independent System Operator Corporation SF 2,319 344,570 344,570
40 Calpine Energy Services, L.P.SF 75,109 5,081,330 5,081,330
41 Cedar Springs III, LLC LU 568,195 10,057,037 10,057,037
42 Cedar Springs Wind, LLC LU 821,087 12,726,833 12,726,833
43 Cedar Valley Solar, LLC LU 3 3 1 6,358 451,592 357,343 808,935
44 Central Oregon Irrigation District LU 0 4 3 24,616 2,241,805 2,241,805
45 Central Rivers Power, LLC LU 4,919 203,450 203,450
46 Chiloquin Solar LLC LU 20,434 1,116,178 1,116,178
47 Chopin Wind, LLC LU 31,603 2,191,158 2,191,158
48 Citigroup Energy Inc.SF 534,642 46,740,361 46,740,361
49 City of Albany LU 496 40,065 40,065
50 City of Anaheim SF 3,215 31,617 31,617
51 City of Astoria LU 57 3,015 3,015
52 City of Burbank SF 6,467 666,469 666,469
53 City of Glendale SF 800 46,000 46,000
54 City of Hurricane (n)LF 3,335 287,004 287,004
55 City of Idaho Falls, Idaho LU 34,438 (bi)1,820,447 1,820,447
56 City of Portland, Portland Water Bureau LU 181 16,039 16,039
57 City of Preston Idaho LU 2,399 154,594 154,594
58 Clatskanie People's Utility District SF 1,023 41,290 41,290
59 Commercial Energy Management Inc.LU 1,131 57,644 57,644
60 Confederate Tribes of Warm Springs LU 186 16,192 16,192
61 ConocoPhillips Company SF 182,978 19,058,774 19,058,774
62 Consolidated Irrigation Company LU 1,662 117,930 117,930
63 Constellation Energy Generation, LLC SF 98,101 9,070,581 9,070,581
64 Constellation Energy Generation, LLC (o)AD 94 (bj)3,766 3,766
65 Cottonwood Hydro, LLC IU 3,366 162,230 162,230
66 Cove Mountain Solar 2, LLC LU 331,287 9,454,940 9,454,940
67 Cove Mountain Solar, LLC LU 161,568 3,901,856 (bk)979,750 4,881,606
68 CP Energy Marketing (US) Inc.SF 4,414 1,231,250 1,231,250
69 Crook County Solar 1, LLC LU 1,052 96,547 96,547
70 Deschutes Valley Water District LU 0 3 2 21,213 593,974 593,974
71 Deseret Generation & Transmission Cooperative (p)LU 100 100 93 650,838 19,716,000 16,360,580 (bl)5,040,000 41,116,580
72 Dorena Hydro, LLC LU 13,599 1,212,163 1,212,163
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73 Douglas Co., Inc. dba Douglas Co. Forest Products LU 3,315 290,235 290,235
74 Draper Irrigation Company IU 221 16,811 16,811
75 Dry Creek, LLC LU 6,162 331,816 331,816
76 Dry Creek, LLC (q)AD (10)(bm)(638)(638)
77 DTE Energy Trading, Inc.SF 107,950 3,002,873 3,002,873
78 Dynasty Power Inc.SF 248,622 51,053,087 51,053,087
79 eBay Inc.LU 0 1 1
80 EDF Trading North America, LLC SF 174,282 14,889,249 14,889,249
81 El Paso Electric Company SF 37,855 3,679,861 3,679,861
82 Elbe Solar Center, LLC (r)AD 0 (bn)13,502 13,502
83 Elbe Solar Center, LLC LU 22,449 1,623,622 (bo)15,589 1,639,211
84 Energy Keepers, Inc.SF 3,616 809,234 809,234
85 Enterprise Solar, LLC (s)AD 0 (bp)200,213 200,213
86 Enterprise Solar, LLC LU 227,719 12,341,019 (bq)235,562 12,576,581
87 Escalante Solar I, LLC LU 209,449 11,158,731 11,158,731
88 Escalante Solar II, LLC LU 208,205 10,550,951 10,550,951
89 Escalante Solar III, LLC LU 209,076 10,241,715 10,241,715
90 Eugene Water & Electric Board SF 14,203 564,120 40,000 604,120
91 Eurus Combine Hills I, LLC LU 79,086 4,053,171 4,053,171
92 ExxonMobil Production Company LU 947 28,027 28,027
93 Fall River Rural Electric Cooperative, Inc.LU 21,861 1,238,934 1,238,934
94 Farm Power Misty Meadow, LLC LU 2,542 226,979 226,979
95 Farmers Irrigation District LU 24,235 2,026,956 2,026,956
96 Fillmore City Corporation LF 30 2,140 2,140
97 Finley BioEnergy, LLC LU 31,851 2,565,439 2,565,439
98 Flathead Electric Cooperative, Inc.(t)LF 370 28,460 28,460
99 Flathead Electric Cooperative, Inc.(u)AD 39 (br)1,728 1,728
100 Four Corners Windfarm, LLC LU 18,053 1,428,378 1,428,378
101 Four Mile Canyon Windfarm, LLC LU 19,193 1,525,886 1,525,886
102 Georgetown Irrigation Company LU 1,342 78,825 78,825
103 Grand Valley Power LF 57 11,829 11,829
104 Granite Mountain Solar East, LLC LU 205,575 10,599,452 10,599,452
105 Granite Mountain Solar West, LLC LU 116,268 6,333,247 6,333,247
106 Granite Peak Solar, LLC LU 3 3 1 6,365 322,927 339,850 662,777
107 Graphite Solar I, LLC LU 108,618 2,825,788 2,825,788
108 Greenville Solar, LLC LU 2 2 1 4,676 353,644 262,811 616,455
109 Gridforce Energy Management, LLC SF 7 733 733
110 Guzman Energy, LLC SF 27,995 3,958,690 3,958,690
111 Hammerich 1&2 LU 1,000 81,674 81,674
112 Hayward Paul Luckey and Joanne Luckey Revocable Trust of 2005 LU 218 9,476 9,476
113 Hunter Solar LLC LU 272,814 6,874,903 987,579 7,862,482
114 Idaho Power Company SF 81,088 5,594,683 6,715 5,601,398
115 Idaho Power Company (v)AD 6,960 (bs)344,368 344,368
116 Iron Springs Solar, LLC LU 204,204 10,913,602 10,913,602
117 J Bar 9 Ranch, Inc.LU 59 371 371
118 Jake Amy LU 1,154 55,095 55,095
119 Jake Amy (w)AD (13)(bt)(805)(805)
120 Joseph Community Solar, LLC LU 618 52,040 52,040
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121 Keeton 1 & 2 LU 345 28,403 28,403
122 Klamath Falls Solar 1, LLC LU 1,514 110,154 110,154
123 Klamath Falls Solar 2, LLC IU 6,792 371,182 371,182
124 Lacomb Irrigation District LU 4,761 237,656 (bu)47,663 285,319
125 Laho Solar, LLC LU 3 3 1 5,742 311,257 306,548 617,805
126 Latigo Wind Park, LLC LU 156,115 9,325,660 9,325,660
127 Los Angeles Department of Water and Power SF 132,104 7,579,456 7,579,456
128 Loyd Fery LU 250 6,888 6,888
129 Macquarie Energy LLC SF 206,678 21,934,792 21,934,792
130 Marsh Valley Hydro Electric Company LU 3,726 235,957 235,957
131 Meadow Creek Project Company LLC LU 288,298 24,658,395 24,658,395
132 Mercuria Energy America, LLC SF 150,961 32,413,972 32,413,972
133 Middle Fork Irrigation District LU 4,857 133,075 133,075
134 Middle Fork Irrigation District (x)AD 0 (bv)6,056 6,056
135 Milford Flat Solar, LLC LU 3 3 1 6,258 323,991 334,140 658,131
136 Milford Solar I, LLC LU 259,395 6,762,422 1,019,418 7,781,840
137 Millican Solar Energy LLC LU 141,640 2,678,413 1,803,077 4,481,490
138 Mink Creek Hydro LLC LU 7,367 369,010 369,010
139 Monroe Hydro, LLC LU 709 63,044 63,044
140 Monsanto Company IU 0 374,244 374,244
141 Morgan City Corporation LF 7 679 679
142 Morgan Stanley Capital Group Inc.SF 141,470 18,516,829 18,516,829
143 Morgan Stanley Capital Group Inc.(y)AD 20 (bw)1,460 1,460
144 Mountain Wind Power II, LLC LU 206,687 13,116,745 13,116,745
145 Mountain Wind Power, LLC LU 152,625 8,416,551 8,416,551
146 Myron Jones, Nola Jones, Larry Oja and Christie Oja LU 288 16,165 16,165
147 (b)Nevada Power Company SF 44,275 2,832,809 2,832,809
148 NextEra Energy Marketing, LLC SF 12,560 467,284 467,284
149 Nichols Gap Limited Partnership LU 2,628 104,660 104,660
150 NorthWestern Energy SF 5,799 565,636 3,151 568,787
151 NorWest Energy 2, LLC IU 20,263 1,473,694 1,473,694
152 NorWest Energy 4, LLC IU 11,387 827,579 827,579
153 NorWest Energy 7, LLC IU 18,272 1,326,045 1,326,045
154 NorWest Energy 9, LLC IU 11,470 626,762 626,762
155 Nucor Corporation (z)IU 0 8,018,900 8,018,900
156 Oak Lea Digester LLC LU 910 81,194 81,194
157 Obsidian Finance Group, LLC LU 869 76,678 76,678
158 Old Mill Solar, LLC LU 7,781 583,547 583,547
159 OR Solar 2, LLC LU 22,367 1,221,823 1,221,823
160 OR Solar 3, LLC LU 25,018 1,367,185 1,367,185
161 OR Solar 5, LLC LU 19,741 1,079,086 1,079,086
162 OR Solar 6, LLC LU 24,967 1,364,231 1,364,231
163 OR Solar 8, LLC LU 26,989 1,474,986 1,474,986
164 Orchard Windfarm 1, LLC LU 15,926 582,126 582,126
165 Orchard Windfarm 1, LLC (aa)AD 0 (bx)5,234 5,234
166 Orchard Windfarm 2, LLC LU 16,796 612,747 612,747
167 Orchard Windfarm 2, LLC (ab)AD 0 (by)5,839 5,839
168 Orchard Windfarm 3, LLC LU 17,019 623,684 623,684
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169 Orchard Windfarm 3, LLC (ac)AD 0 (bz)5,212 5,212
170 Orchard Windfarm 4, LLC LU 18,047 660,732 660,732
171 Orchard Windfarm 4, LLC (ad)AD 59 (ca)1,800 1,800
172 Oregon Environmental Industries, LLC LU 12,933 1,036,422 1,036,422
173 Oregon Solar Incentive LU 8,951 776,143 776,143
174 Oregon State University LU 0 2 2
175 Oregon Trail Windfarm, LLC LU 18,704 1,478,360 1,478,360
176 OSLH, LLC IU 22,773 1,244,174 1,244,174
177 P4 Production, LLC IU 0 (cb)20,600,000 20,600,000
178 Pacific Canyon Windfarm, LLC LU 16,121 1,281,550 1,281,550
179 Pavant Solar II LLC LU 116,432 4,583,486 4,583,486
180 Pavant Solar III LLC LU 46,040 2,430,917 2,430,917
181 Pavant Solar LLC LU 102,006 5,469,965 (cc)153,012 5,622,977
182 Pioneer Wind Park I, LLC LU 218,846 9,170,570 9,170,570
183 Platte River Power Authority SF 2,385 125,074 125,074
184 Portland General Electric Company (ae)LF 11,213 (cd)205,771 205,771
185 Portland General Electric Company (af)AD 0 (ce)(195)(195)
186 Portland General Electric Company SF 69,401 7,585,231 (cf)6,443 7,591,674
187 Power County Wind Park North, LLC LU 60,666 5,182,408 5,182,408
188 Power County Wind Park South, LLC LU 54,713 4,706,666 4,706,666
189 Powerex Corporation SF 247,032 33,686,690 33,686,690
190 Prineville Solar Energy LLC LU 97,149 1,837,081 (cg)1,236,707 3,073,788
191 Provo City Corporation (ag)LF 36 4,255 4,255
192 Public Service Company of Colorado SF 34,115 3,136,007 (ch)25,504 3,161,511
193 Public Service Company of New Mexico SF 19,329 3,775,172 3,775,172
194 Public Utility District No. 1 of Chelan County SF 65,694 2,948,065 (ci)1,065 2,949,130
195 Public Utility District No. 1 of Cowlitz County SF 0 (cj)48,000 48,000
196 Public Utility District No. 1 of Douglas County SF 1 (ck)77 77
197 Public Utility District No. 1 of Snohomish County SF 9,710 455,867 455,867
198 Public Utility District No. 2 of Grant County LU 100,478 (cl)2,189,840 2,189,840
199 Public Utility District No. 2 of Grant County SF 1,291,277 (cm)78,709,440 78,709,440
200 Public Utility District No. 2 of Grant County SF 21 (cn)1,630 1,630
201 Public Utility District No. 2 of Grant County (ah)AD 0 (co)112,439 112,439
202 Puget Sound Energy, Inc.SF 150,280 14,792,800 (cp)6,656 14,799,456
203 Quichapa 1, LLC LU 3 3 2 7,821 319,506 415,219 734,725
204 Quichapa 2, LLC LU 3 3 2 7,834 321,007 415,360 736,367
205 Quichapa 3, LLC LU 3 3 1 7,340 318,080 389,898 707,978
206 Rainbow Energy Marketing Corporation SF 9,510 1,272,968 1,272,968
207 Roseburg Forest Products Company LU 75,771 4,168,151 4,168,151
208 Roseburg LFG Energy, LLC LU 7,504 668,151 668,151
209 Sacramento Municipal Utility District SF 25,552 2,040,472 2,040,472
210 Sage Solar I LLC LU 43,607 2,028,387 2,028,387
211 Sage Solar II LLC LU 42,991 2,008,695 2,008,695
212 Sage Solar III LLC LU 38,861 1,817,124 1,817,124
213 Salt River Project SF 75,250 10,438,965 10,438,965
214 Sand Ranch Windfarm, LLC LU 19,781 1,570,228 1,570,228
215 Seattle City Light SF 109,624 6,261,212 2,394 6,263,606
216 Sempra Gas & Power Marketing, LLC SF 1,400 181,400 181,400
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217 Shell Energy North America (US), L.P.SF 323,865 31,656,232 31,656,232
218 (c)Sierra Pacific Power Company SF 277 7,684 19,487 27,171
219 Sigurd Solar LLC LU 203,870 5,508,554 (cq)868,486 6,377,040
220 Simplot Phosphates LLC LU 123 3,561 3,561
221 Solarize Rogue LLC LU 160 15,375 15,375
222 Solwatt, LLC LU 814 69,931 69,931
223 Spanish Fork Wind Park 2, LLC LU 42,585 2,618,369 2,618,369
224 Sprague Hydro LLC LU 1 378 6,619 61,338 67,957
225 St. Anthony Hydro, LLC LU 5,125 366,425 366,425
226 Stahlbush Island Farms, Inc.IU 955 68,269 68,269
227 SunE DB18, LLC LU 3 3 1 6,321 433,561 355,238 788,799
228 SunE DB24, LLC LU 3 2 1 6,641 259,095 354,583 613,678
229 SunE Solar XVII Project1, LLC LU 3 8 4 6,242 401,026 350,801 751,827
230 SunE Solar XVII Project2, LLC LU 3 8 4 6,480 405,473 364,195 769,668
231 SunE Solar XVII Project3, LLC LU 3 8 4 7,068 299,828 377,360 677,188
232 Sunny Bar Ranch LLLP LU 1,447 71,994 71,994
233 Sunnyside Cogeneration Associates LU 55 53 52 404,896 11,626,560 21,418,784 33,045,344
234 Swalley Irrigation District LU 2,069 166,680 166,680
235 Sweetwater Solar LLC LU 186,499 8,008,595 8,008,595
236 Tacoma Power SF 39,231 4,239,239 1,249 4,240,488
237 Tata Chemicals (Soda Ash) Partners LU 1,194 24,947 24,947
238 Tenaska Power Services Co.SF 43,633 7,841,870 7,841,870
239 Tesoro Refining & Marketing Company, LLC LU 1,423 39,763 39,763
240 Thayn Hydro LLC LU 0 1 4,133 222,193 222,193
241 The Energy Authority, Inc.SF 83,180 8,772,073 8,772,073
242 Three Buttes Windpower, LLC LU 317,724 20,269,304 20,269,304
243 Three Peaks Power, LLC LU 216,136 9,141,290 9,141,290
244 Three Sisters Irrigation District LU 1,851 118,530 118,530
245 Threemile Canyon Wind I, LLC LU 19,954 1,610,859 1,610,859
246 TMF Biofuels, LLC LU 34,431 2,916,657 2,916,657
247 Tooele Army Depot LU 533 20,446 20,446
248 Top of the World Wind Energy LLC LU 394,511 26,037,659 (cr)15,090,203 41,127,862
249 TransAlta Energy Marketing (U.S.) Inc.SF 223,285 20,721,329 20,721,329
250 TransCanada Energy Sales Ltd.SF 5,200 670,200 670,200
251 Tri-State Generation and Transmission Association, Inc.SF 24,109 4,922,508 4,922,508
252 Tucson Electric Power Company SF 22,089 2,503,385 2,503,385
253 Tumbleweed Solar LLC LU 20,252 1,105,904 1,105,904
254 Turlock Irrigation District SF 400 6,180 6,180
255 U.S. Department of the Interior - Bureau of Land Management LU 13 1,005 1,005
256 Uniper Global Commodities SF 112,366 7,455,480 7,455,480
257 United States Air Force at Hill Air Force Base LU 10,601 729,548 729,548
258 University of Utah OS 0 27,968 27,968
259 UNS Electric, Inc.SF 950 53,150 53,150
260 US Magnesium LLC LU 0 (cs)2,011,735 2,011,735
261 Utah Associated Municipal Power Systems (ai)LF 11,172 542,109 542,109
262 Utah Associated Municipal Power Systems SF 20 1,600 1,600
263 Utah Municipal Power Agency SF 28,159 5,604,022 5,604,022
264 Utah Red Hills Renewable Park, LLC LU 205,141 11,888,239 11,888,239
265 Utah Retail Solar customers LU 93,667 8,202,859 8,202,859
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266 Utah Retail Solar customers (aj)AD 47 (ct)4,291 4,291
267 Vitol Inc.SF 87,367 3,987,711 3,987,711
268 Wagon Trail, LLC LU 5,926 471,199 471,199
269 Ward Butte Windfarm, LLC LU 13,717 1,083,622 1,083,622
270 Weber County LU (4)2,376 2,376
271 Western Area Power Administration (ak)LF 1,494 146,648 146,648
272 Western Area Power Administration LU 358 33,129 33,129
273 Western Area Power Administration SF 49,026 1,967,270 (cu)15,356 1,982,626
274 Wolverine Creek Energy, LLC LU 145,937 9,161,926 9,161,926
275 Woodline Solar, LLC IU 19,931 1,089,526 1,089,526
276 Yakima-Tieton Irrigation District LU 5,152 338,738 338,738
277 Liquidated Damages (cv)(4,980,894) (4,980,894)
278 CA Greenhouse Gas Allowances Purchases - Wholesale Program (cw)5,300,422 5,300,422
279 CA Greenhouse Gas Allowances Purchases - Retail Program (cx)15,092,657 15,092,657
280 Net Power Cost Deferrals (cy)(401,579,717)(401,579,717)
281 Netting - Bookouts (1,557,053)(cz)(93,805,625)(93,805,625)
282 Netting - Trading 0 (da)(3,711,472) (3,711,472)
283 System Deviation (as)7,353
284 Legal Contingencies (db)(201,953) (201,953)
285 Accrual (dc)20,967,761 20,967,761
286 Power Exchanges:
287 Avista Corporation EX 382 0 733
288 Bonneville Power Administration EX T- BPA 350,832 5,052 (dd)210,916 210,916
289 Bonneville Power Administration (al)AD T- BPA 2,809
290 Bonneville Power Administration EX 237 1,448,648 1,442,765 (de)(530,970) (530,970)
291 Bonneville Power Administration (am)AD 237 125,972 121,639 (df)(332,541) (332,541)
292 California Independent System Operator EX T-12 2,668,367 6,126,531 (dg)(261,479,689)(261,479,689)
293 California Independent System Operator (an)AD T-12 11,751 (11,751)(dh)(5,331) (5,331)
294 California Independent System Operator EX T-11 (di)(30,633,187)(30,633,187)
295 California Independent System Operator (ao)AD T-11 (dj)(2,585,358) (2,585,358)
296 Emerald People's Utility District EX T-6 0 884 (dk)(22,056) (22,056)
297 Idaho Power Company EX T-6 2,178 2,079
298 Idaho Power Company EX 708 124,135 127,122
299 Los Angeles Department of Water and Power EX OV-1 2,940 (dl)404,452 404,452
300 Milford Wind Corridor Phase I, LLC EX OV-1 1,926 (dm)(269,635) (269,635)
301 Milford Wind Corridor Phase II, LLC EX OV-1 1,014 (dn)(134,817) (134,817)
302 NorthWestern Corporation EX 160 25,315
303 Portland General Electric Company EX T-8 3,557
304 Public Service Company of Colorado EX 334 1,093,354 1,093,052 (do)4,495,381 4,495,381
305 Public Service Company of Colorado (ap)AD 334 149 (dp)4,619 4,619
306 Public Utility District No. 1 of Cowlitz County EX 442 201,548 223,361
307 Seattle City Light EX 554 0 73,345 (dq)(2,849,832) (2,849,832)
308 Western Area Power Administration EX LAS-4 181,516 94,146 (dr)534,517 534,517
309 Western Area Power Administration (aq)AD LAS-4 25,980 (ds)45,251 45,251
310 Imbalance Energy Accrual EX T-11 177,031 (dt)4,942,947 4,942,947
311 Imbalance Energy Accrual (ar)AD T-11 (51,252)(du)(1,093,177) (1,093,177)
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15 TOTAL 17,164,181 6,394,830 9,301,898 36,778,785 1,171,103,517 (606,557,440)601,324,862
FERC FORM NO. 1 (ED. 12-90)Page 326-327
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
Purchases of reactive supply and voltage control, per FERC Docket ER20-2528, effective September 28, 2020.
(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
Bonneville Power Administration - contract termination date: Upon 30 days written notice.
(l) Concept: StatisticalClassificationCode
Settlement adjustment.
(m) Concept: StatisticalClassificationCode
Settlement adjustment.
(n) Concept: StatisticalClassificationCode
City of Hurricane - contract termination dates: August 31, 2022 and January 31, 2023.
(o) Concept: StatisticalClassificationCode
Settlement adjustment.
(p) Concept: StatisticalClassificationCode
Deseret Generation & Transmission Cooperative - contract termination date: September 30, 2024.
(q) Concept: StatisticalClassificationCode
Settlement adjustment.
(r) Concept: StatisticalClassificationCode
Settlement adjustment.
(s) Concept: StatisticalClassificationCode
Settlement adjustment.
(t) Concept: StatisticalClassificationCode
Flathead Electric Cooperative, Inc. - contract termination date: July 31, 2025.
(u) Concept: StatisticalClassificationCode
Settlement adjustment.
(v) Concept: StatisticalClassificationCode
Settlement adjustment.
(w) Concept: StatisticalClassificationCode
Settlement adjustment.
(x) Concept: StatisticalClassificationCode
Settlement adjustment.
(y) Concept: StatisticalClassificationCode
Settlement adjustment.
(z) Concept: StatisticalClassificationCode
Nucor Corporation - contract termination date: December 31, 2031
(aa) Concept: StatisticalClassificationCode
Settlement adjustment.
(ab) Concept: StatisticalClassificationCode
Settlement adjustment.
(ac) Concept: StatisticalClassificationCode
Settlement adjustment.
(ad) Concept: StatisticalClassificationCode
Settlement adjustment.
(ae) Concept: StatisticalClassificationCode
Portland General Electric Company - contract termination date: When the Round Butte project no longer operates for power production purposes.
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(af) Concept: StatisticalClassificationCode
Settlement adjustment.
(ag) Concept: StatisticalClassificationCode
Under Electric Service Agreement subject to termination upon timely notification.
(ah) Concept: StatisticalClassificationCode
Settlement adjustment.
(ai) Concept: StatisticalClassificationCode
Utah Associated Municipal Power System - contract termination date: March 31, 2022.
(aj) Concept: StatisticalClassificationCode
Settlement adjustment.
(ak) Concept: StatisticalClassificationCode
Western Area Power Administration - contract termination date: July 1, 2025.
(al) Concept: StatisticalClassificationCode
Settlement adjustment.
(am) Concept: StatisticalClassificationCode
Settlement adjustment.
(an) Concept: StatisticalClassificationCode
Settlement adjustment.
(ao) Concept: StatisticalClassificationCode
Settlement adjustment.
(ap) Concept: StatisticalClassificationCode
Settlement adjustment.
(aq) Concept: StatisticalClassificationCode
Settlement adjustment.
(ar) Concept: StatisticalClassificationCode
Settlement adjustment.
(as) Concept: MegawattHoursPurchasedOtherThanStorage
Adjustment for inadvertent interchange.
(at) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(au) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(av) Concept: OtherChargesOfPurchasedPower
Purchases of reactive supply and voltage control, per FERC Docket ER20-2528, effective September 28, 2020.
(aw) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ax) Concept: OtherChargesOfPurchasedPower
Reserve share.
(ay) Concept: OtherChargesOfPurchasedPower
Reserve share.
(az) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ba) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(bb) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bc) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(bd) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(be) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bf) Concept: OtherChargesOfPurchasedPower
Reserve share.
(bg) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bh) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bi) Concept: OtherChargesOfPurchasedPower
Labor, equipment and administration fees associated with a hydro project in Idaho Falls, Idaho.
(bj) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bk) Concept: OtherChargesOfPurchasedPower
Purchases of reactive supply and voltage control, per FERC Docket ER20-2528, effective September 28, 2020.
(bl) Concept: OtherChargesOfPurchasedPower
Reimbursement to counterparty for operations and maintenance costs at a coal-fired generating facility located in Vernal, Utah.
(bm) Concept: OtherChargesOfPurchasedPower
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Settlement adjustment.
(bn) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bo) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(bp) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bq) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(br) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bs) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bt) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bu) Concept: OtherChargesOfPurchasedPower
Fixed annual payment.
(bv) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bw) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bx) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(by) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bz) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ca) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cb) Concept: OtherChargesOfPurchasedPower
Compensation for interruptible service and operating reserves.
(cc) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(cd) Concept: OtherChargesOfPurchasedPower
Operations expense plus amortization of unrecovered costs of Cove Project.
(ce) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cf) Concept: OtherChargesOfPurchasedPower
Reserve share.
(cg) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(ch) Concept: OtherChargesOfPurchasedPower
Reserve share.
(ci) Concept: OtherChargesOfPurchasedPower
Reserve share.
(cj) Concept: OtherChargesOfPurchasedPower
Grant County Meaningful Priority assignment fees.
(ck) Concept: OtherChargesOfPurchasedPower
Reserve share.
(cl) Concept: OtherChargesOfPurchasedPower
Operating expense, bond interest, amortization and taxes.
(cm) Concept: OtherChargesOfPurchasedPower
2021 Meaningful Priority award to PacifiCorp of generation output from the Priest Rapids Project from Grant County.
(cn) Concept: OtherChargesOfPurchasedPower
Reserve share.
(co) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cp) Concept: OtherChargesOfPurchasedPower
Reserve share.
(cq) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(cr) Concept: OtherChargesOfPurchasedPower
Compensation curtailment charges.
(cs) Concept: OtherChargesOfPurchasedPower
Ancillary services.
(ct) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cu) Concept: OtherChargesOfPurchasedPower
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Reserve share.
(cv) Concept: OtherChargesOfPurchasedPower
Liquidated damages.
(cw) Concept: OtherChargesOfPurchasedPower
Purchases of greenhouse gas allowances for compliance with the California Air Resources Board greenhouse gas cap-and-trade program.
(cx) Concept: OtherChargesOfPurchasedPower
Purchases of greenhouse gas allowances for compliance with the California Air Resources Board greenhouse gas cap-and-trade program.
(cy) Concept: OtherChargesOfPurchasedPower
Regulatory net power cost and renewable energy credit deferrals.
(cz) Concept: OtherChargesOfPurchasedPower
Reflects transactions that did not physically settle.
(da) Concept: OtherChargesOfPurchasedPower
Reflects transactions that were categorized as trading activities.
(db) Concept: OtherChargesOfPurchasedPower
Reduction in legal contingency reserve.
(dc) 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.
(dd) Concept: OtherChargesOfPurchasedPower
Storage and energy exchange charges.
(de) Concept: OtherChargesOfPurchasedPower
Storage and energy exchange charges.
(df) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dg) Concept: OtherChargesOfPurchasedPower
Energy Imbalance Market (EIM) participating resource settlements in EIM.
(dh) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(di) Concept: OtherChargesOfPurchasedPower
Energy Imbalance Market (EIM) entity settlements in EIM.
(dj) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dk) Concept: OtherChargesOfPurchasedPower
Exchange energy credit.
(dl) Concept: OtherChargesOfPurchasedPower
Station service for a third-party wind project.
(dm) Concept: OtherChargesOfPurchasedPower
Reimbursement for providing station service to a third-party wind project.
(dn) Concept: OtherChargesOfPurchasedPower
Reimbursement for providing station service to a third-party wind project.
(do) Concept: OtherChargesOfPurchasedPower
Exchange energy credit.
(dp) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dq) Concept: OtherChargesOfPurchasedPower
Exchange energy credit.
(dr) Concept: OtherChargesOfPurchasedPower
Imbalance energy settlements between PacifiCorp merchant function and third-party transmission providers.
(ds) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dt) Concept: OtherChargesOfPurchasedPower
Imbalance energy settlements between the PacifiCorp transmission provider and third-party transmission customers.
(du) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 inor 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-firmtransmission 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 OFENERGY REVENUE FROM TRANSMISSION OF ELECTRICITYFOR OTHERS
Line
No.(a)(b)(c)(d)(e)
(f)(g)
(h)(i)(j)(k)(l)(m)(n)
1 3 Phase Renewables, LLC Bonneville Power Administration Oregon Direct Access (i)AD SA 876 BonnevillePowerAdministration various (et)(5)(5)
2 Airport Solar LLC Airport Solar LLC Portland General Electric Company (j)LFP SA 965 TronaSubstation Red Butte/MonaSub 52 127,419 127,419 1,739,110 390,097 2,129,207
3 Airport Solar LLC Airport Solar LLC Portland General Electric Company (k)AD SA 965 Trona
Substation
Red Butte/Mona
Sub 52 3,607 3,607 (eu)179,075 179,075
4 Arizona Electric Power Cooperative, Inc.various signatories various signatories SFP SA 1010 various various 219 219 2,251 (ev)140 2,391
5 Arizona Electric Power Cooperative, Inc.various signatories various signatories NF SA 1011 various various 233 (ew)10 243
6 Arizona Public Service Company (b)Arizona Public Service Company (d)various signatories NF SA 042 various various 3,576 3,576 50,957 (ex)3,179 54,136
7 Arizona Public Service Company (c)Arizona Public Service Company (e)various signatories SFP SA 721 various various 2,448 2,448 15,955 (ey)996 16,951
8 Avangrid Renewables, LLC various signatories various signatories NF SA 121 various various 187,617 187,617 2,093,218 132,253 2,225,471
9 Avangrid Renewables, LLC various signatories various signatories (l)AD SA 121 various various 31,684 31,684 (ez)182,620 182,620
10 Avangrid Renewables, LLC various signatories various signatories SFP SA 122 various various 44,602 44,602 611,441 (fa)38,810 650,251
11 Avangrid Renewables, LLC various signatories various signatories (m)AD SA 122 various various 6,616 6,616 (fb)55,658 55,658
12 Avangrid Renewables, LLC Avangrid Renewables, LLC Avangrid Renewables, LLC and Utah Associated Municipal Power
Systems
(n)OS SA 476 Long Hollow,WY switchingstation
Long Hollow,WY switchingstation
(fc)215,851 215,851
13 Avangrid Renewables, LLC Avangrid Renewables, LLC Avangrid Renewables, LLC and Utah Associated Municipal PowerSystems
(o)AD SA 476
Long Hollow,
WY switching
station
Long Hollow,
WY switching
station
(fd)29,905 29,905
14 Avangrid Renewables, LLC Exxon Mobil (f)Nevada Power Company (p)LFP SA 895 TronaSubstation Red Butte/MonaSub 31 65,378 65,378 1,066,707 (fe)67,465 1,134,172
15 Avangrid Renewables, LLC Exxon Mobil Nevada Power Company (q)AD SA 895 TronaSubstation Red Butte/MonaSub 12,699 12,699 (ff)93,669 93,669
16 Avangrid Renewables, LLC Bonneville Power Administration Oregon Direct Access FNO SA 742 Ponderosa
Substation various 34 270,410 270,410 1,167,491 530,624 1,698,115
17 Avangrid Renewables, LLC Avangrid Renewables, LLC various signatories (r)AD SA 742 PonderosaSubstation various 33 24,892 24,892 (fg)136,480 136,480
18 Avista Corporation various signatories various signatories NF SA 887 various various 1,392 1,392 14,831 (fh)947 15,778
19 Basin Electric Power Cooperative, Inc.Western Area Power Administration Powder River Energy Corporation FNO SA 505 Yellowtail Sub Sheridan
Substation 11 74,081 74,081 371,319 (fi)48,706 420,025
20 Basin Electric Power Cooperative, Inc.Western Area Power Administration Powder River Energy Corporation (s)AD SA 505 Yellowtail Sub SheridanSubstation 12 6,917 6,917 (fj)40,939 40,939
21 Basin Electric Power Cooperative, Inc.Western Area Power Administration Powder River Energy Corporation NF SA 607 various various 190,823 190,823 1,642,686 (fk)103,164 1,745,850
22 Basin Electric Power Cooperative, Inc.Western Area Power Administration Powder River Energy Corporation (t)AD SA 607 various various 9,867 9,867 (fl)102,108 102,108
23 Basin Electric Power Cooperative, Inc.Western Area Power Administration Powder River Energy Corporation SFP SA 606 various various 4,762 4,762 39,645 (fm)2,469 42,114
24 Black Hills Corporation PacifiCorp Montana-Dakota Utilities FNO SA 347 various Sheridan
Substation 49 278,919 278,919 1,658,918 (fn)104,861 1,763,779
25 Black Hills Corporation PacifiCorp Montana-Dakota Utilities (u)AD SA 347 various SheridanSubstation 51 29,166 29,166 (fo)139,781 139,781
Payment By (Company of Public Authority) (Footnote Affiliation)Energy Received From (Company of Public Authority) (FootnoteAffiliation)Energy Delivered To (Company of Public Authority) (FootnoteAffiliation)Statistical Classification Ferc Rate Schedule ofTariff Number
Point ofReceipt(Substation
or Other
Designation)
Point ofDelivery(Substation or
Other
Designation)
BillingDemand
(MW)
MegawattHours
Received
MegawattHours
Delivered
DemandCharges ($)
EnergyCharges
($)
OtherCharges
($)
TotalRevenues
($) (k+l+m)
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26 Black Hills Corporation PacifiCorp Black Hills Corporation (v)LFP SA 67 various WyodakSubstation 52 207,514 207,514 1,767,268 (fp)117,316 1,884,584
27 Black Hills Corporation PacifiCorp Black Hills Corporation (w)AD SA 67 various Wyodak
Substation 52 2,436 2,436 (fq)151,089 151,089
28 Black Hills Corporation various signatories various signatories NF SA 768 various various 895 895 6,022 (fr)375 6,397
29 Black Hills Corporation various signatories various signatories SFP SA 767 various various 748 748 6,287 (fs)391 6,678
30 Black Hills Power Marketing various signatories various signatories NF SA 43 various various 592 592 4,686 (ft)292 4,978
31 Black Hills Power Marketing various signatories various signatories SFP SA 111 various various 21 21 152 (fu)9 161
32 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.
(x)OS RS 369 Midpoint
Substation
Summer Lake
Sub
33 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (y)OS RS 237 various various 428 1,110,865 1,110,865 5,341,813 62,882 5,404,695
34 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (z)AD RS 237 various various 392 108,646 108,646 (fv)400,451 400,451
35 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (aa)LFP SA 656 Lost Creek
Hydro Plant
Alvey
Substation 58 205,251 205,251 1,991,188 (fw)46,614 2,037,802
36 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (ab)AD SA 656 Lost CreekHydro Plant AlveySubstation 58 10,573 10,573 (fx)169,231 169,231
37 Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative FNO SA 229 BonnevillePowerAdministration
GazleySubstation 3 22,834 22,834 113,499 (fy)165,405 278,904
38 Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative (ac)AD SA 229 BonnevillePowerAdministration
GazleySubstation 3 2,264 2,264 (fz)21,453 21,453
39 Bonneville Power Administration Bonneville Power Administration Benton Rural Electric Association FNO SA 539 BonnevillePower
Administration
TietonSubstation 1 5,835 5,835 24,465 (ga)3,143 27,608
40 Bonneville Power Administration Bonneville Power Administration Benton Rural Electric Association (ad)AD SA 539 BonnevillePowerAdministration
TietonSubstation 1 897 897 (gb)10,410 10,410
41 Bonneville Power Administration Bonneville Power Administration Umatilla Electric Cooperative Association and Columbia Basin ElectricCooperative, Inc FNO SA 538 McNarySubstation HinkleSubstation 1 1,426 1,426 8,282 (gc)956 9,238
42 Bonneville Power Administration Bonneville Power Administration Umatilla Electric Cooperative Association and Columbia Basin Electric
Cooperative, Inc
(ae)AD SA 538 McNary
Substation
Hinkle
Substation 1 120 120 (gd)432 432
43 Bonneville Power Administration United States Department of Interior, Bureau of Reclamation Bonneville Power Administration (af)LFP SA 179 USBR Green
Springs
BonnevillePowerAdministration 19 (ge)44,603 44,603
44 Bonneville Power Administration United States Department of Interior, Bureau of Reclamation Bonneville Power Administration (ag)AD SA 179 USBR GreenSprings
Bonneville
Power
Administration
19 (gf)21,061 21,061
45 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (ah)OS RS 368 MalinSubstation MalinSubstation 563,467 563,467 232,452 232,452
46 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (ai)AD RS 368 Malin
Substation
Malin
Substation 48,625 48,625 (gg)21,132 21,132
47 Bonneville Power Administration Bonneville Power Administration Yakama Power FNO SA 328 BonnevillePowerAdministration
WhiteSwan/ToppenishSubstations 6 37,201 37,201 203,597 (gh)114,791 318,388
48 Bonneville Power Administration Bonneville Power Administration Yakama Power (aj)AD SA 328 BonnevillePower
Administration
WhiteSwan/Toppenish
Substations
5 3,476 3,476 (gi)17,682 17,682
49 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO SA 827 BonnevillePowerAdministration Neff Substation 1 668 668 1,024 (gj)284 1,308
50 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (ak)AD SA 827 BonnevillePower
Administration
Neff Substation 1 87 87 (gk)994 994
51 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO SA 746 GoshenSubstation various 220 1,444,125 1,444,125 7,723,379 (gl)1,832,959 9,556,338
52 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (al)AD SA 746 GoshenSubstation various 319 165,425 165,425 (gm)1,035,288 1,035,288
53 Bonneville Power Administration various signatories various signatories NF SA 44 various various 7,290 7,290 98,299 (gn)6,196 104,495
54 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (am)AD SA 44 various various (go)10 10
55 Bonneville Power Administration various signatories various signatories FNO SA 747 Goshen
Substation various 98 763,158 763,158 3,840,134 (gp)694,746 4,534,880
56 Bonneville Power Administration various signatories various signatories (an)AD SA 747 GoshenSubstation various 118 78,813 78,813 (gq)408,104 408,104
57 Bonneville Power Administration Bonneville Power Administration Public Utility District No. 1 of Clark County FNO SA 735 Cardwell-Merwin Chelatchie/View115kV 22 118,413 118,413 760,538 (gr)83,529 844,067
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58 Bonneville Power Administration Bonneville Power Administration Public Utility District No. 1 of Clark County (ao)AD SA 735 Cardwell-Merwin Chelatchie/View115kV 32 16,886 16,886 (gs)80,290 80,290
59 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO SA 865 GoshenSubstation various 1 505 505 692 (gt)209 901
60 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (ap)AD SA 865 Goshen
Substation various 1 61 61 (gu)187 187
61 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO SA 975 BonnevillePowerAdministration various 1 2,905 2,905 16,593 (gv)1,914 18,507
62 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (aq)AD SA 975
Bonneville
Power
Administration
various 1 7 7 (gw)(946) (946)
63 Brookfield Renewable Trading and Marketing LP various signatories various signatories NF SA 941 various various 14 14 1,306 (gx)80 1,386
64 Brookfield Renewable Trading and Marketing LP various signatories various signatories (ar)AD SA 941 various various 70 70 (gy)695 695
65 Brookfield Renewable Trading and Marketing LP various signatories various signatories SFP SA 940 various various 71,685 71,685 442,772 (gz)27,746 470,518
66 Calpine Energy Solutions, LLC Bonneville Power Administration Oregon Direct Access FNO SA 299 BonnevillePowerAdministration various 19 127,962 127,962 633,315 (ha)106,433 739,748
67 Calpine Energy Solutions, LLC Bonneville Power Administration Oregon Direct Access (as)AD SA 299
Bonneville
PowerAdministration various 14 10,908 10,908 (hb)44,289 44,289
68 City of Roseville City of Roseville City of Roseville (at)LFP SA 881 Malin 500Substation Round MountainSub 50 1,708,665 34,598 1,743,263
69 City of Roseville City of Roseville City of Roseville (au)AD SA 881 Malin 500
Substation
Round Mountain
Sub 50 (hc)143,420 143,420
70 Clatskanie People's Utility District Clatskanie People's Utility District Clatskanie People's Utility District (av)LFP SA 899 TroutdaleSubstation various 14 35,769 35,769 462,248 (hd)29,236 491,484
71 Clatskanie People's Utility District Clatskanie People's Utility District Clatskanie People's Utility District (aw)AD SA 899 TroutdaleSubstation various 7,210 7,210 (he)39,944 39,944
72 Clatskanie People's Utility District Clatskanie People's Utility District Clatskanie People's Utility District (ax)LFP SA 901 Troutdale
Substation various 2 36,162 36,162 71,114 (hf)4,497 75,611
73 Clatskanie People's Utility District Clatskanie People's Utility District Clatskanie People's Utility District (ay)AD SA 901 TroutdaleSubstation various (hg)6,891 6,891
74 ConocoPhillps Company various signatories various signatories NF SA 280 various various 286 286 4,140 (hh)257 4,397
75 ConocoPhillps Company various signatories various signatories (az)AD SA 280 various various 63 63 (hi)626 626
76 CP Energy Marketing (US) Inc.various signatories various signatories NF SA 968 various various 758 758 13,995 (hj)870 14,865
77 CP Energy Marketing (US) Inc.various signatories various signatories SFP SA 967 various various 100 100 443 (hk)27 470
78 Deseret Generation and Transmission Co-operative Deseret Generation and Transmission Co-operative Deseret Generation and Transmission Co-operative (ba)OS RS 280 various various 135 1,126,100 1,126,100 4,658,400 (hl)2,392,043 7,050,443
79 Deseret Generation and Transmission Co-operative Deseret Generation and Transmission Co-operative Deseret Generation and Transmission Co-operative (bb)AD RS 280 various various 115 89,081 89,081 (hm)533,476 533,476
80 Deseret Generation and Transmission Co-operative various signatories various signatories NF SA 156 various various 17,696 17,696 171,508 (hn)10,848 182,356
81 Deseret Generation and Transmission Co-operative various signatories various signatories (bc)AD SA 156 various various 1,423 1,423 (ho)13,975 13,975
82 Deseret Generation and Transmission Co-operative various signatories various signatories SFP SA 159 various various 27,600 27,600 161,401 (hp)10,078 171,479
83 Dynasty Power Inc.various signatories various signatories NF SA 1014 various various 242,385 242,385 1,759,433 (hq)110,098 1,869,531
84 Dynasty Power Inc.(bd)AD SA 1014 various various 1,458 1,458 (hr)10,512 10,512
85 Dynasty Power Inc.various signatories various signatories SFP SA 1013 various various 30,482 30,482 360,775 (hs)22,666 383,441
86 Dynasty Power Inc.(be)AD SA 1013 various various 1,408 1,408 (ht)36,038 36,038
87 Eagle Energy Partners I LP various signatories various signatories NF SA 569 various various 13,985 13,985 328,728 (hu)20,525 349,253
88 Eagle Energy Partners I LP various signatories various signatories SFP SA 570 various various 38 38 355 (hv)23 378
89 Energy Keepers, Inc.various signatories various signatories NF SA 814 various various 26,190 26,190 293,750 (hw)18,600 312,350
90 Energy Keepers, Inc.various signatories various signatories (bf)AD SA 814 various various 2,000 2,000 (hx)19,878 19,878
91 Energy Keepers, Inc.various signatories various signatories SFP SA 815 various various 1,222 1,222 22,500 (hy)1,405 23,905
92 Evergreen Biopower LLC NextEra Energy Resources, LLC various signatories (bg)LFP SA 874 various various 10 47,682 47,682 355,570 (hz)67,027 422,597
93 Evergreen Biopower LLC NextEra Energy Resources, LLC Public Utility District No. 2 of Grant County (bh)AD SA 874 various various 10 4,657 4,657 (ia)35,388 35,388
94 Exelon Generation Company, LLC Bonneville Power Administration Oregon Direct Access FNO SA 943
Bonneville
Power
Administration
various 1 5,690 5,690 31,410 (ib)5,101 36,511
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95 Exelon Generation Company, LLC Bonneville Power Administration Oregon Direct Access (bi)AD SA 943 BonnevillePowerAdministration various 1 813 813 (ic)3,425 3,425
96 Exelon Generation Company, LLC various signatories various signatories NF SA 759 various various 144,816 144,816 2,557,794 (id)9,084,713 11,642,507
97 Exelon Generation Company, LLC various signatories various signatories (bj)AD SA 759 various various 354 354 (ie)228,970 228,970
98 Exelon Generation Company, LLC various signatories various signatories SFP SA 760 various various 25,118 25,118 207,012 (if)12,937 219,949
99 Exelon Generation Company, LLC various signatories various signatories (bk)AD SA 760 various various 576 576 (ig)2,725 2,725
100 Fall River Rural Electric Cooperative, Inc.Marysville Hydro Partners Idaho Power Company (bl)OS RS 322 TargheeSubstation GoshenSubstation 138,699 138,699
101 Fall River Rural Electric Cooperative, Inc.Marysville Hydro Partners Idaho Power Company (bm)AD RS 322 TargheeSubstation GoshenSubstation (ih)12,609 12,609
102 Falls Creek H.P. Limited Partnership Lakeview Airport 10 Portland General Electric Company (bn)LFP SA 868
Falls Creek
H.P. LimitedPartnership
Bonneville
PowerAdministration 5 15,330 15,330 145,512 (ii)24,612 170,124
103 Falls Creek H.P. Limited Partnership Lakeview Airport 10 Portland General Electric Company (bo)AD SA 868 Falls CreekH.P. LimitedPartnership
BonnevillePowerAdministration 3 2,047 2,047 (ij)21,014 21,014
104 Garrett Solar LLC Garrett Solar LLC Portland General Electric Company (bp)LFP SA 966 Wallula
Substation
Wala-MIDC
path 10 26,097 26,097 355,570 (ik)81,962 437,532
105 Garrett Solar LLC Garrett Solar LLC Portland General Electric Company (bq)AD SA 966 WallulaSubstation Wala-MIDCpath 10 959 959 (il)36,132 36,132
106 Guzman Energy LLC various signatories various signatories NF SA 786 various various 144,945 144,945 1,189,710 (im)74,928 1,264,638
107 Guzman Energy LLC various signatories various signatories (br)AD SA 786 various various 9,657 9,657 (in)100,580 100,580
108 Guzman Energy LLC various signatories various signatories SFP SA 785 various various 42,028 42,028 388,258 (io)28,626 416,884
109 Guzman Energy LLC various signatories various signatories (bs)AD SA 785 various various (ip)4,360 4,360
110 Idaho Power Company Exxon Mobil Nevada Power Company (bt)LFP SA 212 TronaSubstation Red Butte/MonaSub 52 12,163 12,163 807,005 (iq)50,388 857,393
111 Idaho Power Company Exxon Mobil Nevada Power Company (bu)AD SA 212 TronaSubstation Red Butte/MonaSub (ir)(53,199) (53,199)
112 Idaho Power Company various signatories various signatories NF SA 14 various various 323,860 323,860 2,085,944 (is)130,666 2,216,610
113 Idaho Power Company various signatories various signatories SFP SA 154 various various 1,490 (it)93 1,583
114 Idaho Power Company various signatories various signatories SFP SA 726 various various 592 592 3,885 (iu)249 4,134
115 Idaho Power Company various signatories various signatories (bv)AD SA 726 various various 11 11 (iv)109 109
116 Idaho Power Company various signatories various signatories NF SA 725 various various 375 375 5,318 (iw)343 5,661
117 Idaho Power Company various signatories various signatories (bw)AD SA 725 various various 23 23 (ix)228 228
118 Imperial Irrigation District various signatories various signatories NF SA 1006 various various 4,426 4,426 797,741 (iy)50,097 847,838
119 Los Angeles Department of Water & Power various signatories various signatories NF SA 142 various various 289 289 5,873 (iz)375 6,248
120 Los Angeles Department of Water & Power various signatories various signatories SFP SA 143 various various 1,803 1,803 23,493 (ja)1,501 24,994
121 Macquarie Energy LLC various signatories various signatories NF SA 755 various various 147,201 147,201 1,270,903 (jb)79,656 1,350,559
122 Macquarie Energy LLC various signatories various signatories (bx)AD SA 755 various various 2,033 2,033 (jc)19,655 19,655
123 Macquarie Energy LLC various signatories various signatories SFP SA 754 various various 2,829 2,829 267,266 (jd)16,800 284,066
124 MAG Energy Solutions, Inc.various signatories various signatories NF SA 903 various various 184 184 2,119 (je)131 2,250
125 MAG Energy Solutions, Inc.various signatories various signatories (by)AD SA 903 various various (jf)268 268
126 Mercuria Energy America LLC various signatories various signatories NF SA 998 various various 183,083 183,083 1,322,590 (jg)82,529 1,405,119
127 Mercuria Energy America LLC various signatories various signatories (bz)AD SA 998 various various 6,580 6,580 (jh)75,928 75,928
128 Mercuria Energy America LLC various signatories various signatories SFP SA 997 various various 51,787 51,787 338,246 (ji)21,104 359,350
129 Moon Lake Electric Association Inc.Moon Lake Electric Association Moon Lake Electric Association (ca)OS RS 302 Duchesne Duchesne 21,978 21,978 18,722 18,722
130 Moon Lake Electric Association Inc.Moon Lake Electric Association Moon Lake Electric Association (cb)AD RS 302 Duchesne Duchesne 1,503 1,503 (jj)1,702 1,702
131 Morgan Stanley Capital Group, Inc.various signatories various signatories NF SA 157 various various 311,844 311,844 2,729,178 (jk)172,346 2,901,524
132 Morgan Stanley Capital Group, Inc.various signatories various signatories (cc)AD SA 157 various various 24,927 24,927 (jl)351,339 351,339
133 Morgan Stanley Capital Group, Inc.various signatories various signatories SFP SA 160 various various 28,644 28,644 247,631 (jm)15,477 263,108
134 Navajo Tribal Utility Authority Navajo Tribal Utility Authority Navajo Tribal Utility Authority FNO SA 894 Four Corners Pinto-FourCorners 2 15,497 15,497 80,103 13,242 93,345
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135 Navajo Tribal Utility Authority Navajo Tribal Utility Authority Navajo Tribal Utility Authority (cd)AD SA 894 Four Corners Pinto-FourCorners 1 1,619 1,619 (jn)9,520 9,520
136 Nevada Power Company various signatories various signatories NF SA 455 various various 278 278 2,932 (jo)187 3,119
137 Nevada Power Company various signatories various signatories SFP SA 454 various various 29,329 29,329 164,225 (jp)10,543 174,768
138 NextEra Energy Resources, LLC NextEra Energy Resources, LLC Public Utility District No. 2 of Grant County (ce)LFP SA 733 Wallula
Substation
Wala-MIDC
path 94 179,636 179,636 3,213,481 860,424 4,073,905
139 NextEra Energy Resources, LLC NextEra Energy Resources, LLC Public Utility District No. 2 of Grant County (cf)AD SA 733 WallulaSubstation Wala-MIDCpath 103 30,560 30,560 (jq)394,122 394,122
140 NextEra Energy Resources, LLC various signatories various signatories NF SA 236 various various 4 4
141 Pacific Gas & Electric Company various signatories various signatories NF SA 338 various various 1,930 1,930 14,916 (jr)935 15,851
142 Pacific Gas & Electric Company various signatories various signatories (cg)AD SA 338 various various 55 55 (js)546 546
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.
(ch)OS RS 137 various various 3,314 3,314
144 Portland General Electric Company various signatories various signatories NF SA 8 various various 8,937 8,937 77,336 (jt)4,866 82,202
145 Portland General Electric Company various signatories various signatories SFP SA 248 various various 2,333 2,333 14,416 (ju)916 15,332
146 Powerex Corporation Bonneville Power Administration California Independent System Operator Corporation (ci)LFP SA 169 BonnevillePower
Administration
CRAG ViewSubstation 83 1,170,686 1,170,686 2,844,553 (jv)179,905 3,024,458
147 Powerex Corporation Bonneville Power Administration California Independent System Operator Corporation (cj)AD SA 169 BonnevillePowerAdministration
CRAG ViewSubstation 83 42,078 42,078 (jw)249,782 249,782
148 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (ck)LFP SA 1016 Borah Red Butte/MonaSub 104 3,555,692 (jx)224,880 3,780,572
149 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cl)AD SA 1016 Borah Red Butte/Mona
Sub 104 (jy)218,005 218,005
150 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cm)LFP SA 1017 Borah Red Butte/MonaSub 104 3,555,692 (jz)224,880 3,780,572
151 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cn)AD SA 1017 Borah Red Butte/Mona
Sub 104 (ka)218,005 218,005
152 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (co)LFP SA 1040 Malin 500Substation Round MountainSub 100 2,260,590 (kb)141,722 2,402,312
153 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cp)LFP SA 700 Malin 500Substation Round MountainSub 100 3,417,329 (kc)69,196 3,486,525
154 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cq)AD SA 700 Malin 500
Substation
Round Mountain
Sub 100 (kd)286,840 286,840
155 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cr)LFP SA 701 Malin 500Substation Round MountainSub 100 3,417,329 (ke)69,196 3,486,525
156 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cs)AD SA 701 Malin 500Substation Round MountainSub 100 (kf)286,840 286,840
157 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (ct)LFP SA 702 Malin 500
Substation
Round Mountain
Sub 100 3,417,329 (kg)69,196 3,486,525
158 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cu)AD SA 702 Malin 500Substation Round MountainSub 100 (kh)286,840 286,840
159 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cv)LFP SA 748 Malin 500Substation Round MountainSub 50 1,708,665 (ki)34,598 1,743,263
160 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cw)AD SA 748 Malin 500
Substation
Round Mountain
Sub 50 (kj)143,420 143,420
161 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cx)LFP SA 749 Malin 500Substation Round MountainSub 150 5,125,994 (kk)103,794 5,229,788
162 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cy)AD SA 749 Malin 500Substation Round MountainSub 150 (kl)430,260 430,260
163 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cz)LFP SA 995 Malin 500
Substation
Round Mountain
Sub 100 3,417,329 (km)69,196 3,486,525
164 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (da)AD SA 995 Malin 500Substation Round MountainSub 100 (kn)288,976 288,976
165 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (db)LFP SA 996 Malin 500
Substation
Round Mountain
Sub 100 3,417,329 (ko)69,196 3,486,525
166 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (dc)AD SA 996 Malin 500Substation Round MountainSub 100 (kp)288,976 288,976
167 Powerex Corporation various signatories various signatories NF SA 47 various various 324,750 324,750 2,955,404 (kq)184,516 3,139,920
168 Powerex Corporation various signatories various signatories (dd)AD SA 47 various various 703 703 (kr)497 497
169 Powerex Corporation various signatories various signatories SFP SA 151 various various 79,258 79,258 1,134,710 (ks)70,839 1,205,549
170 Powerex Corporation various signatories various signatories (de)AD SA 151 various various 3,606 3,606 (kt)5,364 5,364
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171 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.NF SA 664 Various Various 2,912 2,912 50,491 (ku)3,192 53,683
172 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.SFP SA 665 Various Various 80 80 745 (kv)46 791
173 Public Utility District No. 1 of Cowlitz County Public Utility District No. 1 of Cowlitz County Bonneville Power Administration (df)OS RS 234 Swift Unit No.2 WoodlandSubstation 216,235 216,235
174 Rainbow Energy Marketing Corporation various signatories various signatories NF SA 316 various various 150,822 150,822 1,408,700 (kw)88,234 1,496,934
175 Rainbow Energy Marketing Corporation various signatories various signatories (dg)AD SA 316 various various 1,894 1,894 (kx)12,420 12,420
176 Rainbow Energy Marketing Corporation various signatories various signatories SFP SA 261 various various 10,716 10,716 100,950 (ky)6,292 107,242
177 Rainbow Energy Marketing Corporation various signatories various signatories (dh)AD SA 261 various various (kz)237 237
178 Sacramento Municipal Utility District Sacramento Municipal Utility District Sacramento Municipal Utility District (di)LFP SA 863 Malin
Substation
Malin
Substation 20 108,582 108,582 675,589 (la)42,726 718,315
179 Sacramento Municipal Utility District Sacramento Municipal Utility District Sacramento Municipal Utility District (dj)AD SA 863 MalinSubstation MalinSubstation 20 12,977 12,977 (lb)59,325 59,325
180 Salt River Project Agricultural Improvement and Power District Salt River Project Agricultural Improvement and Power District Salt River Project Agricultural Improvement and Power District (dk)LFP SA 809 Enel CoveFort Red ButteSubstation 26 131,750 131,750 888,931 (lc)56,220 945,151
181 Salt River Project Agricultural Improvement and Power District Salt River Project Agricultural Improvement and Power District Salt River Project Agricultural Improvement and Power District (dl)AD SA 809 Enel Cove
Fort
Red Butte
Substation 26 15,412 15,412 (ld)78,058 78,058
182 Shell Energy North America (US), L.P.NextEra Energy Resources, LLC Public Utility District No. 2 of Grant County (dm)LFP SA 791 WallulaSubstation Wala-MIDCpath 25 32,224 32,224 888,931 (le)56,220 945,151
183 Shell Energy North America (US), L.P.NextEra Energy Resources, LLC Public Utility District No. 2 of Grant County (dn)AD SA 791 WallulaSubstation Wala-MIDCpath 25 3,868 3,868 (lf)78,058 78,058
184 Shell Energy North America (US), L.P.various signatories various signatories NF SA 23 various various 247,834 247,834 1,394,312 (lg)87,631 1,481,943
185 Shell Energy North America (US), L.P.various signatories various signatories (do)AD SA 23 various various 46,532 46,532 (lh)321,575 321,575
186 Shell Energy North America (US), L.P.various signatories various signatories SFP SA 162 various various 49,531 49,531 183,064 (li)11,517 194,581
187 Shell Energy North America (US), L.P.various signatories various signatories (dp)AD SA 162 various various 6,165 6,165 (lj)24,625 24,625
188 (a)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.
(dq)OS RS 674 Sigurd
Substation
Utah-Nevada
Border (lk)33,147 33,147
189 Sierra Pacific Power Company Operation, maintenance or facility lease services with no receipt ordelivery of energy.Operation, maintenance or facility lease services with no receipt ordelivery of energy.
(dr)AD RS 674 SigurdSubstation Utah-NevadaBorder (ll)3,013 3,013
190 Southern California Edison Company various signatories various signatories NF SA 642 various various 280,230 280,230 2,821,714 (lm)1,052,738 3,874,452
191 Southern California Edison Company various signatories various signatories AD SA 642 various various 45,614 45,614 (ln)515,310 515,310
192 Southern California Edison Company various signatories various signatories SFP SA 643 various various 5,162 (lo)321 5,483
193 Southern California Public Power Authority Powerex Corporation (g)Southern California Public Power Authority NF SA 629 Tieton
Substation various 71 71 (lp)62,617 62,617
194 Southern California Public Power Authority Powerex Corporation (h)Southern California Public Power Authority AD SA 629 TietonSubstation various (lq)(1,268) (1,268)
195 State of South Dakota Western Area Power Administration Black Hills Corporation (ds)LFP SA 779 Yellowtail Sub WyodakSubstation 4 17,468 17,468 142,227 (lr)8,996 151,223
196 State of South Dakota Western Area Power Administration Black Hills Corporation (dt)AD SA 779 Yellowtail Sub Wyodak
Substation 4 1,525 1,525 (ls)12,490 12,490
197 Tenaska Power Services Co.various signatories various signatories NF SA 125 various various 58,320 58,320 517,147 (lt)149,895 667,042
198 Tenaska Power Services Co.various signatories various signatories (du)AD SA 125 various various 3,049 3,049 (lu)58,305 58,305
199 Tenaska Power Services Co.various signatories various signatories SFP SA 126 various various 14,859 14,859 95,554 (lv)6,069 101,623
200 Tenaska Power Services Co.various signatories various signatories (dv)AD SA 126 various various 295 295 (lw)2,707 2,707
201 The Energy Authority, Inc.various signatories various signatories NF SA 310 various various 130,708 130,708 1,106,434 (lx)69,475 1,175,909
202 The Energy Authority, Inc.various signatories various signatories (dw)AD SA 310 various various 11,875 11,875 (ly)75,673 75,673
203 The Energy Authority, Inc.various signatories various signatories SFP SA 311 various various 312 312 9,857 (lz)632 10,489
204 Thermo No. 1 BE-01, LLC Thermo Geothermal Project various signatories (dx)LFP SA 568 South MilfordSub MonaSubstation 11 49,359 49,359 391,135 (ma)73,031 464,166
205 Thermo No. 1 BE-01, LLC Thermo Geothermal Project various signatories (dy)AD SA 568 South Milford
Sub
Mona
Substation 11 5,408 5,408 (mb)39,023 39,023
206 TransAlta Energy Marketing (U.S.) Inc.various signatories various signatories NF SA 127 various various 78,858 78,858 624,564 (mc)39,447 664,011
207 TransAlta Energy Marketing (U.S.) Inc.various signatories various signatories (dz)AD SA 127 various various 4,206 4,206 (md)29,863 29,863
208 TransAlta Energy Marketing (U.S.) Inc.various signatories various signatories SFP SA 128 various various 6,756 6,756 58,227 (me)4,904 63,131
209 TransAlta Energy Marketing (U.S.) Inc.various signatories various signatories (ea)AD SA 128 various various 80 80 (mf)875 875
210 Tri-State Generation and Transmission Association, Inc various signatories Tri-State Generation and Transmission Association, Inc FNO SA 628 DaveJohnston Sub ThermopolisSub 17 113,880 113,880 596,704 (mg)98,159 694,863
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211 Tri-State Generation and Transmission Association, Inc various signatories Tri-State Generation and Transmission Association, Inc (eb)AD SA 628 DaveJohnston Sub ThermopolisSub 18 13,052 13,052 (mh)23,751 23,751
212 Tri-State Generation and Transmission Association, Inc various signatories various signatories NF SA 33 various various 1,314 1,314 9,997 (mi)631 10,628
213 Uniper Global Commodoties various signatories various signatories NF SA 992 various various 57,466 57,466 488,081 (mj)30,631 518,712
214 Uniper Global Commodoties various signatories various signatories SFP SA 991 various various 21 21 93 (mk)6 99
215 United States Department of Interior, Bureau of Reclamation Bonneville Power Administration United States Department of Interior, Bureau of Reclamation FNO SA 506 Walla WallaSub Burbank Pumps 1 2,359 2,359 10,395 (ml)11,728 22,123
216 United States Department of Interior, Bureau of Reclamation Bonneville Power Administration United States Department of Interior, Bureau of Reclamation (ec)AD SA 506 Walla Walla
Sub Burbank Pumps 1 4 4 (mm)(303) (303)
217 United States Department of Interior, Bureau of Reclamation Western Area Power Administration Weber Basin Water Conservancy District (ed)OS RS 286 various various 26,156 26,156 5,079 (mn)21,076 26,155
218 United States Department of Interior, Bureau of Reclamation Western Area Power Administration Weber Basin Water Conservancy District (ee)AD RS 286 various various 1,193 1,193 (mo)2,016 2,016
219 United States Department of Interior, Bureau of Reclamation Bonneville Power Administration Crooked River Irrigation District (ef)OS RS 67 RedmondSubstation Crooked RiverPumps 8,699 8,699 10,961 10,961
220 Utah Associated Municipal Power Systems Utah Associated Municipal Power Systems Utah Associated Municipal Power Systems (eg)OS RS 297 various various 623 3,394,489 3,394,489 21,089,240 (mp)3,576,160 24,665,400
221 Utah Associated Municipal Power Systems Utah Associated Municipal Power Systems Utah Associated Municipal Power Systems (eh)AD RS 297 various various 461 284,839 284,839 (mq)1,413,761 1,413,761
222 Utah Associated Municipal Power Systems various signatories various signatories NF SA 009 various various 134 134 7,473 (mr)466 7,939
223 Utah Associated Municipal Power Systems various signatories various signatories SFP SA 718 various various 50 50 222 (ms)14 236
224 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency (ei)OS RS 637 various various 97 786,335 786,335 3,266,685 (mt)573,786 3,840,471
225 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency (ej)AD RS 637 various various 53 59,895 59,895 (mu)376,917 376,917
226 Utah Municipal Power Agency various signatories various signatories NF SA 20 various various 30,892 30,892 282,404 (mv)17,565 299,969
227 Utah Municipal Power Agency various signatories various signatories (ek)AD SA 20 various various 80 80 (mw)795 795
228 Vitol, Inc various signatories various signatories NF SA 1027 various various 6,675 6,675 247,579 (mx)15,469 263,048
229 Vitol, Inc various signatories various signatories SFP SA 1026 various various 111,111 111,111 975,033 (my)60,879 1,035,912
230 Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric Company (el)OS RS 591 Pelton
Reregulating
Round Butte
Sub 53,154 53,154 (mz)109,725 109,725
231 Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric Company (em)AD RS 591 PeltonReregulating Round ButteSub 6,378 6,378 (na)9,975 9,975
232 Western Area Power Administration Western Area Power Administration Various Western Area Power Administration customers in PacifiCorp'scontrol area.
(en)OS RS 262 various various 330 1,282,281 1,205,345 2,069,609 (nb)550,000 2,619,609
233 Western Area Power Administration Western Area Power Administration Various Western Area Power Administration customers in PacifiCorp's
control area.
(eo)AD RS 262 various various 330 131,427 123,541 (nc)242,636 242,636
234 Western Area Power Administration Western Area Power Administration Various Western Area Power Administration customers in PacifiCorp'scontrol area.
(ep)OS RS 263 various various 30,612 28,744 (nd)27,894 27,894
235 Western Area Power Administration Western Area Power Administration Various Western Area Power Administration customers in PacifiCorp'scontrol area.
(eq)AD RS 263 various various 2,076 1,959 (ne)1,813 1,813
236 Western Area Power Administration Western Area Power Administration various signatories (er)OS RS 684 Dave
Johnston Sub various
237 Western Area Power Administration Western Area Power Administration Western Area Power Administration FNO SA 175 WyomingDistribution WyomingDistribution 1 10,327 10,327 48,363 (nf)45,007 93,370
238 Western Area Power Administration Western Area Power Administration Colorado River Storage Project Western Area Power Administration (es)AD SA 175 various Wyoming
Distribution 1 5 5 (ng)(3,229) (3,229)
239 Western Area Power Administration Western Area Power Administration Colorado River Storage Project various signatories NF SA 137 various various 1,676 1,676 11,259 (nh)699 11,958
240 Western Area Power Administration Colorado River Storage Project Western Area Power Administration Colorado River Storage Project various signatories NF SA 132 various various 2,525 (ni)157 2,682
241 Accrual (342,334) (344,674)(nj)5,161,858 5,161,858
35 TOTAL 7,127 19,273,875 19,184,728 106,540,090 36,357,750 44,249,275 187,147,115
FERC FORM NO. 1 (ED. 12-90)Page 328-330
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) 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.
(b) Concept: TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
(c) Concept: TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
(d) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
(e) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
(f) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
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.
(g) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
(h) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
(i) Concept: StatisticalClassificationCode
Transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 876). Service provided pursuant to rules and regulations of Oregon Direct Access. Agreement terminates upon notification pursuant to Oregon Direct Access and Open Access Transmission Tariff.
(j) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 965) terminating on December 31, 2024.
(k) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 965) terminating on December 31, 2024.
(l) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(m) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(n) Concept: StatisticalClassificationCode
Ancillary services under the Open Access Transmission Tariff (1st Revised Service Agreement 476) in effect until superseded.
(o) Concept: StatisticalClassificationCode
Ancillary services under the Open Access Transmission Tariff (1st Revised Service Agreement 476) in effect until superseded.
(p) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 895) terminating on April 30, 2024.
(q) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 895) terminating on April 30, 2024.
(r) 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.
(s) 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.
(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
Network transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 347) terminating on December 31, 2023.
(v) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 67) terminating on December 31, 2023.
(w) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 67) terminating on December 31, 2023.
(x) 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.
(y) 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.
(z) 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.
(aa) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 656) terminating on August 31, 2030.
(ab) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 656) terminating on August 31, 2030.
(ac) 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.
(ad) 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.
(ae) Concept: StatisticalClassificationCode
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Network transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 538) terminating on September 30, 2028.
(af) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (5th Revised Service Agreement 179) terminating on September 30, 2025.
(ag) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (5th Revised Service Agreement 179) terminating on September 30, 2025.
(ah) 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.
(ai) 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.
(aj) 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.
(ak) Concept: StatisticalClassificationCode
Network transmission service under the Open Access Transmission Tariff (2nd Revised Service Agreement 827) terminating on September 30, 2028.
(al) 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.
(am) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(an) 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.
(ao) Concept: StatisticalClassificationCode
Network transmission service under the Open Access Transmission Tariff (2nd Revised Service Agreement 735) terminating on September 30, 2028.
(ap) 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.
(aq) 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.
(ar) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(as) 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.
(at) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 881) terminating on February 28, 2023.
(au) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 881) terminating on February 28, 2023.
(av) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 899) terminating on September 30, 2023.
(aw) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 899) terminating on September 30, 2023.
(ax) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 901) terminating on September 30, 2023.
(ay) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 901) terminating on September 30, 2023.
(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
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.
(bb) 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.
(bc) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bd) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(be) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(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
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 874) terminating on December 31, 2032.
(bh) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 874) terminating on December 31, 2032.
(bi) 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.
(bj) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bk) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bl) 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.
(bm) Concept: StatisticalClassificationCode
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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.
(bn) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 868) terminating on December 31, 2034.
(bo) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 868) terminating on December 31, 2034.
(bp) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 966) terminating on November 30, 2024.
(bq) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 966) terminating on November 30, 2024.
(br) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(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
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 212) terminating on May 31, 2024.
(bu) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 212) terminating on May 31, 2024.
(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
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bz) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ca) 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.
(cb) 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.
(cc) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(cd) Concept: StatisticalClassificationCode
Network transmission service under the Open Access Transmission Tariff (Service Agreement 894) terminating on December 31, 2057.
(ce) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 733) terminating on November 30, 2023.
(cf) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 733) terminating on November 30, 2023.
(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
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.
(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 (9th Revised Service Agreement 169) terminating on October 31, 2025.
(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 1016) 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 (Service Agreement 1017) terminating on June 30, 2024.
(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
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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
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.
(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
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(di) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 863) terminating on June 30, 2027.
(dj) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 863) terminating on June 30, 2027.
(dk) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 809) terminating on October 31, 2025.
(dl) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 809) terminating on October 31, 2025.
(dm) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 791) terminating upon written notification.
(dn) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 791) terminating upon written notification.
(do) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dp) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dq) 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. Terminated in September 2022.
(dr) 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. Terminated in September 2022.
(ds) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 779) terminating on August 31, 2024.
(dt) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 779) terminating on August 31, 2024.
(du) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(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 (3rd Revised Service Agreement 568) terminating on April 30, 2029.
(dy) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 568) terminating on April 30, 2029.
(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
Network transmission service under the Open Access Transmission Tariff (10th Revised Service Agreement 628) terminating on June 30, 2031.
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(ec) Concept: StatisticalClassificationCode
Network transmission service and distribution delivery service under the Open Access Transmission Tariff (2nd Revised Service Agreement 506) terminating upon written notification.
(ed) 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.
(ee) 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.
(ef) 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.
(eg) 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.
(eh) 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.
(ei) 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.
(ej) 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.
(ek) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(el) 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.
(em) 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.
(en) 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.
(eo) 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.
(ep) 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.
(eq) 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.
(er) 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. 3-Q.
(es) Concept: StatisticalClassificationCode
Evergreen network transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 175).
(et) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(eu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ev) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ew) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ex) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ey) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ez) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fa) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(fd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fe) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ff) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fi) 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.
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(fj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Transmission resale - purchase of point-to-point transmission. Scheduling, system control and dispatch service. Reactive supply and voltage control 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.
(fs) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ft) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Reactive supply and voltage control service.
(fx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(fy) 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.
(fz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ga) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(gb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(gd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ge) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Reactive supply and voltage control service.
(gf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gh) 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.
(gi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gj) 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.
(gk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gl) 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.
(gm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(go) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gp) 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.
(gq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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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. Reactive supply and voltage control 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
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.
(gw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(gy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(gz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ha) 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.
(hb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(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.
(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
Annual transmission services true-up and prior period charges/refund.
(hh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(hj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hl) 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.
(hm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(hn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ho) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(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
Annual transmission services true-up and prior period charges/refund.
(hs) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ht) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(hu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(hy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
4/17/23, 2:37 PM FERC Form
file:///C:/Users/p20323/AppData/Local/Temp/Temp1_PacifiCorp Form 1.zip/ferc_renderer.html 185/266
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hz) 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.
(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. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(ic) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(id) 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.
(ie) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(if) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ig) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ih) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ii) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ij) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ik) 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.
(il) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(im) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(in) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(io) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ip) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(iq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ir) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(is) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(it) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(iu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(iv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(iw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ix) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(iy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(iz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ja) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control 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
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(jg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
4/17/23, 2:37 PM FERC Form
file:///C:/Users/p20323/AppData/Local/Temp/Temp1_PacifiCorp Form 1.zip/ferc_renderer.html 186/266
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ji) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(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
Annual transmission services true-up and prior period charges/refund.
(jo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(jr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(js) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(jt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(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
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(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
Scheduling, system control and dispatch service.
(kd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ke) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(kf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(kg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(kh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ki) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(kj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(kk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(kl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(km) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(kn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ko) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
4/17/23, 2:37 PM FERC Form
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Scheduling, system control and dispatch service.
(kp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(kq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ks) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ku) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(kw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(ky) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(la) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(lc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ld) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(le) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(lg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(li) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(lk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
(ll) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(lm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ln) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(lo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(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
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(lv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
4/17/23, 2:37 PM FERC Form
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Annual transmission services true-up and prior period charges/refund.
(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
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.
(mb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(mc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(md) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(me) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(mg) 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.
(mh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(mi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ml) 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.
(mm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(mn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Energy consumption charge for deliveries at and below 138kV.
(mo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(mp) 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.
(mq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(mr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ms) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mt) 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.
(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
Annual transmission services true-up and prior period charges/refund.
(mx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(my) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mz) 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.
(na) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(nb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Fixed termination fee associated with a contract cancellation applied for the duration of this agreement.
(nc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Fixed termination fee associated with a contract cancellation applied for the duration of this agreement. Prior period adjustment.
(nd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Charges for low-voltage transmission of power and energy.
(ne) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
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Charges for low-voltage transmission of power and energy. Prior period adjustment.
(nf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Distribution voltage service charge. Primary delivery service. Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ng) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up and prior period charges/refund.
(nh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ni) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(nj) 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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-FirmTransmission 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
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41
42
43
44
45
46
47
48
49
40 TOTAL
FERC FORM NO. 1 (REV 03-07)Page 331
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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)LFP (56,187) (56,187)
2 Adams Solar Center, LLC OS (10,568) (10,568)
3 Arizona Public Service Company (i)AD (bo)(8,686) (8,686)
4 Arizona Public Service Company NF 11,303 11,303 69,636 69,636
5 Arizona Public Service Company OS 433,179 433,179
6 Arizona Public Service Company SFP 866,880 866,880 5,199,957 5,199,957
7 Ashland, City of (j)AD (bp)3,795 3,795
8 Ashland, City of FNS 2,840 2,840 24,603 24,603
9 Avista Corporation (k)AD (bq)6,718 6,718
10 Avista Corporation FNS 25,993 25,234 233,988 233,988
11 Avista Corporation NF 104,192 104,321 759,589 759,589
12 Avista Corporation OS 15,492 15,492
13 Avista Corporation SFP 251,548 251,548 1,120,682 1,120,682
14 Basin Electric Power Cooperative, Inc.NF 150 150 224 224
15 Basin Electric Power Cooperative, Inc.OS 143 143
16 Big Horn Rural Electric Company (l)(m)OLF 30,208 30,208 (br)137,165 137,165
17 Black Hills Power, Inc.(n)AD (bs)(123)(123)
18 Black Hills Power, Inc.NF 3,252 3,252 3,252 3,252
19 Black Hills Power, Inc.(o)OS (bt)8,542 8,542
20 Black Hills Power, Inc.SFP 6,144 6,144 46,264 46,264
21 Bonneville Power Administration (p)AD (bu)1,287,540 1,287,540
22 Bonneville Power Administration FNS 4,135 4,274 8,543,866 8,543,866
23 Bonneville Power Administration (q)LFP 5,328,751 5,506,636 69,970,956 69,970,956
24 Bonneville Power Administration NF 1,962,814 2,026,876 7,823,273 7,823,273
25 Bonneville Power Administration (r)OLF 3,025,610 3,126,839 2,683,200 2,683,200
26 Bonneville Power Administration (s)(t)(u)OS (bv)(bw)18,501,219 18,501,219
27 Bonneville Power Administration SFP 3,818 3,963 20,021 20,021
28 California Independent System Operator Corporation (v)AD (bx)(703)(703)
29 California Independent System Operator Corporation (w)OS (by)11,015,918 11,015,918
30 California Independent System Operator Corporation SFP 39,061 39,061
31 Deseret Generation & Transmission Cooperative (x)LFP 674,520 674,520 2,377,700 2,377,700
32 Deseret Generation & Transmission Cooperative NF 616 616 15,827 15,827
33 Elbe Solar Center, LLC (y)LFP (271,328) (271,328)
Name of Company or Public Authority (Footnote Affiliations)Statistical Classification MegaWatt Hours Received MegaWatt Hours Delivered Demand Charges ($)Energy Charges ($)OtherCharges
($)
Total Cost ofTransmission
($)
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34 Elbe Solar Center, LLC (z)OS (bz)(51,832) (51,832)
35 El Paso Electric Company NF 9,040 9,040 47,817 47,817
36 El Paso Electric Company OS 80 80
37 Flathead Electric Cooperative, Inc.(aa)AD (ca)(1,728) (1,728)
38 Flathead Electric Cooperative, Inc.(ab)OS (cb)76,437 76,437
39 (a)Hermiston Generating Company, L.P.(ac)OS (cc)222,252 222,252
40 Idaho Power Company (ad)AD (cd)(76,130) (76,130)
41 Idaho Power Company FNS 13,006 13,006
42 Idaho Power Company (ae)LFP 4,467,600 4,467,600 16,352,199 16,352,199
43 Idaho Power Company NF 221,062 221,062 448,477 448,477
44 Idaho Power Company (af)(ag)OLF (ce)29,760 29,760
45 Idaho Power Company (ah)OS (cf)(23,791) (23,791)
46 Idaho Power Company SFP 259,824 259,824 885,159 885,159
47 Los Angeles Department of Water and Power (ai)AD (cg)(12,834) (12,834)
48 Los Angeles Department of Water and Power NF 69,280 69,280 536,899 536,899
49 Los Angeles Department of Water and Power (aj)OS (ch)51,512 51,512
50 Los Angeles Department of Water and Power SFP 1,525 1,525 12,917 12,917
51 Moon Lake Electric Association, Inc.FNS 19 19 276,832 276,832
52 Morgan City Corporation (ak)AD (ci)217 217
53 Morgan City Corporation (al)LFP 1,613 1,613
54 (b)Nevada Power Company (am)AD (cj)35,966 35,966
55 (c)Nevada Power Company NF 56,846 56,846 279,563 279,563
56 (d)Nevada Power Company (an)OS (ck)65,961 65,961
57 (e)Nevada Power Company SFP 219,840 219,840 895,740 895,740
58 NorthWestern Corporation (ao)AD (cl)11,976 11,976
59 NorthWestern Corporation NF 11,300 11,300 52,816 52,816
60 NorthWestern Corporation (ap)OS (cm)471,908 471,908
61 NorthWestern Corporation SFP 625,705 651,020 3,007,182 3,007,182
62 Platte River Power Authority (aq)LFP 206,200 206,200 878,212 878,212
63 Platte River Power Authority NF 6 6 29 29
64 Platte River Power Authority (ar)OS (cn)22,044 22,044
65 Portland General Electric Company (as)AD (co)12 12
66 Portland General Electric Company (at)LFP 105,120 105,120 183,204 183,204
67 Portland General Electric Company NF 648 648 1,916 1,916
68 Portland General Electric Company (au)OLF 219 219
69 Portland General Electric Company (av)OS 4,349 (cp)17,544 17,544
70 Public Service Company of Colorado (aw)LFP 115,425 115,425 443,122 443,122
71 Public Service Company of Colorado NF 104,702 104,702 699,559 699,559
72 Public Service Company of Colorado (ax)OS (cq)154,403 154,403
73 Public Service Company of Colorado SFP 24,702 24,702
74 Public Service Company of New Mexico (ay)AD (cr)22 22
75 Public Service Company of New Mexico NF 35 35 280 280
76 Public Service Company of New Mexico (az)OS (cs)655 655
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77 Public Service Company of New Mexico SFP 13,440 13,440 71,456 71,456
78 Salt River Project (ba)AD (ct)2 2
79 Salt River Project NF 125 125 771 771
80 Salt River Project (bb)OS (cu)111 111
81 (f)Sierra Pacific Power Company NF 6,110 6,110 31,121 31,121
82 (g)Sierra Pacific Power Company (bc)OS (cv)989 989
83 Surprise Valley Electrification Corp.(bd)(be)OLF (cw)7,195 7,195
84 Tri-State Generation and Transmission Association, Inc.(bf)LFP 420,480 420,480 1,158,704 1,158,704
85 Tri-State Generation and Transmission Association, Inc.NF 8,952 8,952 259,684 259,684
86 Tri-State Generation and Transmission Association, Inc.(bg)OS (cx)18,652 18,652
87 Tucson Electric Power Company NF 125 125 729 729
88 Tucson Electric Power Company (bh)OS (cy)73 73
89 Western Area Power Administration (bi)AD (cz)71,071 71,071
90 Western Area Power Administration FNS 936,980 936,980 6,154,677 6,154,677
91 Western Area Power Administration NF 267,638 267,638 973,123 973,123
92 Western Area Power Administration (bj)(bk)(bl)OS (da)(db)725,090 725,090
93 Western Area Power Administration SFP 66,794 66,794 190,887 190,887
94 Westport Field Services, LLC (bm)(bn)LFP (dc)(1,605,720)(1,605,720)
95 Accrual (dd)(853,472)(853,472)
TOTAL 20,497,595 20,870,089 132,472,386 65,277 30,697,592 163,235,255
FERC FORM NO. 1 (REV. 02-04)
Page 332
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FOOTNOTE DATA
(a) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Hermiston Generating Company, L.P. operates the Hermiston Plant and is jointly owned. PacifiCorp owns a 50% share of the Hermiston 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
Adams Solar Center, LLC - contract termination date: October 30, 2036.
(i) Concept: StatisticalClassificationCode
Settlement adjustment.
(j) Concept: StatisticalClassificationCode
Settlement adjustment.
(k) Concept: StatisticalClassificationCode
Settlement adjustment.
(l) Concept: StatisticalClassificationCode
Big Horn Rural Electric Company - contract termination date: March 10, 2024.
(m) Concept: StatisticalClassificationCode
Use of facilities.
(n) Concept: StatisticalClassificationCode
Settlement adjustment.
(o) Concept: StatisticalClassificationCode
Ancillary services.
(p) Concept: StatisticalClassificationCode
Settlement adjustment.
(q) Concept: StatisticalClassificationCode
Bonneville Power Administration - contract termination dates: March 2023, July 2023, October 2023, December 2023, January 2024, July 2024, September 2024, October 2024, November 2024, October 2025, November 2025, January 2026, July 2026, September 2026, November 2026, December 2026, January 2027, March 2027, April 2027, July 2027, October 2027, November 2027, November 2033, December 2041, and evergreen.
(r) Concept: StatisticalClassificationCode
Bonneville Power Administration - contract termination dates: September 30, 2023; September 30, 2027 and evergreen.
(s) Concept: StatisticalClassificationCode
Ancillary services.
(t) Concept: StatisticalClassificationCode
Use of facilities.
(u) 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.
(v) Concept: StatisticalClassificationCode
Settlement adjustment.
(w) Concept: StatisticalClassificationCode
Ancillary services.
(x) Concept: StatisticalClassificationCode
Deseret Generation & Transmission Cooperative - contract termination date: November 1, 2034.
(y) Concept: StatisticalClassificationCode
Elbe Solar Center, LLC - contract termination date: October 30, 2036.
(z) Concept: StatisticalClassificationCode
Ancillary services.
(aa) Concept: StatisticalClassificationCode
Settlement adjustment.
(ab) Concept: StatisticalClassificationCode
Use of facilities.
(ac) Concept: StatisticalClassificationCode
Use of facilities.
(ad) Concept: StatisticalClassificationCode
Settlement adjustment.
(ae) Concept: StatisticalClassificationCode
Idaho Power Company - contract termination dates: April 1, 2025 and July 1, 2025.
(af) 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.
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(ag) Concept: StatisticalClassificationCode
Use of facilities.
(ah) Concept: StatisticalClassificationCode
Ancillary services.
(ai) Concept: StatisticalClassificationCode
Settlement adjustment.
(aj) Concept: StatisticalClassificationCode
Ancillary services.
(ak) Concept: StatisticalClassificationCode
Settlement adjustment.
(al) Concept: StatisticalClassificationCode
Morgan City Corporation - contract termination date: evergreen.
(am) Concept: StatisticalClassificationCode
Settlement adjustment.
(an) Concept: StatisticalClassificationCode
Ancillary services.
(ao) Concept: StatisticalClassificationCode
Settlement adjustment.
(ap) Concept: StatisticalClassificationCode
Ancillary services.
(aq) Concept: StatisticalClassificationCode
Platte River Power Authority - contract termination date: October 31, 2027.
(ar) Concept: StatisticalClassificationCode
Ancillary services.
(as) Concept: StatisticalClassificationCode
Settlement adjustment.
(at) Concept: StatisticalClassificationCode
Portland General Electric Company - contract termination date: April 1, 2027.
(au) Concept: StatisticalClassificationCode
Portland General Electric Company - contract termination date: Upon two years written notice.
(av) Concept: StatisticalClassificationCode
Ancillary services.
(aw) 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.
(ax) Concept: StatisticalClassificationCode
Ancillary services.
(ay) Concept: StatisticalClassificationCode
Settlement adjustment.
(az) Concept: StatisticalClassificationCode
Ancillary services.
(ba) Concept: StatisticalClassificationCode
Settlement adjustment.
(bb) Concept: StatisticalClassificationCode
Ancillary services.
(bc) Concept: StatisticalClassificationCode
Ancillary services.
(bd) Concept: StatisticalClassificationCode
Use of facilities.
(be) Concept: StatisticalClassificationCode
Surprise Valley Electrification Corp. - contract termination date: evergreen
(bf) 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.
(bg) Concept: StatisticalClassificationCode
Ancillary services.
(bh) Concept: StatisticalClassificationCode
Ancillary services.
(bi) Concept: StatisticalClassificationCode
Settlement adjustment.
(bj) Concept: StatisticalClassificationCode
Ancillary services.
(bk) Concept: StatisticalClassificationCode
Use of facilities.
(bl) 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. See also Page 328, Transmission of electricity for others in this Form No. 1.
(bm) Concept: StatisticalClassificationCode
Reimbursement for third-party services.
(bn) Concept: StatisticalClassificationCode
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Westport Field Services, LLC - contract termination date: evergreen.
(bo) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(bp) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(bq) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(br) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(bs) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(bt) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(bu) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(bv) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(bw) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(bx) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(by) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(bz) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(ca) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cb) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(cc) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(cd) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(ce) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(cf) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cg) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(ch) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(ci) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cj) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(ck) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cl) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cm) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cn) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(co) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cp) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cq) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cr) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cs) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(ct) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cu) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cv) Concept: OtherChargesTransmissionOfElectricityByOthers
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Ancillary services.
(cw) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(cx) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cy) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cz) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(da) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(db) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(dc) Concept: OtherChargesTransmissionOfElectricityByOthers
Reimbursement for third-party services.
(dd) 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.Description
(a)
Amount
(b)
1 1,421,742
2
3
4
5
6 Business & Economic Development and Corporate Memberships & Subscriptions:
7 Advance Casper 10,000
8 Carbon County Economic Development Corporation 5,000
9 ChamberWest 5,000
10 Clatsop Economic Development Resources 5,000
11 Economic Development for Central Oregon 7,500
12 Greater Yakima Chamber of Commerce 5,000
13 Jordan River Commission 7,500
14 Klamath County Economic Development Association 5,000
15 Lander Chamber of Commerce 5,000
16 Laramie Chamber of Business Alliance 5,000
17 Ogden-Weber Chamber of Commerce 6,000
18 Oregon Business Council 29,748
19 Oregon Economic Development Association 5,000
20 Oregon State University College of Forestry 15,000
21 Oregon State University, Utility Pole Research Cooperative 15,000
22 Portland Business Alliance 40,243
23 Redmond Economic Development, Inc.5,000
24 Salt Lake Chamber 27,000
25 South Valley Chamber 5,000
26 Sport Oregon 5,000
27 Utah Manufacturers Association 8,785
28 Utah Taxpayers Association 18,700
29 Utah Valley Chamber of Commerce 10,000
30 Walla Walla Valley Chamber of Commerce 10,000
31 Wyoming Business Alliance 9,250
32 Wyoming Construction Coalition, Inc.5,000
33 Wyoming County Commissioners Association 25,062
34 Yakima County Development Association 7,500
35 Other (Individually < $5,000)77,096
36 Rating Agency and Trustee Fees:
37 Computershare Shareowner Services, LLC 26,450
38 Moody's Investors Service 235,349
39 Standard and Poor's Financial Services, LLC 205,202
40 The Bank of New York Mellon 137,603
41 U.S. Bank National Association 15,293
42 Directors' Fees - Regional Advisory Board 14,000
46 2,440,023
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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 compositedepreciation 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 64,151,576 64,151,576
2 Steam Production Plant 385,120,154 385,120,154
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 36,200,450 312,727 36,513,177
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 202,888,708 40,954 202,929,662
7 Transmission Plant 137,423,038 137,423,038
8 Distribution Plant 204,800,954 204,800,954
9 Regional Transmission and Market Operation
10 General Plant 49,920,325 432,399 50,352,724
11 Common Plant-Electric
12 TOTAL (a)1,016,353,629 (b)0 64,937,656 1,081,291,285
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
LineNo.(a)(b)(c)(d)(e)(f)(g)
12 OTHER PRODUCTION PLANT: PRYOR MOUNTAIN - WIND: 340.20 0.079 3.45%
13 (c)Account 403 - Provisions
FERC FORM NO. 1 (REV. 12-03)Page 336-337
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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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, 2022, depreciation expense associated with transportation equipment was $23,520,027.
(b) Concept: DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as a regulatory asset or liability.
(c) 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 6,854,134 6,854,134 Electric 928 6,854,134
2 Utah Public Service Commission: Rate Cases and Proceedings 149,468 149,468 Electric 928 149,468
3 Oregon Public Utility Commission: Annual Fee 4,806,077 4,806,077 Electric 928 4,806,077
4 Oregon Public Utility Commission: Rate Cases and Proceedings 1,613,884 1,613,884 Electric 928 1,613,884
5 Oregon Public Utility Commission: Deferred Intervenor Funding Grants 2,541,940 486,640 3,028,580
6 Wyoming Public Service Commission: Annual Fee 1,725,894 1,725,894 Electric 928 1,725,894
7 Wyoming Public Service Commission: Rate Cases and Proceedings 227,457 227,457 Electric 928 227,457
8 Washington Utilities and Transportation Commission: Annual Fee 1,160,301 1,160,301 Electric 928 1,160,301
9 Washington Utilities and Transportation Commission: Rate Cases and Proceedings 251,066 251,066 Electric 928 251,066
10 Idaho Public Utilities Commission: Annual Fee 577,903 577,903 Electric 928 577,903
11 Idaho Public Utilities Commission: Rate Cases and Proceedings 15,381 15,381 Electric 928 15,381
12 Idaho Public Utilities Commission: Deferred Intervenor Funding Grants 40,000 40,000
13 California Public Utilities Commission: Annual Fee 4,619 4,619 Electric 928 4,619
14 California Public Utilities Commission: Rate Cases and Proceedings 873,331 873,331 Electric 928 873,331
15 California Public Utilities Commission: Deferred Intervenor Funding Grants 392,138 12,574 404,712
16 California Environmental Protection Agency: Industry Compliance Fee 45,940 17,078 63,018 Electric 928 63,018
17 Multi-State: Rate Cases and Proceedings 89,951 89,951 Electric 928 89,951
18 Multi-State: Other Regulatory 364,529 364,529 Electric 928 364,529
19 Federal Energy Regulatory Commission: Annual Fee 3,092,400 3,092,400 Electric 928 3,092,400
20 Federal Energy Regulatory Commission: Annual Fee - Hydroelectric Plants 3,155,288 3,155,288 Electric 928 3,155,288
21 Federal Energy Regulatory Commission: Transmission Rate Cases 177,164 177,164 Electric 928 177,164
22 Federal Energy Regulatory Commission: Other Regulatory 964,834 964,834 Electric 928 964,834
46 TOTAL 21,422,556 4,744,143 26,166,699 2,934,078 26,166,699 539,214 3,473,292
FERC FORM NO. 1 (ED. 12-96)
Page 350-351
Description (Furnish name of regulatory commission or body the docket orcase number and a description of the case)Assessed by Regulatory Commission Expenses of Utility Total Expenses for Current Year Deferred in Account 182.3 at Beginning of Year Department AccountNo.Amount
DeferredtoAccount182.3
ContraAccount Amount
Deferred
inAccount182.3End ofYear
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 wildlifeOther hydroelectric
Fossil-fuel steam
Internal combustion or gas turbineNuclearUnconventional generationSiting and heat rejection
Transmission
OverheadUndergroundDistribution
Regional Transmission and Market Operation
Environment (other than equipment)Other (Classify and include items in excess of $50,000.)Total Cost IncurredElectric, 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 GroupsResearch 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:
2 (1)b. Generation, Fossil-fuel steam (a)Utah Sustainable Transportation and Energy Plan - Clean Coal Technology Projects (201)908 (201)
3 (3) Distribution (b)Utah Sustainable Transportation and Energy Plan - Innovative Utility Projects 309 105,640 908 105,949
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 InCurrent Year: Amount UnamortizedAccumulation
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: ResearchDevelopmentAndDemonstrationDescription
The Utah Sustainable Transportation and Energy Plan was signed into law in March 2016. The Utah legislation established a five-year pilot program to provide up to $10 million annually of mandated funding for electric vehicle infrastructure and clean coal research, and authorized funding at the Utah Public Service Commission's discretion for solar development, utility-scale battery storage and other innovative technology, economic development and air quality initiatives.
(b) Concept: ResearchDevelopmentAndDemonstrationDescription
The Utah Sustainable Transportation and Energy Plan was signed into law in March 2016. The Utah legislation established a five-year pilot program to provide up to $10 million annually of mandated funding for electric vehicle infrastructure and clean coal research, and authorized funding at the Utah Public Service Commission's discretion for solar development, utility-scale battery storage and other innovative technology,
economic development and air quality initiatives.
FERC FORM NO. 1 (ED. 12-87)
Page 352-353
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 98,022,487
4 18,574,344
5
6 44,646,731
7 29,588,283
8 8,164,767
9
10 35,058,626
11 234,055,238
12
13 42,740,350
14 12,762,662
15
16 74,108,341
17 1,837,070
18 131,448,423
19
20 140,762,837
21 31,337,006
22
23 118,755,072
24 29,588,283
25 8,164,767
26
27 36,895,696
28 365,503,661 365,503,661
29
30
31
32
33
34
35
36
37
38
39
40
41
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)
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42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65 365,503,661 365,503,661
66
67
68 182,699,716 182,699,716
69
70
71 182,699,716 182,699,716
72
73 12,733,927 12,733,927
74
75
76 12,733,927 12,733,927
77
78
79 5,985,749 5,985,749
80 391,293 391,293
81 584,499 584,499
82 10,008,586 10,008,586
83
84
85
86
87
88
89
Maintenance
Production - Manufactured Gas
Production-Natural Gas (Including Exploration and Development)
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
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90
91
92
93
94
95 16,970,127 16,970,127
96 577,907,431 577,907,431
FERC FORM NO. 1 (ED. 12-88)Page 354-355
TOTAL Other Accounts
TOTAL SALARIES AND WAGES
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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.
LineNo.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)24,651 24,717 215,402 344,570
2.1 Net Purchases (Account 555.1)
3 Net Sales (Account 447)(16)(16)(16)(16)
4 Transmission Rights
5 Ancillary Services
6 Other Items (list separately)
7 Energy Imbalance Market (Account 555)(37,040,608)(94,990,193)(214,249,930)(294,703,565)
46 TOTAL (37,015,973)(94,965,492)(214,034,544)(294,359,011)
FERC FORM NO. 1 (NEW. 12-05)
Page 397
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
LineNo.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 149,022,238 MWh 13,341,675
2 Reactive Supply and Voltage 115,056,579 MWh 21,928,676 137,611,410 MWh 26,464,769
3 Regulation and Frequency Response 122,767,866 MWh 28,490,830 142,746,327 MWh 35,050,049
4 Energy Imbalance 3,454,077 MWh 36,164,027
5 Operating Reserve - Spinning 123,914,475 MWh 20,817,632 142,142,077 MWh 23,878,490
6 Operating Reserve - Supplement 123,914,475 MWh 20,817,632 149,829,487 MWh 23,758,868
7 Other 0
8 Total (Lines 1 thru 7)485,653,395 MWh 92,054,770 724,805,616 MWh 158,657,878
FERC FORM NO. 1 (New 2-04)Page 398
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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-TermFirm Point-to-pointReservations(g)
OtherLong-Term
Firm
Service(h)
Short-TermFirm Point-to-pointReservation(i)
OtherService(j)
NAME OF SYSTEM: 0
1 January 15,371 3 18 8,735 570 3,459 1,274 1,333
2 February 16,542 23 8 8,996 661 3,459 2,104 1,322
3 March 14,974 10 8 8,460 633 3,459 1,118 1,304
4 Total for Quarter 1 26,191 1,864 10,377 4,496 3,959
5 April 14,708 13 9 8,024 497 3,458 1,483 1,246
6 May 15,104 26 17 8,299 364 3,562 1,339 1,540
7 June 18,940 27 18 10,397 452 3,706 2,570 1,815
8 Total for Quarter 2 26,720 1,313 10,726 5,392 4,601
9 July 19,657 28 17 11,169 501 3,702 2,352 1,933
10 August 19,686 31 17 10,772 465 3,702 2,750 1,997
11 September 20,091 6 17 10,730 449 3,704 3,160 2,048
12 Total for Quarter 3 32,671 1,415 11,108 8,262 5,978
13 October 14,218 6 17 7,644 326 3,706 1,192 1,350
14 November 15,694 29 18 8,645 573 3,506 1,655 1,315
15 December 16,691 22 18 9,168 699 3,506 2,033 1,285
16 Total for Quarter 4 25,457 1,598 10,718 4,880 3,950
17 Total (a)111,039 (b)6,190 (c)42,929 (d)23,030 (e)18,488
FERC FORM NO. 1 (NEW. 07-04)Page 400
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
ServiceUsage(i)
TotalUsage(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
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Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:2023-04-18 Year/Period of ReportEnd of: 2022/ 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)57,164,096
3 Steam 33,269,618 23 Requirements Sales for Resale (See instruction 4, page 311.)273,270
4 Nuclear 24 Non-Requirements Sales for Resale (See instruction 4, page 311.)4,563,022
5 Hydro-Conventional 2,939,814 25 Energy Furnished Without Charge
6 Hydro-Pumped Storage 26 Energy Used by the Company (Electric Dept Only, Excluding Station Use)(a)144,838
7 Other 16,308,950 27 Total Energy Losses 4,342,866
8 Less Energy for Pumping 4,056 27.1 Total Energy Stored
9 Net Generation (Enter Total of lines 3 through 8)52,514,326 28 TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES 66,488,092
10 Purchases (other than for Energy Storage)17,164,181
10.1 Purchases for Energy Storage
11 Power Exchanges:
12 Received 6,394,830
13 Delivered 9,301,898
14 Net Exchanges (Line 12 minus line 13)(2,907,068)
15 Transmission For Other (Wheeling)
16 Received 19,273,875
17 Delivered 19,184,728
18 Net Transmission for Other (Line 16 minus line 17)89,147
19 Transmission By Others Losses (372,494)
20 TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)66,488,092
FERC FORM NO. 1 (ED. 12-90)Page 401a
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Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:2023-04-18 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: InternalUseEnergy
For metered locations only.
FERC FORM NO. 1 (ED. 12-90)
Page 401a
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 5,930,733 495,061 8,514 3 18
30 February 5,316,777 456,082 8,805 23 8
31 March 5,393,979 539,851 8,249 10 8
32 April 4,994,632 424,178 7,819 13 9
33 May 5,002,715 304,332 8,135 26 17
34 June 5,470,102 583,233 10,216 27 18
35 July 6,444,768 259,229 11,017 27 17
36 August 6,252,889 267,669 10,623 31 17
37 September 5,311,089 312,697 10,593 6 17
38 October 4,979,242 311,904 7,476 6 17
39 November 5,382,263 258,567 8,447 29 18
40 December 6,008,903 350,219 9,026 22 17
41 Total 66,488,092 4,563,022
FERC FORM NO. 1 (ED. 12-90)Page 401b
Month Total Monthly Energy Monthly Non-Requirement Sales for Resale & AssociatedLosses Monthly Peak - Megawatts Monthly Peak - Day of Month Monthly Peak - Hour
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 Mct.7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.
8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
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 ofplant.
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:DaveJohnston
PlantName:
Gadsby
Peakers
PlantName:
Gadsby
Steam
PlantName:
(d)Hayden
Plant Name:(e)Hermiston
Plant Name:(f)Hunter -Total Plant
Plant Name:(g)Hunter UnitNo. 1
Plant Name:(h)Hunter UnitNo. 2
Plant Name:Hunter UnitNo. 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 38 504 156 161 564 722 116 170 78 240 1,100 424 271 470 903 1,401 547 637 590 270
7 8,580 6,418 8,760 8,758 8,512 8,760 451 2,227 8,760 7,791 8,749 5,716 8,678 8,046 8,731 8,753 8,550 8,547 8,597 6,793
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 17 17 (k)0 (l)0 17 159 (m)0 28 (n)0 (o)0 184 (p)0 (q)0 (r)0 140 275 29 (s)0 101 54
12 262,129,000 2,171,994,000 1,080,477,000 1,066,740,000 2,805,979,000 3,581,919,000 3,348,000 115,473,000 523,072,000 1,433,878,000 5,865,764,000 1,777,337,000 1,434,289,000 2,654,138,000 5,673,115,000 7,376,117,000 3,047,188,000 3,531,485,000 2,456,201,000 1,343,811,000
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 8,560,993 24,673,334 70,285,327 38,840,051 44,441,422 169,193,662 4,273,000 15,597,601 18,014,887 12,902,298 214,854,459 65,677,305 55,051,238 94,125,916 129,280,130 150,842,695 35,808,970 53,403,807 134,169,823 54,345,252
15 106,676,568 335,057,846 180,408,667 186,635,182 313,525,353 910,243,608 84,343,954 72,772,477 98,512,231 171,980,270 1,109,402,252 394,035,965 254,730,227 460,636,060 792,656,084 1,295,421,239 335,160,637 574,108,770 647,580,263 426,864,408
16 5,607,448 1,355,802 7,310,048 3,180,430 261,730 30,295,336 1,372,866 2,330,719 618,012 13,053,975 4,351,325 4,351,325 4,351,325 6,881,631 48,906,883 59,253,098 677,254
17 162,040,605 364,817,509 259,792,686 228,792,749 361,631,782 1,120,181,204 88,616,954 90,995,034 119,540,906 186,297,509 1,366,936,695 473,744,495 323,812,690 569,379,510 931,195,409 1,496,364,578 385,501,882 644,307,203 842,444,006 482,097,440
18 4,253.034 614.896 1,669.512 1,329.186 637.911 1,371.477 489.461 361.608 1,471.273 666.395 1,095.495 1,034.987 1,099.683 1,148.892 916.982 964.992 651.957 983.375 1,191.239 1,664.356
19 5,580 171,863 (66,469)350,915 68,938 13,148 111,400 (108,689)22,829 8,240 5,304 9,285 4,749 12,899,059 103,142 126,268 354,309 33,399
20 144,499,963 (t)22,272,625 24,909,252 102,455,322 47,818,141 756,516 10,693,287 13,812,208 76,653,042 110,615,301 33,374,543 27,395,420 49,845,338 125,825,036 (u)200,531,042 113,701,690 124,095,798 90,267,799 22,633,607
21
22 276,783 154,163 1,951,667 3,702,898 199,675 1,057,240 21,636,723 6,594,109 6,698,590 8,344,024 14,472,070 24,475,399 8,089,623 5,196,311
23 6,037,863
24
25 1,916,441 (108,428)613,571 2,403,479 856,875 224,194 8,131,847 (23,662) (45,720)84,998 (62,940)17,694 3,655,092 4,549,215 2,856
26 1,026,449 1,025,482 4,038,529 1,131,512 577,603 16,395,804 4,324,591 103,585 5,794,936 4,208,755 (2,716,899)4,303,080 15,357,383 (21,398,417)332,823 409,098 6,718,078 2,014,964
27 7,560 83,212 13,146 9,847 1,199 2,100 3,642 287,408 376 460 100 17,847
28
29 354,292 531,874 116,953 307,789 111,102 71,498 125,189 1,193,380 497,921 1,938,010
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 CondenserWater
When Limited by CondenserWater
Average Number of Employees
Net Generation, Exclusive ofPlant Use - kWh
Cost of Plant: Land and LandRights
Structures and Improvements
Equipment Costs
Asset Retirement Costs
Total cost (total 13 thru 20)
Cost per KW of InstalledCapacity (line 17/5) Including
Production Expenses: Oper,Supv, & Engr
Fuel
Coolants and Water (NuclearPlants Only)
Steam Expenses
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses
Misc Steam (or Nuclear) PowerExpenses
Rents
Allowances
Maintenance Supervision andEngineering
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30 930,295 17,618 (12,103)347,285 471,449 3,180,224 101,023 217,244 222,662 4,138,840 2,158,351 824,874 1,155,615 2,931,591 7,888,103 1,191,787 1,235,600 1,728,850 394,034
31 182,882 2,715,100 2,841,405 12,076,428 1,196,448 1,281,360 13,135,374 7,095,449 2,093,204 3,946,721 15,003,273 23,680,560 8,751,438 6,690,399
32 185,788 5,200,108 2,101,027 459,478 1,140,493 9,615,009 215,096 1,664,064 707,919 6,617,537 4,613,905 730,502 1,273,130 5,122,247 11,869,388 415,796 412,325 4,029,630 3,218,131
33 59,657 320,343 665,270 46,433 3,144,916 170,080 145,195 116,594 2,548,917 884,001 584,047 1,080,869 880,476 3,115,389 16,872 18,194 1,722,320 138,214
34 8,712,857 152,831,475 31,769,079 33,802,229 107,163,717 96,029,780 2,099,590 18,551,904 17,534,026 84,784,889 164,807,730 59,012,582 35,772,737 70,022,411 180,793,847 263,863,546 119,417,578 130,846,958 123,603,013 40,336,906
35 0.0332 0.0704 0.0294 0.0317 0.0382 0.0268 0.6271 0.1607 0.0335 0.0591 0.0281 0.0332 0.0249 0.0264 0.0319 0.0358 0.0392 0.0371 0.0503 0.0300
35 Chehalis Colstrip Colstrip Craig Craig Currant
Creek
Dave
Johnston
Dave
Johnston
Gadsby
Peakers
Gadsby
Steam Hayden Hayden Hermiston Hunter -
Total Plant
Hunter -TotalPlant
Hunter
Unit No. 1
HunterUnit No.1
Hunter
Unit No. 2
HunterUnit No.2
Hunter
Unit No. 3
HunterUnit No.3 Huntington Huntington Jim
Bridger
Jim
Bridger Lake Side Lake Side
2 Naughton Naughton Wyodak 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 (af)Oil
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 Boe
38 14,680,500 667,299 861 552,706 20,029,289 2,484,095 14,408 97,122 1,953,447 243,500 388 10,406,574 2,627,175 12,473 798,682 3,108 656,224 1,113 1,172,269 8,252 2,520,067 5,273 4,215,906 11,559 24,005,516 21,676,066 1,013,953 7,170,833 1,039,989 4,874
39 1,097 8,596 140,000 9,933 133,614 1,048 8,312 138,000 1,017 1,045 11,117 136,057 1,048 11,566 138,000 11,609 138,000 11,710 138,000 11,457 138,000 11,411 138,000 9,355 138,000 1,045 1,045 10,055 1,052 7,891 138,000
40 9.843 31.244 123.624 47.196 5.115 18.707 151.260 7.789 5.474 53.726 117.295 7.366 41.454 155.610 49.645 131.714 41.948 110.819 5.245 5.169 47.580 5.437 20.901 144.432
41 9.843 33.218 123.624 44.714 5.115 18.372 151.260 7.789 5.474 56.338 117.295 7.366 41.366 155.610 41.174 41.482 41.430 49.654 131.714 47.262 110.819 5.245 5.169 50.575 5.437 21.086 144.432
42 8.971 1.932 21.025 2.251 4.883 1.105 26.097 7.656 5.238 2.534 20.524 7.031 1.788 26.848 1.773 27.167 1.771 26.941 1.808 26.715 2.176 22.725 2.526 19.120 5.021 4.948 2.515 5.166 1.336 24.920
43 0.067 0.021 0.023 0.037 0.013 0.001 0.226 0.093 0.026 0.053 0.019 0.019 0.019 0.018 0.022 0.027 0.037 0.035 0.021 0.016 0.016 0.001
44 7,416.061 10,618.446 4.686 10,293.286 7,477.183 11,528.529 23.315 29,514.636 17,679.795 10,350.095 4.234 7,602.803 10,360.829 12.324 10,433.700 10.136 10,715.447 4.496 10,120.396 18.020 10,137.477 5.387 10,693.743 9.083 7,432.220 7,102.156 8,302.024 3,072.670 12,213.855 21.023
FERC FORM NO. 1 (REV. 12-03)Page 402-403
Maintenance of Structures
Maintenance of Boiler (orreactor) Plant
Maintenance of Electric Plant
Maintenance of Misc Steam (or
Nuclear) Plant
Total Production Expenses
Expenses per Net kWh
Plant Name
Fuel Kind
Fuel Unit
Quantity(Units) ofFuel Burned
Avg HeatCont - FuelBurned
(btu/indicate
if nuclear)
Avg Cost of
Fuel/unit, asDelvd f.o.b.during year
AverageCost of Fuelper UnitBurned
AverageCost of Fuel
Burned per
Million BTU
Average
Cost of FuelBurned perkWh NetGen
AverageBTU perkWh Net
Generation
4/17/23, 2:37 PM FERC Form
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 2022 were $1.9 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, DeseretPower Electric Cooperative and Utah Associated Municipal Power Systems, each with anundivided interest of 60.31%, 25.108% and 14.582%, respectively. Data reported representsPacifiCorp's share. Costs that were billed to minority owners for the operations andmaintenance (excluding fuel) of this unit for calendar year 2022 were $7.6 million andwere 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 2022 were $31.3 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 2022 were $5.5 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.
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(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
4/17/23, 2:37 PM FERC Form
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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.
LineNo.Item(a)
FERC Licensed ProjectNo.14803Plant Name:
(a)(b)Copco No. 1
FERC Licensed ProjectNo.14803Plant Name:
(c)Copco No. 2
FERC Licensed ProjectNo.14803Plant Name:
(d)Iron Gate
FERC Licensed ProjectNo.14803Plant Name:
(e)JC Boyle
FERC Licensed
Project No.
1927Plant Name:Clearwater No. 1
FERCLicensedProject
No.
1927PlantName:ClearwaterNo. 2
FERCLicensedProject
No.
1927PlantName:FishCreek
FERC
LicensedProject No.1927PlantName:
Lemolo No.
1
FERC
LicensedProject No.1927PlantName:
Lemolo No.
2
FERCLicensedProject
No.
1927PlantName:SlideCreek
FERC
LicensedProject No.1927PlantName:
Soda
Springs
FERCLicensedProject No.1927Plant Name:
Toketee
FERCLicensedProject No.20Plant Name:
Grace
FERCLicensedProject No.20Plant Name:
Oneida
FERCLicensedProject No.20Plant Name:
Soda
FERCLicensedProject No.2071Plant Name:
Yale
FERCLicensedProject No.2111Plant Name:
Swift No. 1
FERCLicensedProject No.2420Plant Name:
Cutler
FERCLicensed
Project No.
2630Plant Name:ProspectNo. 2
FERCLicensedProject No.935Plant 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 18.00 97.98 15 26 11.00 31.99 38.50 18.00 11.00 42.50 33.00 30.00 14.45 134 240.00 30 32.00 136.00
6 27 31 19 76 8 11 11 29 31 15 12 37 22 13 10 164 251 30 34 146
7 4,387 4,288 8,455 5,083 8,684 7,982 3,208 8,642 7,951 8,588 8,720 8,601 4,897 8,760 4,524 6,316 5,496 5,382 8,744 8,760
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 2 1 1 1 1 1 1 1 1 2 1 3 2 3 1 1 3 1 1
12 64,464,000 76,669,000 77,201,000 157,072,000 23,783,000 19,946,000 21,343,000 104,064,000 108,628,000 51,532,000 43,711,000 183,318,000 44,164,000 26,211,000 14,406,000 527,461,000 616,675,000 25,493,000 161,545,000 487,064,000
13
14 74,674 309,259 511,083 8,363,013 20,287,495 3,507,754 105,168 1,955,029
15 1,538,996 2,501,188 1,764,935 3,136,740 6,618,213 2,308,973 4,335,355 5,632,491 4,366,304 3,064,049 1,411,371 18,810,433 75,832,393 5,002,210 4,885,599 114,983,112
16 5,232,135 15,051,267 12,465,242 15,815,119 33,766,811 15,208,417 91,062,652 14,522,980 16,597,312 9,099,320 11,267,298 35,120,685 51,415,209 11,988,985 37,392,880 40,887,824
17 1,577,000 2,217,159 2,993,343 6,945,395 12,065,486 9,079,477 2,864,603 6,669,170 6,605,218 15,930,300 6,516,351 18,987,591 26,082,045 15,291,535 7,439,801 20,570,892
18 50,817 250,151 533,014 531,801 1,820,580 582,653 2,089,011 625,687 616,213 984,865 2,372,045 1,302,690 1,086,176 686,471 4,527,994
19
20 8,398,948 20,019,765 17,756,534 26,429,055 54,271,090 27,179,520 100,351,621 27,450,328 28,259,721 29,387,793 19,706,103 83,653,767 174,919,832 36,876,660 50,509,919 182,924,851
21 559.930 769.991 1,614.230 826.166 1,409.639 1,509.973 9,122.875 645.890 856.355 979.593 1,363.744 624.282 728.833 1,229.222 1,578.435 1,345.036
22
23 52,819 68,395 1,756,257 269,458 38,526 160,061 45,815 82,095 228,758 53,250 32,589 215,018 162,037 142,309 71,674 1,748,135 3,253,741 199,573 802,867 1,767,304
24 299 518 219 637 767 52,465 219 847 72,076 129,092 7,632 73,152
25 242 326 217 1,184 29,378 50,921 21,544 62,653 75,403 35,253 80,654 83,239 44,053 40,048 18,689 911,078 1,882,466 120,795 387 924,676
26
27 1,111,388 1,420,248 1,504,689 835,421 269,763 436,688 346,770 575,370 597,150 313,302 374,195 667,793 1,557,007 548,830 419,357 426,620 333,422 1,439,639 441,423 678,234
28 127,304 171,046 114,031 2,456 65,508 113,548 48,039 139,707 168,138 78,610 49,164 186,736 16,738 14,762 6,982 146,396 262,201 (112,912)67,385 148,581
29 261
30 582 1,116 48,178 31,423 87,398 23,043 70,754 81,714 44,710 23,043 96,781 9,357 1,454 678 17,340 31,475 94,041 45,900
31 7,845 3,410 37,039 23,294 85,049 112,415 37,082 90,594 9,646 44,043 36,780 105,920 1,940 1,940 82,337 106,767 7,321 116,466 74,709
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 plateRating in MW)
Net Peak Demand on Plant-Megawatts(60 minutes)
Plant Hours Connect to Load
Net Plant Capability (in megawatts)
(a) Under Most Favorable OperConditions
(b) Under the Most Adverse OperConditions
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 (line20 / 5)
Production Expenses
Operation Supervision and Engineering
Water for Power
Hydraulic Expenses
Electric Expenses
Misc Hydraulic Power GenerationExpenses
Rents
Maintenance Supervision andEngineering
Maintenance of Structures
Maintenance of Reservoirs, Dams, and
Waterways
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32 2,939 47,284 84,029 (141,852)17,455 239,480 57,776 35,739 65,586 40,027 20,655 147,679 61,072 65,567 51,372 247,690 106,149 2,569 61,461 161,747
33 22,227 30,007 20,005 59,780 45,694 84,162 33,509 101,331 117,282 67,859 33,509 129,470 96,247 79,558 37,127 519,234 919,144 528,857 322,116 530,069
34 1,317,501 1,745,151 3,483,754 1,111,664 521,340 1,257,825 689,130 1,105,368 1,425,392 695,122 658,071 1,564,343 2,052,431 894,468 607,819 4,170,906 7,024,457 2,185,842 1,914,039 4,404,372
35 0.020 0.023 0.045 0.007 0.022 0.063 0.032 0.011 0.013 0.013 0.015 0.009 0.046 0.034 0.042 0.008 0.011 0.086 0.012 0.009
FERC FORM NO. 1 (REV. 12-03)Page 406-407
Maintenance of Electric Plant
Maintenance of Misc Hydraulic Plant
Total Production Expenses (total 23 thru
33)
Expenses per net kWh
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) 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.
(b) 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.
(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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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.0Plant 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
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)
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38
39 0
FERC FORM NO. 1 (REV. 12-03)Page 408-409
Expenses per kWh (line 37 / 9)
Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
LineNo.(a)(b)(c)(d)(e)(f)
(g)(h)(i)(j)(k)
(l)
(m)
1 Ashton (Licensed Project No. 2381)1917 6.85 7.0 27,949,000 34,600,876 5,051,223 483,434 107,439 Water (i)Hydro
2 Bend 1913 1.11 1.0 20,000 4,893,770 4,408,802 152,842 2,607 Water Hydro
3 Big Fork (Licensed Project No. 2652)1910 4.15 6.0 26,340,000 13,945,337 3,360,322 559,119 34,598 Water Hydro
4 Eagle Point 1957 2.81 3.0 13,590,000 3,885,302 1,382,670 339,049 153,024 Water Hydro
5 (a)East Side (Licensed Project No. 2082)1924 3.20 0.0 1,736,685 542,714 36,188 2,036 Water Hydro
6 Fall Creek (Licensed Project No. 2082)1903 2.20 2.0 6,024,000 3,110,884 1,414,038 194,192 71,080 Water Hydro
7 Granite 1896 2.00 1.2 3,460,482 5,419,448 2,709,724 246,154 23,690 Water Hydro
8 Gunlock 1917 0.75 0.4 682,817 690,253 920,337 80,216 18,612 Water Hydro
9 Last Chance 1983 1.73 1.3 3,466,952 3,225,846 1,864,651 138,252 17,533 Water Hydro
10 Paris (Licensed Project No. 703)1910 0.72 0.5 944,321 766,477 1,064,551 47,204 27,228 Water Hydro
11 Pioneer (Licensed Project No. 2722)1897 5.00 2.6 7,638,135 12,757,695 2,551,539 537,364 153,371 Water Hydro
12 Prospect No. 1 (Licensed Project No. 2630)1912 3.76 5.0 219,000 5,566,212 1,480,376 153,990 66,793 Water Hydro
13 Prospect No. 3 (Licensed Project No. 2337)1932 7.20 0.0 (175,000)10,160,489 1,411,179 360,575 119,004 Water Hydro
14 Prospect No. 4 (Licensed Project No. 2630)1944 1.00 1.0 (16,000)2,553,835 2,553,835 41,347 18,890 Water Hydro
15 Sand Cove 1926 0.80 0.4 590,447 1,176,961 1,471,201 93,605 34,367 Water Hydro
16 Stairs (Licensed Project No. 597)1895 1.00 1.3 3,424,362 2,494,437 2,494,437 232,871 6,441 Water Hydro
17 Veyo 1920 0.50 0.0 940,897 1,881,794 74,883 59,076 Water Hydro
18 Viva Naughton 1986 0.74 0.1 422,459 1,232,115 1,665,020 127,016 22,428 Water Hydro
19 Wallowa Falls (Licensed Project No. 308)1921 1.10 2.0 1,687,000 5,824,445 5,294,950 280,220 824 Water Hydro
20 Weber (Licensed Project No. 1744)1911 3.85 3.0 8,847,107 4,051,414 1,052,315 248,463 27,267 Water Hydro
21 (b)West Side (Licensed Project No. 2082)1908 0.60 0.0 (51,000)577,606 962,677 58,804 8,921 Water Hydro
22 (c)Keno Regulating Dam (Licensed Project No. 2082)7,942,847 18,526 5,128 Hydro
23 (d)Upper Klamath Lake (Licensed Project No. 2082)3,754,436 93,618 (7,380,545)Hydro
24 (e)North Umpqua (Licensed Project No. 1927)20,272,731 Hydro
25 (f)(g)Lifton Pumping Plant 1917 21,842,608 (7,800,931)411,938 59,294 Water Hydro
26 Cedar Springs II 2020 198.88 244.0 603,521,000 255,260,552 1,283,490 1,908,006 3,261,102 Wind (j)Wind
27 Dunlap Ranch 1 2010 136.90 111.0 469,881,000 218,620,374 1,596,935 323,526 1,456,949 Wind Wind
28 Ekola Flats 2020 250.90 180.0 805,728,000 318,675,352 1,270,129 1,379,525 1,623,288 Wind Wind
29 Foote Creek 1999 48.00 42.0 208,749,000 82,076,123 1,709,919 604,094 226,465 Wind Wind
30 Glenrock 2008 119.30 107.0 328,535,000 192,871,655 1,616,695 1,618,266 1,379,452 Wind Wind
31 Glenrock III 2009 46.00 44.0 123,123,000 81,543,756 1,772,690 129,388 539,919 Wind Wind
32 Goodnoe Hills 2008 103.40 95.0 265,804,000 155,294,975 1,501,886 1,565,267 93,751 Wind Wind
33 High Plains 2009 122.10 104.0 383,965,000 189,956,098 1,555,742 1,401,760 1,418,770 Wind Wind
34 Leaning Juniper 1 2006 110.38 100.0 253,408,000 177,667,194 1,609,596 1,914,967 111,507 Wind Wind
35 Marengo 2007 156.00 151.0 391,503,000 213,243,765 1,366,947 1,589,084 1,579,118 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 AssetRetire.Costs) PerMW
OperationExc'l.Fuel
FuelProductionExpenses
MaintenanceProductionExpenses
KindofFuel
Fuel
Costs
(incents(perMillionBtu)
Generation
Type
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36 Marengo II 2008 78.00 77.0 196,630,000 110,656,369 1,418,671 699,079 789,559 Wind Wind
37 McFadden Ridge I 2009 35.15 33.0 115,716,000 52,741,429 1,500,467 402,708 408,434 Wind Wind
38 Pryor Mountain 2020 239.80 177.0 814,117,000 396,640,581 1,654,047 1,172,745 2,641,263 Wind Wind
39 Rolling Hills 2009 115.80 107.0 286,356,000 197,102,215 1,702,092 101,612 59,813 Wind Wind
40 Seven Mile Hill 2008 122.10 109.0 413,081,000 188,372,345 1,542,771 525,490 189,029 Wind Wind
41 Seven Mile Hill II 2008 24.05 23.0 86,843,000 38,512,786 1,601,363 103,845 37,233 Wind Wind
42 TB Flats 2020 503.20 461.0 1,488,986,000 594,641,713 1,181,720 2,964,822 2,438,291 Wind Wind
43 (h)Black Cap 2012 2.00 2.0 3,933,895 540,941 270,471 Solar Solar
FERC FORM NO. 1 (REV. 12-03)Page 410-411
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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).
(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 (4,056,000)
(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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 requirements or used for the provision of ancillary services.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 of the power was determined. In columns (n) and (o), report 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 and conversion equipment, lines and equipment whose primary purpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project includedin the property accounts listed.
Line
No.
Name of the Energy Storage Project
(a)
FunctionalClassification(b)
Location of theProject(c)
MWHs
(d)
MWHs delivered to the grid tosupport Production(e)
MWHs delivered to the grid tosupport Transmission(f)
MWHs delivered to
the grid to support
Distribution(g)
MWHs LostDuringConversion,
Storage and
Dischargeof EnergyProduction(h)
MWHs LostDuringConversion,
Storage and
Discharge ofEnergyTransmission(i)
MWHs LostDuringConversion,
Storage and
Dischargeof EnergyDistribution(j)
MWHsSold(k)
Revenuesfrom
Energy
StorageOperations(l)
PowerPurchasedfor
Storage
Operations(555.1)(Dollars)(m)
Fuel Costsfrom
associated
fuelaccountsfor StorageOperationsAssociated
with Self-
GeneratedPower(Dollars)(n)
OtherCostsAssociated
with Self-
GeneratedPower(Dollars)(o)
ProjectCostsincludedin
(p)
Production(Dollars)(q)
Transmission(Dollars)(r)
Distribution(Dollars)(s)
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
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34
FERC FORM NO. 1 ((NEW 12-12))Page 414
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 group totals only for each 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 one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not bedistinguished from the remainder of the line.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 pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancyand state whether expenses with respect to such structures are included in 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 two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g).
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 year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinctstatement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company.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 DEPRECIATION AND TAXES
LineNo.
(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)(l)(m)(n)(o)(p)
1 (a)See footnote
2 AEOLUS, WY ANTICLINE, WY 500.00 500.00 Steel Tower 138.00 1 3-1272ACSR 45/7
3 (b)ALVEY, OR DIXONVILLE 500KV, OR 500.00 500.00 Steel Tower 58.00 1 1272ACSR54/19
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 ACSR26/7
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 ACSR26/7
8 (g)COLSTRIP 4, MT COLSTRIP, MT 500.00 500.00 Steel Tower 0.00 1 795 ACSR26/7
9 CAPTAIN JACK, OR MALIN, OR 500.00 500.00 Steel Tower 7.00 1 3-1272
ACSR 36/1
10 (h)DIXONVILLE 500kV, OR MERIDIAN, OR 500.00 500.00 Steel Tower 74.00 1 3-1272ACSR 36/1
11 (i)HEMINGWAY, ID SUMMER LAKE, OR 500.00 500.00 Steel Tower 242.00 1 3-1272ACSR 36/1
12 KLAMATH CO-GEN, OR SNOW GOOSE, OR 500.00 500.00 Steel Tower 2.00 1
3-1272
ACSR54/19
13 MALIN, OR INDIAN SPRINGS, CA 500.00 500.00 Steel Tower 47.00 1 3-1852ACSR51/27
14 MERIDIAN, OR KLAMATH CO-GEN, OR 500.00 500.00 Steel Tower 58.00 1
3-1272
ACSR54/19
15 (j)MIDPOINT, ID HEMINGWAY, ID 500.00 500.00 Steel Tower 130.00 1 3-1272ACSR 36/1
16 SNOW GOOSE, OR CAPTAIN JACK, OR 500.00 500.00 Steel Tower 24.00 1
3-1272
ACSR
54/19
17 SUMMER LAKE, OR MALIN, OR 500.00 500.00 Steel Tower 75.00 1 3-1272ACSR 36/1
18 500kV Costs and Expenses 31,912,816 556,357,970 588,270,786 36,734 2,375,212 758,490 3,170,436
19 90TH SOUTH, UT CAMP WILLIAMS #3, UT 345.00 345.00 Steel - SP 11 0 1
1557.4
ACSR/TW36/7
20 90TH SOUTH, UT CAMP WILLIAMS #4, UT 345.00 345.00 Steel - SP 0.00 11 1 1557.4ACSR/TW36/7
21 90TH SOUTH, UT CAMP WILLIAMS #1, UT 345.00 345.00 Steel - SP 11.00 0 1 1272
ACSR 45/7
From To Operating Designated Type of SupportingStructure On Structure of LineDesignated
OnStructuresofAnother
Line
NumberofCircuits
Size of
ConductorandMaterial
Land ConstructionCosts Total Costs OperationExpenses MaintenanceExpenses Rents TotalExpenses
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22 90TH SOUTH, UT TERMINAL, UT 345.00 345.00 Steel - SP 0.00 16 1 1272ACSR 45/7
23 ANTICLINE, WY JIM BRIDGER, WY 345.00 345.00 Steel - H 5.00 0 1 3-1272ACSR 45/7
24 BEN LOMOND, UT POPULUS #1, ID 345.00 345.00 Steel - SP 0.00 82 1 1272
ACSR 45/7
25 BEN LOMOND, UT POPULUS #2, ID 345.00 345.00 Steel - SP 86.00 0 1 1272ACSR 45/7
26 BEN LOMOND, UT CAMP WILLIAMS, UT 345.00 345.00 Steel - SP 69.00 0 1 1272ACSR 45/7
27 BEN LOMOND, UT TERMINAL #2, UT 345.00 345.00 Steel - SP 47.00 0 1 1272
ACSR 45/7
28 BEN LOMOND, UT TERMINAL #1, UT 345.00 345.00 Steel - SP 0.00 47 1 1272ACSR 45/7
29 (k)BORAH, ID MIDPOINT #1, ID 345.00 345.00 Wood - H 83.00 0 1 1272
ACSR 45/7
30 (l)BORAH, ID MIDPOINT #2, ID 345.00 345.00 Wood - H 78.00 0 1 1272ACSR 45/7
31 CAMP WILLIAMS, UT MONA #3, UT 345.00 345.00 Wood - H 47.00 0 1 954 ACSR45/7
32 CAMP WILLIAMS, UT MONA #1, UT 345.00 345.00 Wood - H 47.00 0 1 1272
ACSR 45/7
33 CAMP WILLIAMS, UT MONA #2, UT 345.00 345.00 Steel Tower 48.00 0 1 954 ACSR45/7
34 CAMP WILLIAMS, UT MONA #4 UT 345.00 345.00 Steel Tower 5.00 43 1 954 ACSR45/7
35 CLOVER, UT OQUIRRH, UT 345.00 345.00 Steel Tower 100.00 0 1 1949
ACSR 45/7
36 CURRANT CREEK, UT MONA, UT 345.00 345.00 Steel - SP 1.00 0 1 954 ACSR54/7
37 EMERY, UT CAMP WILLIAMS, UT 345.00 345.00 Steel Tower 121.00 0 1 1272ACSR 45/7
38 EMERY, UT HUNTINGTON, UT 345.00 345.00 Wood - H 20.00 0 1 954 ACSR
45/7
39 EMERY, UT SIGURD #1, UT 345.00 345.00 Steel - H 74.00 0 1 954 ACSR45/7
40 EMERY, UT SIGURD #2, UT 345.00 345.00 Steel - H 75.00 0 1 954 ACSR54/7
41 FOUR CORNERS, NM PINTO, UT 345.00 345.00 Wood - H 101.00 0 1 795 ACSR
45/7
42 (m)GOSHEN, ID KINPORT, ID 345.00 345.00 Wood - H 41.00 0 1 795 ACSR26/7
43 HUNTINGTON, UT HUNT PLANT 1, UT 345.00 345.00 Steel Tower 1.00 0 1
2156
ACSR
8419
44 HUNTINGTON, UT HUNT PLANT 2, UT 345.00 345.00 Steel Tower 1.00 0 1 2156ACSR8419
45 HUNTINGTON, UT PINTO, UT 345.00 345.00 Steel - SP 159.00 0 1 795 ACSR
45/7
46 HUNTINGTON, UT SPANISH FORK, UT 345.00 345.00 Steel Tower 78.00 0 1 1272ACSR 45/7
47 (n)JIM BRIDGER, WY GOSHEN, ID 345.00 345.00 Steel Tower 226.00 0 1 1272ACSR 36/1
48 (o)JIM BRIDGER, WY BORAH, ID 345.00 345.00 Steel Tower 241.00 0 1 1272
ACSR 36/1
49 (p)JIM BRIDGER, WY KINPORT, ID 345.00 345.00 Steel - SP 235.00 0 1 1272ACSR 36/1
50 (q)KINPORT, ID MIDPOINT, ID 345.00 345.00 Steel - SP 113.00 0 1 1272ACSR 45/7
51 MONA, UT SIGURD #1, UT 345.00 345.00 Wood - H 69.00 0 1 795 ACSR
45/7
52 MONA, UT SIGURD #2, UT 345.00 345.00 Steel - SP 0.00 69 1 954 ACSR45/7
53 MONA, UT HUNTINGTON, UT 345.00 345.00 Steel - SP 60.00 0 1 954 ACSR54/7
54 RED BUTTE, UT SIGURD, UT 345.00 345.00 Steel - H 171.00 0 1 2-954
ACSR 45/7
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55 SIGURD, UT UT-NV STATE LINE 345.00 345.00 Steel Tower 190.00 0 1 954 ACSR54/7
56 SPANISH FORK, UT CAMP WILLIAMS, UT 345.00 345.00 Steel - SP 0.00 35 1 1272ACSR 45/7
57 TERMINAL, UT BORAH, ID 345.00 345.00 Wood - H 138.00 0 1 2-954
ACSR 45/7
58 TERMINAL, UT BORAH, ID 345.00 345.00 Steel - SP 0.00 47 1 2-1272ACSR 45/7
59 TERMINAL, UT CAMP WILLIAMS #2, UT 345.00 345.00 Steel - SP 16.00 10 1 1272ACSR 45/7
60 TERMINAL, UT CAMP WILLIAMS, UT 345.00 345.00 Steel Tower 0.00 23 1 1272
ACSR 45/7
61 345 kV Costs and Expenses 162,114,348 1,693,169,410 1,855,283,758 132,921 1,536,671 648,746 2,318,338
62 AEOLUS, WY EKOLA FLATS, WY 230.00 230.00 Steel - H 1.00 0 1 795 ACSR26/7
63 AEOLUS, WY FREEZEOUT, WY 230.00 230.00 Steel - H 4.00 0 1 1272
ACSR 45/7
64 AEOLUS, WY SHIRLEY BASIN #1, WY 230.00 230.00 Steel - H 16.00 0 1 1158.4ACSS 25/7
65 AEOLUS, WY SHIRLEY BASIN #2, WY 230.00 230.00 Steel - H 16.00 0 1 1158.4ACSS 25/7
66 ALVEY, OR DIXONVILLE, OR 230.00 230.00 Wood - H 59.00 0 1 1272
ACSR 36/1
67 ANTELOPE, ID ANACONDA, MT 230.00 230.00 Wood - H 76.00 0 1 1272ACSR 45/7
68 ANTELOPE, ID LOST RIVER, ID 230.00 230.00 Wood - H 20.00 0 1 795 ACSR
45/7
69 ARROWHEAD, WY FIREHOLE, WY 230.00 230.00 Wood - H 9.00 0 1 795 ACSR26/7
70 ATLANTIC CITY, WY COLUMBIA GENEVA, WY 230.00 230.00 Wood - H 1.00 0 1 1272ACSR 36/1
71 BEN LOMOND, UT NAUGHTON #1, WY 230.00 230.00 Wood - H 88.00 0 1 795 ACSR
26/7
72 BEN LOMOND, UT NAUGHTON #2, WY 230.00 230.00 Wood - H 88.00 0 1 795 ACSR26/7
73 BIRCH CREEK, UT RAILROAD, WY 230.00 230.00 Wood - H 19.00 0 1 954 ACSR54/7
74 BITTER CREEK, WY MONELL, WY 230.00 230.00 Wood - H 3.00 0 1 795 ACSR
26/7
75 BRIDGER PUMP, WY MANS FACE, WY 230.00 230.00 Wood - H 1.00 0 1 1272ACSR 36/1
76 BUFFALO, WY CASPER, WY 230.00 230.00 Wood - H 107.00 0 1 1272ACSR 36/1
77 (r)CASPER, WY DAVE JOHNSTON, WY 230.00 230.00 Wood - H 36.00 0 1
1557.4
ACSR/TW45/7
78 CASPER, WY RIVERTON, WY 230.00 230.00 Wood - H 110.00 0 1 1272ACSR 36/1
79 CHAPPEL CREEK, WY CRAVEN CREEK, WY 230.00 230.00 Steel - SP 30.00 0 1 954 ACSR
54/7
80 CHAPPEL CREEK, WY JONAH GAS, WY 230.00 230.00 Wood - H 32.00 0 1 1272ACSR 45/7
81 CHAPPEL CREEK, WY RILEY RIDGE, WY 230.00 230.00 Wood - H 29.00 6 1 1272ACSR 45/7
82 CORRAL, OR OCHOCO #1, OR 230.00 230.00 Wood - H 9.00 0 1
1557.4
ACSR/TW36/7
83 CORRAL, OR OCHOCO #2, OR 230.00 230.00 Wood - H 10.00 0 1 1557.4ACSR/TW36/7
84 CRAVEN CREEK, WY PIONEER, WY 230.00 230.00 Wood - H 2.00 0 1 1272
ACSR 45/7
85 DAVE JOHNSTON, WY SPENCE, WY 230.00 230.00 Wood - H 31.00 0 1 1272ACSR 45/7
86 DAVE JOHNSTON, WY WYODAK, WY 230.00 230.00 Wood - H 69.00 0 1 1272ACSR 36/1
87 DIXONVILLE 500kV, OR DIXONVILLE 230kV, OR 230.00 230.00 Wood - H 1.00 0 1 1272
ACSR 36/1
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88 DIXONVILLE, OR RESTON (BPA), OR 230.00 230.00 Wood - H 17.00 0 1 795 ACSR26/7
89 FAIRVIEW (BPA), OR ISTHMUS, OR 230.00 230.00 Wood - H 12.00 0 1 1272ACSR 36/1
90 FIREHOLE, WY MONUMENT, WY 230.00 230.00 Wood - H 49.00 0 1 1272
ACSR 45/7
91 FRIEND, OR OCHOCO #1, OR 230.00 230.00 Steel - SP 1.00 0 2 1557.4ACSR/TW36/7
92 FRIEND, OR OCHOCO #2, OR 230.00 230.00 Steel - SP 0.00 1 2
1557.4
ACSR/TW
36/7
93 FRY, OR BETHEL, OR 230.00 230.00 Wood - H 26.00 0 1 1272ACSR 36/1
94 FRY, OR ALVEY, OR 230.00 230.00 Wood - H 45.00 0 1 1272ACSR 36/1
95 GLEN CANYON, AZ SIGURD, UT 230.00 230.00 Wood - H 159.00 0 1 954 ACSR45/7
96 GONDER, UT - NV STATE LINE PAVANT, UT 230.00 230.00 Wood - H 98.00 0 1 795 ACSR45/7
97 DIXONVILLE, OR GRANTS PASS, OR 230.00 230.00 Wood - H 62.00 0 1 1272
ACSR 36/1
98 HIGH PLAINS, WY STANDPIPE, WY 230.00 230.00 Wood - H 39.00 0 1 1272ACSR 45/7
99 (s)HURRICANE, OR WALLA WALLA, WA 230.00 230.00 Wood - H 78.00 0 1 1272ACSR 36/1
100 JIM BRIDGER, WY ROCK SPRINGS, WY 230.00 230.00 Wood - H 35.00 0 1 1272
ACSR 45/7
101 JIM BRIDGER, WY SPENCE, WY 230.00 230.00 Wood - H 149.00 0 1 1272ACSR 36/1
102 KLAMATH FALLS, OR MALIN, OR 230.00 230.00 Wood - H 35.00 0 1 1272ACSR 36/1
103 KLAMATH FALLS, OR SNOW GOOSE, OR 230.00 230.00 Steel Tower 4.00 0 1
1511
ACCC36/1
104 LIMA, WY ROBERSON, WY 230.00 230.00 Wood - H 2.00 0 1 1272ACSR 45/7
105 LONE PINE, OR KLAMATH FALLS, OR 230.00 230.00 Wood - H 76.00 0 1 795 ACSR
26/7
106 LONE PINE, OR MERIDIAN #1, OR 230.00 230.00 Steel - SP 5.00 0 1 1272ACSR54/19
107 LONE PINE, OR MERIDIAN #2, OR 230.00 230.00 Steel - SP 5.00 0 1 1272ACSR 36/1
108 MCNARY (BPA), OR WALLA WALLA, WA 230.00 230.00 Wood - H 56.00 0 1 1272
ACSR 36/1
109 MCNARY (BPA), OR WALLULA, WA 230.00 230.00 Wood - H 29.00 0 1 1158.4ACSS/TW25/7
110 MERIDIAN, OR GRANTS PASS, OR 230.00 230.00 Wood - H 35.00 0 1 1272
ACSR 36/1
111 MONUMENT, WY EXXON, WY 230.00 230.00 Wood - H 13.00 0 1 1272ACSR 36/1
112 MONUMENT, WY CRAVEN CREEK, WY 230.00 230.00 Wood - H 20.00 0 1 1272ACSR 45/7
113 NAUGHTON, WY TREASURETON, ID 230.00 230.00 Wood - H 80.00 0 1 1272
ACSR 45/7
114 NAUGHTON, WY MONUMENT, WY 230.00 230.00 Wood - H 30.00 0 1 1272ACSR 36/1
115 NAUGHTON, WY CRAVEN CREEK, WY 230.00 230.00 Wood - H 16.00 0 1 954 ACSR
54/7
116 PALISADES SS, WY BLUE RIM, WY 230.00 230.00 Wood - H 4.00 0 1 1272ACSR 36/1
117 PAROWAN VALLEY, UT SIGURD, UT 230.00 230.00 Wood - H 94.00 0 1 795 ACSR45/7
118 PAROWAN VALLEY, UT WEST CEDAR, UT 230.00 230.00 Wood - H 26.00 0 1 795 ACSR
45/7
119 PAVANT, UT SIGURD, UT 230.00 230.00 Wood - H 43.00 0 1 795 ACSR45/7
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120 POINT OF ROCKS, WY DAVE JOHNSTON, WY 230.00 230.00 Wood - H 210.00 0 1 1272ACSR 36/1
121 POMONA, WA VANTAGE, WA 230.00 230.00 Wood - H 40.00 0 1 1272ACSR 45/7
122 PONDEROSA (BPA), OR CORRAL, OR 230.00 230.00 Steel Tower 1.00 1 1 1272
ACSR 45/7
123 POMONA, WA UNION GAP, WA 230.00 230.00 Wood - H 7.00 0 1 1272ACSR 36/1
124 RIVERTON, WY ROCK SPRINGS, WY 230.00 230.00 Wood - H 118.00 0 1 1272ACSR 36/1
125 RIVERTON, WY THERMOPOLIS, WY 230.00 230.00 Wood - H 51.00 0 1 1272
ACSR 36/1
126 ROCK SPRINGS, WY FLAMING GORGE, UT 230.00 230.00 Wood - H 55.00 0 1 1272ACSR 36/1
127 ROCK SPRINGS, WY JIM BRIDGER, WY 230.00 230.00 Wood - H 35.00 0 1 1272
ACSR 36/1
128 ROCK SPRINGS, WY MONUMENT, WY 230.00 230.00 Wood - H 41.00 0 1 1272ACSR 36/1
129 SHERIDAN (MDU), WY BUFFALO, WY 230.00 230.00 Wood - H 40.00 0 1 795 ACSR26/7
130 SHERIDAN (MDU), WY YELLOWTAIL, MT 230.00 230.00 Wood - H 62.00 0 1 795 ACSR
26/7
131 SHIRLEY BASIN, WY DUNLAP RANCH, WY 230.00 230.00 Wood - H 12.00 0 1 795 ACSR26/7
132 SWIFT No. 1, WA SWIFT No. 2, WA 230.00 230.00 Wood - H 2.00 0 1 954 ACSR45/7
133 SWIFT No. 2, WA WOODLAND (BPA) SS, WA 230.00 230.00 Wood - H 23.00 0 1 954 ACSR
45/7
134 TALBOT, WA MARENGO II, WA 230.00 230.00 Wood - H 7.00 0 1 795 ACSR26/7
135 TAP TO HANNA, OR NICKEL MOUNTAIN, OR 230.00 230.00 Wood - H 9.00 0 1 795 ACSR26/7
136 THERMOPOLIS, WY YELLOWTAIL, MT 230.00 230.00 Wood - H 176.00 0 1 1272
ACSR 36/1
137 TREASURETON, ID BRADY, ID 230.00 230.00 Wood - H 66.00 0 1 795 ACSR26/7
138 TROUTDALE (BPA), OR GRESHAM (PGE), OR 230.00 230.00 Steel Tower 6.00 0 1 954 ACSR45/7
139 TROUTDALE (BPA), OR LINNEMAN (PGE), OR 230.00 230.00 Steel Tower 0.00 6 1 900 ACSR
54/7
140 UNION GAP, WA MIDWAY (BPA), WA 230.00 230.00 Wood - H 39.00 0 1 954 ACSR45/7
141 WALLA WALLA, WA LEWISTON (AVISTA), ID 230.00 230.00 Wood - H 45.00 0 1 1272
ACSR 36/1
142 WALLA WALLA, WA WANAPUM (GPUD), WA 230.00 230.00 Wood - H 33.00 0 1 1272ACSR 36/1
143 WANAPUM (GPUD), WA POMONA, WA 230.00 230.00 Wood - H 37.00 0 1 1272ACSR 36/1
144 WINDSTAR, WY GLENROCK, WY 230.00 230.00 Wood - H 13.00 0 1 1272
ACSR 45/7
145 WYODAK, WY BUFFALO, WY 230.00 230.00 Wood - H 69.00 0 1 1272ACSR 36/1
146 YAMSAY (BPA), OR KLAMATH FALLS, OR 230.00 230.00 Wood - H 63.00 0 1 795 ACSR26/7
147 230kV Costs and Expenses 40,083,473 626,702,572 666,786,045 219,801 2,950,647 364,384 3,534,832
148 (t)ANTELOPE, ID GOSHEN, ID 161.00 161.00 Wood - H 45.00 0 1 397.5ACSR 26/7
149 (u)BIG GRASSY, ID JEFFERSON, ID 161.00 161.00 Wood - H 0.00 21 1 250HH CU/7
150 BONNEVILLE, ID EAGLEROCK, ID 161.00 161.00 Wood - SP 9.00 0 1 954 ACSR
45/7
151 EAGLEROCK, ID GOSHEN, ID 161.00 161.00 Wood - H 15.00 0 1 1272ACSR 45/7
152 GOSHEN, ID GRACE, ID 161.00 161.00 Wood - H 57.00 0 1 250HH CU/7
153 (v)GOSHEN, ID JEFFERSON, ID 161.00 161.00 Wood - H 0.00 29 1 250HH CU
/7
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154 GOSHEN, ID RIGBY, ID 161.00 161.00 Wood - H 31.00 0 1 397.5ACSR 26/7
155 GOSHEN, ID SUGARMILL, ID 161.00 161.00 Wood - SP 17.00 0 1 795 AAC/37
156 GOSHEN, ID SUGARMILL, ID 161.00 161.00 Wood - SP 26.00 0 1
1557.4
ACSR/TW36/7
157 RIGBY, ID REXBURG, ID 161.00 161.00 Wood - SP 12.00 0 1 1272ACSR
158 RIGBY, ID JEFFERSON, ID 161.00 161.00 Wood - SP 18.00 0 1 397.5
ACSR 26/7
159 RIGBY, ID SUGARMILL, ID 161.00 161.00 Wood - SP 21.00 0 1 1557.4ACSR/TW
160 SUGARMILL, ID RIGBY, ID 161.00 161.00 Wood - SP 17.00 0 1 397.5ACSR 26/7
161 TAP TO PAYNE, ID PAYNE, ID 161.00 161.00 Wood - SP 3.00 0 1 1557.4
ACSR/TW
162 YELLOWTAIL, MT RIMROCK, MT 161.00 161.00 Wood - H 46.00 0 1 556.5ACSR 26/7
163 161 kV Costs and Expenses 5,226,750 86,643,348 91,870,098 3,598 146,723 17,214 167,535
164 90TH SOUTH, UT DUMAS #1, UT 138.00 138.00 Wood - H 6.00 0 1 795 AAC
/37
165 90TH SOUTH, UT DUMAS #2, UT 138.00 138.00 Wood - H 6.00 0 1 795 AAC/37
166 90TH SOUTH, UT OQUIRRH, UT 138.00 138.00 Wood - SP 13.00 0 1 795 ACSR26/7
167 90TH SOUTH, UT SANDY, UT 138.00 138.00 Steel - SP 1.00 0 1 795 AAC
/37
168 ABAJO, UT PINTO, UT 138.00 138.00 Wood - H 44.00 0 1 397.5ACSR 26/7
169 ABAJO, UT SAN JUAN, UT 138.00 138.00 Wood - SP 10.00 0 1 795 ACSR26/7
170 AGRIUM, UT THREEMILE KNOLL, ID 138.00 138.00 Wood - H 4.00 0 1 397.5
ACSR 26/7
171 ANSCHTZ CO-GEN, WY EVANSTON, WY 138.00 138.00 Wood - H 21.00 0 1 795 ACSR26/7
172 (w)ANTELOPE, ID SCOVILLE #1, ID 138.00 138.00 Wood - H 1.00 0 1 397.5ACSR 26/7
173 (x)ANTELOPE, ID SCOVILLE #2, ID 138.00 138.00 Wood - H 1.00 0 1 397.5
ACSR 26/7
174 ASHGROVE, UT CLOVER, UT 138.00 138.00 Wood - H 26.00 0 1 397.5ACSR 26/7
175 ASHLEY, UT CARBON, UT 138.00 138.00 Wood - H 101.00 0 1 397.5
ACSR 26/7
176 ASHLEY, UT VERNAL, UT 138.00 138.00 Wood - H 12.00 0 1 397.5ACSR 26/7
177 BANGERTER, UT OQUIRRH, UT 138.00 138.00 Wood - H 0.00 6 1 1557.4ACSR/TW36/7
178 BARNEYS, UT GRINDING, UT 138.00 138.00 Wood - SP 1.00 0 1
1557.4
ACSR/TW36/7
179 BDO, UT BDO TAP, UT 138.00 138.00 Wood - SP 1.00 0 1 397.5ACSR 26/7
180 BEN LOMOND, UT ANGEL, UT 138.00 138.00 Steel - SP 24.00 0 1 397.5
ACSR 26/7
181 BEN LOMOND, UT BRIGHAM CITY, UT 138.00 138.00 Wood - H 14.00 0 1 1272ACSR 45/7
182 BEN LOMOND #1, UT EL MONTE, UT 138.00 138.00 Steel - SP 14.00 0 1 795 ACSR45/7
183 BEN LOMOND #2, UT EL MONTE, UT 138.00 138.00 Wood - H 0.00 13 1 795 ACSR
45/7
184 BEN LOMOND, UT HONEYVILLE, UT 138.00 138.00 Steel Tower 22.00 0 1 250 CUHD/12
185 BEN LOMOND, UT SYRACUSE #1, UT 138.00 230.00 Steel Tower 7.00 13 1 795 AAC/37
186 BEN LOMOND, UT SYRACUSE, UT 138.00 138.00 Steel Tower 58.00 0 1 1272
ACSR 45/7
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187 BEN LOMOND, UT W ZIRCONIUM, UT 138.00 138.00 Wood - SP 14.00 0 1 795 AAC/37
188 BEN LOMOND, UT WHEELON, UT 138.00 138.00 Steel Tower 42.00 0 1 250 CUHD/12
189 BONANZA, UT CHAPITA, UT 138.00 138.00 Wood - H 9.00 0 1 795 ACSR
26/7
190 BRIDGERLAND, UT GREEN CANYON, UT 138.00 138.00 Wood - SP 16.00 0 1 1272ACSR 45/7
191 BRIGHAM CITY, UT WHEELON, UT 138.00 138.00 Wood - H 24.00 0 1 795 ACSR26/7
192 BUTLERVILLE, UT 90TH SOUTH, UT 138.00 138.00 Steel - SP 9.00 0 1 795 AAC
/37
193 CAMERON, UT MILFORD, UT 138.00 138.00 Wood - SP 25.00 0 1 397.5ACSR 26/7
194 CAMERON, UT PAROWAN, UT 138.00 138.00 Wood - H 35.00 0 1 397.5
ACSR 26/7
195 CAMERON, UT SIGURD, UT 138.00 138.00 Wood - H 63.00 0 1 397.5ACSR 26/7
196 CANYON COMP, WY STR 204, WY 138.00 138.00 Wood - H 12.00 0 1 795 ACSR26/7
197 CARBON, UT HELPER #2, UT 138.00 138.00 Wood - H 2.00 0 1 556.5
ACSR 26/7
198 CARBON, UT MOAB, UT 138.00 138.00 Wood - H 120.00 0 1 954 ACSR54/7
199 CARBON, UT SPANISH FORK #1, UT 138.00 138.00 Steel Tower 54.00 0 1 795 ACSR26/7
200 CARBON, UT SPANISH FORK #2, UT 138.00 138.00 Steel Tower 52.00 0 1 1272
ACSR 45/7
201 (y)CENTRAL (UAMPS) #2, UT SAINT GEORGE, UT 138.00 138.00 Steel - SP 20.00 0 1 1272ACSR 45/7
202 (z)CENTRAL (UAMPS) #3, UT SAINT GEORGE, UT 138.00 138.00 Steel - SP 0.00 20 1 1272ACSR 45/7
203 CLEAR CREEK, WY PAINTER, UT 138.00 138.00 Wood - SP 5.00 0 1 795 ACSR
26/7
204 CLOVER, UT BURRASTON PONDS 138.00 138.00 Wood - SP 2.00 0 1 397.5ACSR 26/7
205 CLOVER, UT NEBO, UT 138.00 138.00 Wood - SP 8.00 0 1 1272ACSR 45/7
206 COLUMBIA, UT SUNNYSIDE, UT 138.00 138.00 Wood - H 2.00 0 1 397.5
ACSR 26/7
207 COTTONWOOD, UT HAMMER, UT 138.00 138.00 Wood - SP 5.00 0 1 795 AAC/37
208 COTTONWOOD, UT MCCLELLAND, UT 138.00 138.00 Steel - SP 6.00 0 1 795 AAC
/37
209 COTTONWOOD, UT SILVER CREEK, UT 138.00 138.00 Wood - SP 30.00 0 1 397.5ACSR 26/7
210 CUTLER, UT WHEELON, UT 138.00 138.00 Wood - SP 1.00 0 1 250 CUHD/12
211 DANIEL, UT MIDWAY, UT 138.00 138.00 Wood - SP 4.00 0 1 1272
ACSR 45/7
212 DRY CREEK, UT SPANISH FORK, UT 138.00 138.00 Steel - SP 5.00 0 1 1272ACSR 45/7
213 DUMAS, UT WESTFIELD, UT 138.00 138.00 Wood - SP 19.00 0 1 795 ACSR26/7
214 DYNAMO, UT TRI-CITY #1, UT 138.00 138.00 Steel - SP 2.00 0 1 795 ACSR
26/7
215 DYNAMO, UT TRI-CITY #2, UT 138.00 138.00 Steel - SP 0.00 3 1 795 ACSR26/7
216 EAGLE MOUNTAIN, UT PONY EXPRESS, UT 138.00 138.00 Wood - SP 10.00 0 1 795 ACSR26/7
217 EAST LAYTON, UT 105 TAP, UT 138.00 138.00 Steel - SP 15.00 0 1 795 ACSR
26/7
218 EBAY TAP, UT OQUIRRH, UT 138.00 138.00 Wood - SP 1.00 0 1 795 ACSR26/7
219 EL MONTE, UT PIONEER, UT 138.00 138.00 Steel - SP 1.00 0 1 1272ACSR 45/7
220 EL MONTE, UT STR30B, UT 138.00 138.00 Steel - SP 9.00 0 1 1272ACSR 45/7
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221 EMERY, UT CLAWSON, UT 138.00 138.00 Wood - SP 0.00 4 2 397.5ACSR 26/7
222 EVANSTON, WY RAILROAD, UT 138.00 138.00 Wood - SP 3.00 0 1 795 ACSR
26/7
223 FORT DOUGLAS, UT MCCLELLAND, UT 138.00 138.00 Wood - SP 3.00 0 1 1557.4ACSR/TW36/7
224 FRANKLIN, ID GREEN CANYON, UT 138.00 138.00 Wood - SP 25.00 0 1 397.5ACSR 26/7
225 FRANKLIN, ID TREASURETON, ID 138.00 138.00 Wood - SP 10.00 0 1 795 ACSR
26/7
226 GADSBY, UT JORDAN, UT 138.00 138.00 Wood - SP 1.00 0 1 1272ACSR 45/7
227 GADSBY, UT TERMINAL, UT 138.00 138.00 Wood - SP 6.00 0 1 1272
ACSR 45/7
228 GADSBY, UT THIRD WEST, UT 138.00 138.00 Wood - SP 1.00 0 1 1557.4ACSR/TW36/7
229 GRAPHITE, UT MOUNTAIN VIEW, UT 138.00 138.00 Wood - SP 1.00 0 1 397.5ACSR 26/7
230 GREEN CANYON, UT NIBLEY, UT 138.00 138.00 Wood - SP 7.00 0 1 1272
ACSR 45/7
231 GREEN CANYON, UT WHEELON, UT 138.00 138.00 Wood - SP 19.00 0 1 397.5ACSR 26/7
232 GRINDING, UT OQUIRRH, UT 138.00 138.00 Wood - SP 3.00 0 1 795 ACSR45/7
233 GRINDING, UT TOOELE, UT 138.00 138.00 Wood - SP 14.00 0 1 795 ACSR45/7
234 HALE, UT MIDWAY, UT 138.00 138.00 Wood - H 19.00 0 1 397.5ACSR 26/7
235 HALE, UT SPANISH FORK, UT 138.00 138.00 Wood - H 18.00 0 1 1272
ACSR 45/7
236 HALE, UT TANNER, UT 138.00 138.00 Wood - H 7.00 0 1 1272ACSR 45/7
237 HAMMER, UT BUTLERVILLE, UT 138.00 138.00 Wood - SP 0.00 2 1 795 ACSR26/7
238 HIGHLAND, UT BULL RIVER (LEHI #5), UT 138.00 138.00 Wood - SP 7.00 0 1 1272
ACSR 45/7
239 HONEYVILLE, UT LAMPO, UT 138.00 138.00 Wood - H 25.00 0 1 397.5ACSR 26/7
240 HONEYVILLE, UT WHEELON, UT 138.00 138.00 Steel Tower 0.00 14 1 250 CUHD/12
241 HUNTINGTON, UT MCFADDEN, UT 138.00 138.00 Wood - H 7.00 0 1 397.5
ACSR 26/7
242 JERUSALEM, UT NEBO, UT 138.00 138.00 Wood - H 26.00 0 1 397.5ACSR 26/7
243 JORDAN, UT MCCLELLAND, UT 138.00 138.00 Wood - SP 5.00 0 1 795 AAC/37
244 JORDAN, UT TERMINAL, UT 138.00 138.00 Wood - SP 6.00 0 1 1272
AAC/91
245 JORDAN, UT THIRD WEST, UT 138.00 138.00 Wood - SP 3.00 0 1 1557.4ACSR/TW36/7
246 KEARNS, UT TAYLORSVILLE, UT 138.00 138.00 Wood - SP 3.00 0 1 795 ACSR
26/7
247 KEARNS, UT WEST VALLEY, UT 138.00 138.00 Wood - SP 2.00 0 1 1557.4ACSR/TW36/7
248 LONE PEAK, UT CAMP WILLIAMS, UT 138.00 138.00 Steel - SP 0.00 8 1 1272
ACSR 45/7
249 MCCLELLAND, UT MIDVALLEY, UT 138.00 138.00 Wood - SP 6.00 0 1 795 ACSR26/7
250 MCFADDEN, UT BLACKHAWK, UT 138.00 138.00 Wood - H 11.00 0 1 795 ACSR26/7
251 MID VALLEY, UT 90TH SOUTH, UT 138.00 138.00 Wood - H 9.00 0 1 1272
ACSR 45/7
252 MID VALLEY #2, UT COTTONWOOD, UT 138.00 138.00 Wood - SP 3.00 0 1 1557.4ACSR/TW36/7
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253 MID VALLEY #1, UT COTTONWOOD, UT 138.00 138.00 Wood - SP 5.00 0 1 1557.4ACSR/TW36/7
254 MID VALLEY, UT TAYLORSVILLE, UT 138.00 138.00 Wood - SP 4.00 2 1
1557.4
ACSR/TW
36/7
255 MIDDLETON, UT ST. GEORGE, UT 138.00 138.00 Wood - H 1.00 0 1 397.5ACSR 26/7
256 MOAB, UT PINTO, UT 138.00 138.00 Wood - H 68.00 0 1 397.5ACSR 26/7
257 NAUGHTON, WY CANYON COMP, WY 138.00 138.00 Wood - H 35.00 0 1 795 ACSR
26/7
258 NAUGHTON, WY PAINTER, WY 138.00 138.00 Wood - H 44.00 0 1 795 ACSR26/7
259 NEBO, UT DRY CREEK, UT 138.00 138.00 Wood - H 33.00 0 1 795 ACSR26/7
260 NUCOR STEEL, UT WHEELON, UT 138.00 138.00 Wood - H 13.00 0 1 397.5ACSR 26/7
261 ONEIDA, ID OVID, UT 138.00 138.00 Wood - H 23.00 0 1 336.4ACSR 26/7
262 ONIEDA, ID GRACE, ID 138.00 138.00 Wood - H 19.00 0 1 250 CUHD
/12
263 OQUIRRH, UT BARNEY, UT 138.00 138.00 Wood - H 5.00 0 1 795 ACSR26/7
264 OQUIRRH, UT BINGHAM CANYON, UT 138.00 138.00 Wood - H 8.00 0 1 1557.4ACSR/TW36/7
265 OQUIRRH, UT TOOELE, UT 138.00 138.00 Steel - SP 44.00 0 1 1272
ACSR 45/7
266 OQUIRRH, UT WILDFLOWER TAP, UT 138.00 138.00 Wood - H 2 1 1557.4ACSR/TW 36/7
267 WILDFLOWER TAP, UT WILDFLOWER, UT 138.00 138.00 Wood - H 1.00 1 397.5
ACSR 26/7
268 PAINTER, UT RAILROAD, UT 138.00 138.00 Wood - H 7.00 0 1 1272ACSR 45/7
269 PARRISH #105, UT TERMINAL, UT 138.00 138.00 Steel - SP 14.00 0 1 795 ACSR45/7
270 PAROWAN, UT WEST CEDAR, UT 138.00 138.00 Wood - H 21.00 0 1 397.5
ACSR 26/7
271 PARRISH, UT TAP TO N. SALT LAKE, UT 138.00 138.00 Steel - SP 0.00 11 1 795 ACSR26/7
272 PARRISH, UT TERMINAL #1, UT 138.00 138.00 Steel - SP 16.00 0 1 795 ACSR45/7
273 PARRISH, UT TERMINAL #2, UT 138.00 138.00 Steel - SP 0.00 14 1 795 ACSR26/7
274 RAILROAD, UT CANYON COMP, WY 138.00 138.00 Wood - H 17.00 0 1 795 ACSR26/7
275 ST. GEORGE, UT PURGATORY FLAT, UT 138.00 138.00 Wood - SP 10.00 0 2 1272
ACSR 45/7
276 RED BUTTE, UT WEST CEDAR, UT 138.00 138.00 Wood - H 47.00 0 1 397.5ACSR 26/7
277 RIVERDALE, UT EAST LAYTON, UT 138.00 138.00 Steel - SP 0.00 6 1 795 ACSR26/7
278 SHICK, UT PARRISH, UT 138.00 138.00 Wood - H 0.00 10 1 250 CUHD
/12
279 SILVER CREEK, UT DANIEL, UT 138.00 138.00 Wood - SP 17.00 0 1 1272ACSR 45/7
280 SILVER CREEK, UT RAILROAD, UT 138.00 138.00 Wood - SP 72.00 0 1 1272ACSR 45/7
281 SPANISH FORK, UT TANNER, UT 138.00 138.00 Wood - H 10.00 0 1 1272
ACSR 45/7
282 SUNRISE, UT OQUIRRH, UT 138.00 138.00 Wood - SP 0.00 2 1 1557.4ACSR/TW36/7
283 SYRACUSE, UT ANGEL #1, UT 138.00 138.00 Wood - SP 0.00 7 1 250 CUHD
/12
284 SYRACUSE, UT CLEARFIELD SOUTH, UT 138.00 138.00 Steel - SP 5.00 0 1 1272ACSR 45/7
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285 SYRACUSE, UT PARRISH, UT 138.00 138.00 Steel Tower 15.00 0 1 1272ACSR 45/7
286 TAP TO ANGEL NORTH, UT TAP TO PARRISH, UT 138.00 138.00 Wood - H 13.00 0 1 795 AAC/37
287 TAYLORSVILLE, UT 90TH SOUTH, UT 138.00 138.00 Wood - SP 6.00 2 1 795 AAC
/37
288 TERMINAL, UT KENNECOTT, UT 138.00 138.00 Steel - SP 16.00 0 1 795 ACSR26/7
289 TERMINAL, UT MIDVALLEY #1, UT 138.00 138.00 Wood - H 7.00 0 1 1272ACSR 45/7
290 TERMINAL, UT MIDVALLEY #2, UT 138.00 138.00 Wood - H 7.00 0 1
1557.4
ACSR/TW36/7
291 TERMINAL, UT ROWLEY, UT 138.00 138.00 Wood - H 53.00 0 1 795 AAC/37
292 TERMINAL, UT TOOELE, UT 138.00 138.00 Wood - H 24.00 6 1 397.5
ACSR 26/7
293 TERMINAL, UT WEST VALLEY, UT 138.00 138.00 Wood - SP 7.00 0 1 1557.4ACSR/TW36/7
294 THREEMILE KNOLL, ID GRACE #1, ID 138.00 138.00 Wood - H 17.00 0 1 250 CUHD
/12
295 THREEMILE KNOLL, ID GRACE #2, ID 138.00 138.00 Wood - H 17.00 0 1 1272ACSR 45/7
296 THREEMILE KNOLL, ID MONSANTO #1, ID 138.00 138.00 Wood - H 2.00 0 1 1557.4ACSR/TW36/7
297 THREEMILE KNOLL, ID MONSANTO #2, ID 138.00 138.00 Steel - SP 2.00 0 1 1272
ACSR 45/7
298 TIMP #1, UT DYNAMO, UT 138.00 138.00 Steel - SP 2.00 0 1 1557.4ACSR/TW36/7
299 TIMP #2, UT DYNAMO, UT 138.00 138.00 Steel - SP 0.00 2 1
1557.4
ACSR/TW36/7
300 TIMP, UT HALE, UT 138.00 138.00 Steel - SP 4.00 0 1 1557.4ACSR/TW36/7
301 TIMP, UT SPANISH FORK, UT 138.00 138.00 Wood - H 23.00 0 1
1557.4
ACSR/TW36/7
302 TIMP, UT VINEYARD, UT 138.00 138.00 Wood - SP 2.00 0 1 1272ACSR 45/7
303 TREASURETON, ID GRACE, ID 138.00 138.00 Steel Tower 25.00 0 1 250 CUHD
/12
304 TREASURETON, ID GRACE #2, ID 138.00 138.00 Steel Tower 0.00 25 1 250 CUHD/12
305 TREASURETON, ID ONEIDA, ID 138.00 138.00 Wood - H 6.00 0 1 250 CUHD/12
306 TRI-CITY, UT OQUIRRH, UT 138.00 138.00 Wood - SP 3.00 19 1
1557.4
ACSR/TW36/7
307 TRI-CITY, UT SUNRISE, ID 138.00 138.00 Wood - SP 19.00 0 1 1557.4ACSR/TW36/7
308 TRI-CITY, UT WESTFIELD, UT 138.00 138.00 Wood - H 15.00 0 1 1272
ACSR 45/7
309 VERNAL (WAPA), UT NAPLES, UT 138.00 138.00 Wood - SP 1.00 0 1 1557.4ACSR/TW36/7
310 WEST CEDAR, UT THREE PEAKS, UT 138.00 138.00 Wood - SP 20.00 0 1 795 ACSR
26/7
311 WEST VALLEY, UT OQUIRRH, UT 138.00 138.00 Wood - H 9.00 0 1 1557.4ACSR/TW36/7
312 WESTFIELD, UT HALE, UT 138.00 138.00 Wood - H 13.00 0 1 795 ACSR
26/7
313 (aa)WHEELON, UT AMERICAN FALLS, ID 138.00 138.00 Wood - H 82.00 0 1 250 CUHD/12
314 WHEELON #1, UT TREASURETON, ID 138.00 138.00 Steel Tower 29.00 0 1 250 CUHD/12
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315 WHEELON #2, UT TREASURETON, ID 138.00 138.00 Steel Tower 0.00 29 1 250 CUHD/12
316 WHEELON #3, UT TREASURETON, ID 138.00 138.00 Wood - H 29.00 0 1 250 CUHD/12
317 138 kV Costs and Expenses 43,250,165 457,641,211 500,891,376 293,164 1,841,819 90,545 2,225,528
318 All 115kV Lines 1,675.00 8,375,318 329,062,879 337,438,197 119,288 3,276,258 385,656 3,781,202
319 All 69kV Lines 2,914.00 9,949,045 390,813,737 400,762,782 117,876 960,062 293,537 1,371,475
320 All 57kV Lines 107.00 141,468 13,509,982 13,651,450 87,721 15,465 4,994 108,180
321 All 46kV Lines 2,531.00 12,681,141 320,031,112 332,712,253 216,587 1,515,717 32,157 1,764,461
36 TOTAL 17,398.00 667.00 315 313,734,524 4,473,932,221 4,787,666,745 1,227,690 14,618,574 2,595,723 18,441,987
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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 Colstrip 4 - Colstrip 500kV line is jointly owned by PacifiCorp, NorthWestern Energy, Puget Sound Energy, Avista Corporation and Portland General Electric Company, in which PacifiCorp owns 6.8% of the line. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp’s share.
(h) 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%.
(i) 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.
(j) 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.
(k) 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.
(l) 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.
(m) 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.
(n) 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.
(o) 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 70.8%29.2%
Populus - Borah #1 70.8%29.2%
Plant cost and operations and maintenance costs reported for this line represents PacifiCorp’s share.
(p) 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 70.8%29.2%
Populus - Kinport 70.8%29.2%
Plant cost and operations and maintenance costs reported for this line represents PacifiCorp’s share.
(q) 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.
(r) 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.
(s) 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.
(t) 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.
(u) 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.
(v) 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.
(w) 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.
(x) 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.
(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 Central #3 - Saint George 138kV line is jointly owned by PacifiCorp and Utah Associated Municipal Power Systems with an undivided interest of 43.26% and 56.74%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp's share.
(aa) 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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), it is 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, and costs of Underground Conduit in column (m).3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic.
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)(q)
1 JORDANELLE, UT MIDWAY, UT 12 Steel/Wood - SP 14 1 1 1272 ACSR 45/7 Vertical 10'138 4,380,420 6,024,064 5,161,392 (a)15,565,876 Overground
44 TOTAL 12 14 1 1 4,380,420 6,024,064 5,161,392 15,565,876
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 andLandRights
Poles,Towers
and
Fixtures
ConductorsandDevices
AssetRetire.Costs Total Construction
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ Q4
FOOTNOTE DATA
(a) 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
LineNo.(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 9 3
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
Name and Location of Substation Transmission or Distribution Attended or Unattended Primary Voltage (In MVa)Secondary Voltage (InMVa)
TertiaryVoltage(In
MVa)
CapacityofSubstation(In
Service)
(In MVa)
Number ofTransformersIn Service
Number ofSpareTransformers
Type ofEquipment Numberof Units
TotalCapacity(In MVa)
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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
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 12.47 500 2
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 44 2
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
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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 12.47 210 3
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
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
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
129 (c)GOSHEN, ID Transmission Unattended 345.00 161.00 13.80 1733 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 69.00 105 2
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134 RIGBY, ID Transmission Unattended 161.00 69.00 13.80 229 4 2
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 COOS RIVER, OR Distribution Unattended 115.00 20.80 20 1
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183 COQUILLE, OR Distribution Unattended 115.00 20.80 40 2
184 CREEK, OR Distribution Unattended 69.00 34.50 5 1
185 CROOKED RIVER RANCH, OR Distribution Unattended 69.00 20.80 25 2
186 CROWFOOT, OR Distribution Unattended 115.00 20.80 20 1
187 CULLY, OR Distribution Unattended 115.00 12.47 25 1
188 CULVER, OR Distribution Unattended 69.00 12.47 7.20 13 1
189 DAIRY, OR Distribution Unattended 69.00 12.47 25 1
190 DALLAS, OR Distribution Unattended 115.00 20.80 50 2
191 DALREED, OR Distribution Unattended 230.00 34.50 13.20 95 4 1
192 DEVILS LAKE, OR Distribution Unattended 115.00 20.80 50 2
193 DIXON, OR Distribution Unattended 115.00 4.16 7.20 7 1
194 DODGE BRIDGE, OR Distribution Unattended 69.00 20.80 25 2
195 DOWELL, OR Distribution Unattended 115.00 12.47 25 1
196 EASY VALLEY, OR Distribution Unattended 115.00 12.47 45 2
197 EMPIRE, OR Distribution Unattended 115.00 20.80 20 1
198 ENTERPRISE, OR Distribution Unattended 69.00 20.80 19 2
199 FERN HILL, OR Distribution Unattended 115.00 12.47 7.20 13 1
200 FIELDER CREEK, OR Distribution Unattended 115.00 20.80 20 1
201 FISH HOLE, OR Distribution Unattended 115.00 69.00 12.47 19 3
202 FOOTHILLS, OR Distribution Unattended 69.00 12.47 21 4
203 FRALEY, OR Distribution Unattended 69.00 12.47 5 3
204 GARDEN VALLEY, OR Distribution Unattended 69.00 20.80 20 1
205 GLENDALE, OR Distribution Unattended 230.00 12.47 25 2
206 GLENEDEN, OR Distribution Unattended 20.80 4.16 6 1
207 GLIDE, OR Distribution Unattended 115.00 12.47 13 1
208 GOLD HILL, OR Distribution Unattended 69.00 12.47 11 3
209 GORDON HOLLOW, OR Distribution Unattended 69.00 20.80 6 1
210 GOSHEN, OR Distribution Unattended 115.00 20.80 20 1
211 GRANT STREET, OR Distribution Unattended 115.00 20.80 45 2
212 GREEN, OR Distribution Unattended 69.00 12.47 25 1
213 GRIFFIN CREEK, OR Distribution Unattended 115.00 12.47 20 1
214 HAMAKER, OR Distribution Unattended 69.00 12.47 8 3
215 HARRISBURG, OR Distribution Unattended 69.00 20.80 13 1
216 HENLEY, OR Distribution Unattended 69.00 12.47 6 3
217 HERMISTON, OR Distribution Unattended 69.00 12.47 20 1
218 HILLVIEW, OR Distribution Unattended 115.00 20.80 45 2
219 HINKLE, OR Distribution Unattended 69.00 12.47 20 1
220 HOLLADAY, OR Distribution Unattended 115.00 12.47 75 3
221 HOLLYWOOD, OR Distribution Unattended 115.00 12.47 50 2
222 HOOD RIVER, OR Distribution Unattended 69.00 12.47 40 2
223 HORNET, OR Distribution Unattended 69.00 12.47 20 1
224 HUMBUG, OR Distribution Unattended 69.00 12.47 9 1
225 HUNTERS CIRCLE, OR Distribution Unattended 69.00 12.47 13 1
226 ILLAHEE FLATS, OR Distribution Unattended 115.00 7.20 2 1
227 INDEPENDENCE, OR Distribution Unattended 69.00 20.80 25 1
228 JACKSONVILLE, OR Distribution Unattended 115.00 69.00 13.20 75 2
229 JEFFERSON, OR Distribution Unattended 69.00 20.80 25 1
230 JEROME PRAIRIE, OR Distribution Unattended 115.00 12.47 25 1
231 JORDAN POINT, OR Distribution Unattended 115.00 12.47 20 1
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232 JOSEPH, OR Distribution Unattended 20.80 12.47 6 1 1
233 JUNCTION CITY, OR Distribution Unattended 69.00 20.80 22 2
234 KENWOOD, OR Distribution Unattended 69.00 12.47 3 3
235 KILLINGSWORTH, OR Distribution Unattended 69.00 12.47 40 2
236 KNAPPA SVENSEN, OR Distribution Unattended 115.00 12.47 4.16 6 1
237 KNOTT, OR Distribution Unattended 115.00 57.00 12.47 172 5
238 LAKEPORT, OR Distribution Unattended 69.00 12.47 50 2
239 LANCASTER, OR Distribution Unattended 69.00 20.80 13 3
240 LEBANON, OR Distribution Unattended 115.00 20.80 45 2
241 LINCOLN, OR Distribution Unattended 115.00 12.47 105 3
242 LOCKHART STREET, OR Distribution Unattended 115.00 20.80 40 2
243 LYONS, OR Distribution Unattended 69.00 20.80 25 2
244 MADRAS, OR Distribution Unattended 69.00 12.47 7.20 25 2
245 MALLORY, OR Distribution Unattended 115.00 12.47 25 1
246 MARYS RIVER, OR Distribution Unattended 115.00 20.80 20 1
247 MEDCO, OR Distribution Unattended 115.00 12.47 20 1
248 MEDFORD, OR Distribution Unattended 115.00 12.47 67 8
249 MERLIN, OR Distribution Unattended 115.00 12.47 45 2
250 MERRILL, OR Distribution Unattended 69.00 12.47 17 6
251 MINAM, OR Distribution Unattended 69.00 12.47 0 1
252 MODOC, OR Distribution Unattended 69.00 12.47 6 3
253 MONPAC, OR Distribution Unattended 115.00 69.00 13.20 50 1
254 MURDER CREEK, OR Distribution Unattended 115.00 20.80 100 4
255 MYRTLE CREEK, OR Distribution Unattended 69.00 12.47 14 1
256 MYRTLE POINT, OR Distribution Unattended 115.00 20.80 9 1
257 NEW DESCHUTES, OR Distribution Unattended 69.00 12.47 25 1
258 NEW O'BRIEN, OR Distribution Unattended 115.00 12.47 9 1
259 OAK KNOLL, OR Distribution Unattended 115.00 12.47 45 2
260 OAKLAND, OR Distribution Unattended 115.00 12.47 8 1
261 OREMET, OR Distribution Unattended 115.00 20.80 75 3
262 OVERPASS, OR Distribution Unattended 69.00 12.47 7.20 45 2
263 PALLETTE, OR Distribution Unattended 69.00 20.80 1 1 1
264 PARK STREET, OR Distribution Unattended 115.00 12.47 40 2
265 PARKROSE, OR Distribution Unattended 115.00 12.47 37 2
266 PENDLETON, OR Distribution Unattended 69.00 12.47 43 6 1
267 PILOT ROCK, OR Distribution Unattended 69.00 12.47 22 2
268 POWELL BUTTE, OR Distribution Unattended 115.00 12.47 13 1
269 PRINEVILLE, OR Distribution Unattended 115.00 12.47 50 2
270 PROVOLT, OR Distribution Unattended 69.00 12.47 11 3
271 QUEEN AVE, OR Distribution Unattended 69.00 20.80 50 2
272 RED BLANKET, OR Distribution Unattended 69.00 4.16 2 3
273 REDMOND, OR Distribution Unattended 115.00 12.47 50 2
274 RIDDLE, OR Distribution Unattended 115.00 69.00 75 2
275 RIDDLE VENEER, OR Distribution Unattended 115.00 12.47 7.20 25 1
276 ROBERTS CREEK, OR Distribution Unattended 115.00 69.00 13.20 50 1
277 ROGUE RIVER, OR Distribution Unattended 69.00 12.47 13 1
278 ROSEBURG, OR Distribution Unattended 115.00 20.80 50 2
279 ROSS AVENUE, OR Distribution Unattended 69.00 12.47 9 3
280 ROXY ANN, OR Distribution Unattended 115.00 12.47 25 1
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281 RUCH, OR Distribution Unattended 115.00 12.47 9 1
282 RUNNING Y, OR Distribution Unattended 69.00 20.80 9 1
283 RUSSELLVILLE, OR Distribution Unattended 115.00 12.47 45 2
284 SAGE ROAD, OR Distribution Unattended 115.00 12.47 40 2
285 SCENIC, OR Distribution Unattended 115.00 69.00 13.20 70 3
286 SCIO, OR Distribution Unattended 69.00 12.47 8 1
287 SEASIDE, OR Distribution Unattended 115.00 12.47 40 2
288 SELMA, OR Distribution Unattended 115.00 12.47 9 1
289 SHASTA WAY, OR Distribution Unattended 12.47 4.16 2 3
290 SHEVLIN PARK, OR Distribution Unattended 69.00 12.47 7.20 50 2
291 SIMTAG BOOSTER PUMP, OR Distribution Unattended 34.50 4.16 19 2
292 SOUTH DUNES, OR Distribution Unattended 115.00 12.47 9 1
293 SOUTHGATE, OR Distribution Unattended 69.00 20.80 20 1
294 SPRAGUE RIVER, OR Distribution Unattended 69.00 12.47 7 3
295 STATE STREET, OR Distribution Unattended 115.00 20.80 40 2
296 STAYTON, OR Distribution Unattended 69.00 20.80 55 2
297 STEAMBOAT, OR Distribution Unattended 115.00 7.20 0 1
298 STEVENS ROAD, OR Distribution Unattended 115.00 20.80 50 2
299 SUTHERLIN, OR Distribution Unattended 115.00 12.47 25 1
300 SWEET HOME, OR Distribution Unattended 115.00 20.80 42 2
301 TAKELMA, OR Distribution Unattended 115.00 20.80 13 1
302 TALENT, OR Distribution Unattended 115.00 12.47 50 2
303 TEXUM, OR Distribution Unattended 69.00 12.47 25 1
304 TILLER, OR Distribution Unattended 115.00 12.47 5 1 1
305 TOLO, OR Distribution Unattended 69.00 12.47 11 1
306 TURKEY HILL, OR Distribution Unattended 69.00 12.47 13 3
307 UMAPINE, OR Distribution Unattended 69.00 12.47 20 1
308 UMATILLA, OR Distribution Unattended 69.00 12.47 25 2
309 VERNON, OR Distribution Unattended 115.00 12.47 7.20 50 2
310 VILAS, OR Distribution Unattended 115.00 12.47 25 1
311 VILLAGE GREEN, OR Distribution Unattended 115.00 20.80 40 2
312 VINE STREET, OR Distribution Unattended 69.00 20.80 30 1
313 WALLOWA, OR Distribution Unattended 69.00 12.47 7 1
314 WARM SPRINGS, OR Distribution Unattended 69.00 20.80 13 3
315 WARRENTON, OR Distribution Unattended 115.00 12.47 38 2
316 WASCO, OR Distribution Unattended 20.80 4.16 2 3
317 WECOMA BEACH, OR Distribution Unattended 20.80 4.16 3 1
318 WESTON, OR Distribution Unattended 69.00 12.47 25 1
319 WEYERHAEUSER, OR Distribution Unattended 69.00 12.47 40 2
320 WHITE CITY, OR Distribution Unattended 115.00 12.47 65 3
321 WILLOW COVE, OR Distribution Unattended 34.50 4.16 28 3
322 WINCHESTER, OR Distribution Unattended 115.00 69.00 12.47 75 5
323 WINSTON, OR Distribution Unattended 69.00 12.47 23 3
324 YEW AVENUE, OR Distribution Unattended 115.00 12.47 25 1
325 YOUNGS BAY, OR Distribution Unattended 115.00 12.47 37 2
326 LEMOLO 1, OR Transmission Attended 12.47 7.20 2 3
327 PARRISH GAP, OR Transmission Attended 230.00 69.00 12.47 150 1
328 APPLEGATE, OR Transmission Unattended 115.00 69.00 12.47 65 2
329 CALAPOOYA, OR Transmission Unattended 230.00 20.80 12.47 88 2
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330 CAVE JUNCTION, OR Transmission Unattended 115.00 69.00 13.20 70 2
331 CHILOQUIN, OR Transmission Unattended 230.00 115.00 12.47 131 5 1
332 COLD SPRINGS, OR Transmission Unattended 230.00 69.00 66 2
333 COVE, OR Transmission Unattended 230.00 69.00 2.40 127 3
334 DIAMOND HILL, OR Transmission Unattended 230.00 69.00 12.47 75 1
335 DIXONVILLE 230, OR Transmission Unattended 230.00 115.00 13.80 344 6
336 (i)DIXONVILLE 500, OR Transmission Unattended 500.00 230.00 34.50 650 3 1
337 FRIEND, OR Transmission Unattended 230.00 115.00 12.47 500 2
338 FRY, OR Transmission Unattended 230.00 115.00 12.47 500 2 3
339 GRANTS PASS, OR Transmission Unattended 230.00 115.00 12.47 583 4 2
340 HAZELWOOD, OR Transmission Unattended 115.00 69.00 12.47 154 3
341 (j)HURRICANE, OR Transmission Unattended 230.00 69.00 29 2 1
342 ISTHMUS, OR Transmission Unattended 230.00 115.00 13.80 250 1
343 KLAMATH FALLS, OR Transmission Unattended 230.00 69.00 13.80 251 6
344 LONE PINE, OR Transmission Unattended 230.00 115.00 13.80 733 10
345 (k)MALIN, OR Transmission Unattended 500.00 230.00 13.80 775 4 1
346 (l)MERIDIAN, OR Transmission Unattended 500.00 230.00 34.50 1300 6 1
347 MILE HI, OR Transmission Unattended 115.00 69.00 12.47 39 4
348 NICKEL MOUNTAIN, OR Transmission Unattended 230.00 115.00 12.47 125 1
349 PILOT BUTTE, OR Transmission Unattended 230.00 69.00 400 4
350 PONDEROSA, OR Transmission Unattended 230.00 115.00 12.47 500 2
351 PROSPECT CENTRAL, OR Transmission Unattended 115.00 69.00 12.47 45 3 1
352 (m)ROUNDUP, OR Transmission Unattended 230.00 69.00 67 2
353 (n)SANTIAM TIE, OR Transmission Unattended 230.00 69.00 12.47 75 1
354 SNOW GOOSE, OR Transmission Unattended 500.00 230.00 34.50 650 3 1
355 TROUTDALE, OR Transmission Unattended 230.00 115.00 13.20 500 3
356 TUCKER, OR Transmission Unattended 115.00 69.00 12.47 100 2
357 WHETSTONE, OR Transmission Unattended 230.00 115.00 12.47 250 1
358 PIONEER PLANT, UT Distribution Attended 138.00 12.47 30 1
359 WEST VALLEY, UT Distribution Attended 138.00 12.47 30 1
360 106TH SOUTH, UT Distribution Unattended 138.00 12.47 30 1
361 118TH SOUTH, UT Distribution Unattended 138.00 12.47 30 1
362 126TH SOUTH, UT Distribution Unattended 138.00 12.47 66 2
363 23RD STREET, UT Distribution Unattended 46.00 12.47 13 1
364 70TH SOUTH, UT Distribution Unattended 138.00 12.47 30 1
365 ALTAVIEW, UT Distribution Unattended 46.00 12.47 45 2
366 AMALGA, UT Distribution Unattended 46.00 12.47 11 1
367 AMERICAN FORK, UT Distribution Unattended 138.00 12.47 30 1
368 ANGEL, UT Distribution Unattended 138.00 46.00 12.47 135 3
369 ARAGONITE, UT Distribution Unattended 46.00 12.47 1 1
370 AURORA, UT Distribution Unattended 46.00 12.47 3 1
371 BANGERTER, UT Distribution Unattended 138.00 13.20 63 2
372 BDO, UT Distribution Unattended 138.00 12.47 30 1
373 BEAR RIVER, UT Distribution Unattended 46.00 12.47 17 2
374 BENJAMIN, UT Distribution Unattended 46.00 12.47 4 1
375 BINGHAM, UT Distribution Unattended 46.00 13.20 25 1
376 BLACK MOUNTAIN, UT Distribution Unattended 46.00 7.20 1 1
377 BLUE CREEK, UT Distribution Unattended 46.00 12.47 2 3
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378 BLUFF, UT Distribution Unattended 69.00 12.47 2 3
379 BLUFFDALE, UT Distribution Unattended 46.00 12.47 14 1
380 BOTHWELL, UT Distribution Unattended 46.00 12.47 4 1
381 BRIAN HEAD, UT Distribution Unattended 34.50 12.47 14 1
382 BRIGHTON, UT Distribution Unattended 46.00 24.90 29 2
383 BROOKLAWN, UT Distribution Unattended 46.00 12.47 6 1
384 BRUNSWICK, UT Distribution Unattended 46.00 12.47 7.20 62 3
385 BURTON, UT Distribution Unattended 34.50 12.47 11 3
386 BUSH, UT Distribution Unattended 46.00 12.47 14 1
387 CANNON, UT Distribution Unattended 46.00 12.47 13 1
388 CANYONLANDS, UT Distribution Unattended 69.00 12.47 1 1
389 CAPITOL, UT Distribution Unattended 46.00 12.47 20 1
390 CARBIDE, UT Distribution Unattended 69.00 12.47 3 1
391 CARBONVILLE, UT Distribution Unattended 46.00 12.47 6 1
392 CARLISLE, UT Distribution Unattended 138.00 12.47 30 1
393 CASTO, UT Distribution Unattended 46.00 12.47 28 1
394 CENTENNIAL, UT Distribution Unattended 138.00 12.47 40 2
395 CENTERVILLE, UT Distribution Unattended 46.00 12.47 22 1
396 CENTRAL, UT Distribution Unattended 46.00 12.47 9 1
397 CHAPEL HILL, UT Distribution Unattended 138.00 12.47 30 1
398 CHERRYWOOD, UT Distribution Unattended 138.00 12.47 55 2
399 CIRCLEVILLE, UT Distribution Unattended 69.00 12.47 3 1
400 CLEAR CREEK, UT Distribution Unattended 46.00 12.47 4 1
401 CLEAR LAKE, UT Distribution Unattended 69.00 12.47 0 3
402 CLEARFIELD SOUTH, UT Distribution Unattended 138.00 12.47 60 2
403 CLINTON, UT Distribution Unattended 138.00 12.47 50 2
404 CLIVE, UT Distribution Unattended 46.00 12.47 4 1
405 COALVILLE, UT Distribution Unattended 138.00 12.47 22 1
406 COLD WATER CANYON, UT Distribution Unattended 138.00 12.47 30 1
407 COLEMAN, UT Distribution Unattended 138.00 69.00 6.60 106 4
408 COLTON WELL, UT Distribution Unattended 46.00 2.40 1 3
409 COMMERCE, UT Distribution Unattended 138.00 12.47 30 1
410 COPPER HILLS, UT Distribution Unattended 138.00 13.20 30 1
411 CORRINE, UT Distribution Unattended 46.00 12.47 3 1
412 COVE FORT, UT Distribution Unattended 46.00 12.47 2 3
413 COZYDALE, UT Distribution Unattended 138.00 12.47 30 1
414 CRANER FLAT, UT Distribution Unattended 138.00 7.20 40 2
415 CROSS HOLLOW, UT Distribution Unattended 138.00 12.47 20 1
416 CROYDON, UT Distribution Unattended 138.00 46.00 12.47 81 2
417 CUDAHY, UT Distribution Unattended 138.00 12.47 30 1
418 DAMMERON VALLEY, UT Distribution Unattended 34.50 12.47 5 1
419 DECADE, UT Distribution Unattended 138.00 13.20 60 2
420 DECKER LAKE, UT Distribution Unattended 138.00 12.47 55 2
421 DELLE, UT Distribution Unattended 46.00 12.47 6 1
422 DELTA, UT Distribution Unattended 69.00 46.00 13.20 48 3
423 DEWEYVILLE, UT Distribution Unattended 46.00 12.47 4 1
424 DIMPLE DELL, UT Distribution Unattended 138.00 12.47 60 2
425 DRAPER, UT Distribution Unattended 138.00 13.20 60 2
426 DUMAS, UT Distribution Unattended 138.00 12.47 60 2
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427 EAST BENCH, UT Distribution Unattended 138.00 12.47 30 1
428 EAST HYRUM, UT Distribution Unattended 46.00 12.47 6 1
429 EAST LAYTON, UT Distribution Unattended 138.00 12.47 60 2
430 EAST MILLCREEK, UT Distribution Unattended 46.00 12.47 20 1
431 EDEN, UT Distribution Unattended 46.00 12.47 19 2
432 ELBERTA, UT Distribution Unattended 46.00 12.47 5 1
433 ELK MEADOWS, UT Distribution Unattended 46.00 12.47 3 1
434 ELSINORE, UT Distribution Unattended 46.00 12.47 2 1
435 EMERY CITY, UT Distribution Unattended 69.00 12.47 3 3
436 EMIGRATION, UT Distribution Unattended 46.00 12.47 25 1
437 ENOCH, UT Distribution Unattended 138.00 12.47 14 1
438 ENTERPRISE VALLEY, UT Distribution Unattended 138.00 12.47 10 1
439 EUREKA, UT Distribution Unattended 46.00 12.47 3 1
440 FARMINGTON, UT Distribution Unattended 138.00 13.20 60 2
441 FAYETTE, UT Distribution Unattended 46.00 12.47 1 2
442 FERRON, UT Distribution Unattended 69.00 12.47 5 1
443 FIELDING, UT Distribution Unattended 46.00 12.47 6 1
444 FIFTH WEST, UT Distribution Unattended 138.00 13.20 60 2
445 FLUX, UT Distribution Unattended 46.00 12.47 4 1
446 FOOL CREEK, UT Distribution Unattended 46.00 12.47 2 1
447 FORT DOUGLAS, UT Distribution Unattended 138.00 13.20 40 1
448 FOUNTAIN GREEN, UT Distribution Unattended 46.00 12.47 7 1
449 FREEDOM, UT Distribution Unattended 46.00 7.20 0 1
450 FRUIT HEIGHTS, UT Distribution Unattended 46.00 12.47 22 1
451 GARDEN CITY, UT Distribution Unattended 69.00 12.47 13 1
452 GATEWAY, UT Distribution Unattended 69.00 34.50 14 1 2
453 GOLD RUSH, UT Distribution Unattended 138.00 13.20 30 1
454 GORDON AVENUE, UT Distribution Unattended 138.00 12.47 30 1
455 GOSHEN UTAH, UT Distribution Unattended 46.00 12.47 7 1
456 GRANGER, UT Distribution Unattended 46.00 12.47 50 2
457 GRANTSVILLE, UT Distribution Unattended 46.00 12.47 24 1
458 GRAVEL PIT, UT Distribution Unattended 46.00 12.47 3 1
459 GROW, UT Distribution Unattended 138.00 12.47 78 3
460 GUNNISON, UT Distribution Unattended 46.00 12.47 20 1
461 HAMMER, UT Distribution Unattended 138.00 12.47 60 2
462 HAVASU, UT Distribution Unattended 69.00 12.47 3 1
463 HELPER CITY, UT Distribution Unattended 46.00 4.16 3 3
464 HERRIMAN, UT Distribution Unattended 138.00 13.20 60 2
465 HIGHLAND, UT Distribution Unattended 138.00 46.00 12.47 97 2
466 HIGHLAND DISTRIBUTION, UT Distribution Unattended 46.00 12.47 25 1
467 HOGGARD, UT Distribution Unattended 138.00 12.47 50 2
468 HOLDEN, UT Distribution Unattended 46.00 12.47 4 1
469 HOLLADAY, UT Distribution Unattended 46.00 12.47 32 2
470 HONEYVILLE, UT Distribution Unattended 138.00 46.00 6.60 35 1
471 HUNTER, UT Distribution Unattended 46.00 12.47 22 1
472 HUNTINGTON CITY, UT Distribution Unattended 69.00 12.47 7 1
473 IRON MOUNTAIN, UT Distribution Unattended 34.50 12.47 1 3
474 IRONTON, UT Distribution Unattended 46.00 12.47 2 1
475 IVINS, UT Distribution Unattended 69.00 12.47 30 1
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476 JORDAN NARROWS, UT Distribution Unattended 46.00 2.40 14 2
477 JORDAN PARK, UT Distribution Unattended 138.00 12.47 30 1
478 JORDANELLE, UT Distribution Unattended 138.00 12.47 30 1
479 JUAB, UT Distribution Unattended 46.00 12.47 4 1
480 JUDGE, UT Distribution Unattended 46.00 12.47 22 1
481 JUNCTION, UT Distribution Unattended 69.00 12.47 3 1
482 KAIBAB, UT Distribution Unattended 69.00 12.47 5 1
483 KAMAS, UT Distribution Unattended 46.00 12.47 11 1
484 KEARNS, UT Distribution Unattended 138.00 12.47 60 2
485 KENSINGTON, UT Distribution Unattended 46.00 4.16 7 1
486 KYUNE, UT Distribution Unattended 46.00 7.20 0 1
487 LAKE PARK, UT Distribution Unattended 138.00 12.47 53 2
488 LAMPO, UT Distribution Unattended 138.00 46.00 12.47 75 1
489 LAYTON, UT Distribution Unattended 46.00 12.47 40 2
490 LEE CREEK, UT Distribution Unattended 138.00 13.20 30 1
491 LEGRANDE, UT Distribution Unattended 46.00 12.47 2 1
492 LEWISTON, UT Distribution Unattended 46.00 7.20 22 1
493 LINCOLN, UT Distribution Unattended 46.00 12.47 20 1
494 LINDON, UT Distribution Unattended 46.00 12.47 25 1
495 LISBON, UT Distribution Unattended 69.00 12.47 3 1
496 LOAFER, UT Distribution Unattended 46.00 7.20 0 1
497 LOGAN CANYON, UT Distribution Unattended 46.00 7.20 1 1
498 LONE TREE, UT Distribution Unattended 34.50 12.47 20 1
499 LOWER BEAVER, UT Distribution Unattended 46.00 13.20 0 1
500 LYNNDYL, UT Distribution Unattended 46.00 12.47 4 1
501 MAESER, UT Distribution Unattended 69.00 12.47 20 1
502 MAGNA, UT Distribution Unattended 138.00 12.47 30 1
503 MANILA, UT Distribution Unattended 138.00 12.47 30 1
504 MANTUA, UT Distribution Unattended 46.00 12.47 3 1
505 MAPLETON, UT Distribution Unattended 46.00 12.47 25 1
506 MARRIOTT, UT Distribution Unattended 46.00 12.47 20 1
507 MARYSVALE, UT Distribution Unattended 46.00 12.47 3 1
508 MATHIS, UT Distribution Unattended 46.00 12.47 9 1
509 MCCORNICK, UT Distribution Unattended 46.00 12.47 6 1
510 MCKAY, UT Distribution Unattended 46.00 12.47 28 1
511 MEADOWBROOK, UT Distribution Unattended 138.00 12.47 46.00 42 2
512 MEDICAL, UT Distribution Unattended 46.00 12.47 51 3
513 MIDLAND, UT Distribution Unattended 138.00 12.47 30 1
514 MIDVALE, UT Distribution Unattended 46.00 12.47 25 1
515 MILFORD, UT Distribution Unattended 138.00 46.00 13.20 89 2
516 MILFORD TV, UT Distribution Unattended 46.00 13.20 0 1
517 MINERSVILLE, UT Distribution Unattended 46.00 12.47 2 1
518 MOAB CITY, UT Distribution Unattended 69.00 12.47 19 2
519 MOORE, UT Distribution Unattended 69.00 12.47 3 1
520 MORGAN, UT Distribution Unattended 46.00 12.47 5 1
521 MORONI, UT Distribution Unattended 46.00 12.47 6 1
522 MORTON COURT, UT Distribution Unattended 138.00 12.47 65 2
523 MOUNTAIN DELL, UT Distribution Unattended 46.00 12.47 5 1
524 MOUNTAIN GREEN, UT Distribution Unattended 46.00 12.47 9 1
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525 MYTON, UT Distribution Unattended 69.00 12.47 6 1
526 NAPLES, UT Distribution Unattended 138.00 13.20 30 1
527 NEW HARMONY, UT Distribution Unattended 69.00 12.47 7 1
528 NEWGATE, UT Distribution Unattended 46.00 12.47 16 1
529 NEWTON, UT Distribution Unattended 46.00 12.47 5 1
530 NIBLEY, UT Distribution Unattended 138.00 24.90 54 2
531 NORTH BENCH, UT Distribution Unattended 46.00 12.47 25 1
532 NORTH FIELDS, UT Distribution Unattended 46.00 12.47 2 1
533 NORTH LOGAN, UT Distribution Unattended 46.00 12.47 25 1
534 NORTH OGDEN, UT Distribution Unattended 46.00 12.47 22 1
535 NORTH SALT LAKE, UT Distribution Unattended 46.00 13.20 25 1
536 NORTHEAST, UT Distribution Unattended 46.00 12.47 45 2
537 NORTHRIDGE, UT Distribution Unattended 46.00 12.47 14 1
538 OAKLAND AVENUE, UT Distribution Unattended 46.00 12.47 22 1
539 OAKLEY, UT Distribution Unattended 46.00 12.47 6 1
540 OLYMPUS, UT Distribution Unattended 46.00 12.47 22 1
541 OPHIR, UT Distribution Unattended 46.00 12.47 3 1
542 ORANGE, UT Distribution Unattended 46.00 12.47 20 1
543 ORANGEVILLE, UT Distribution Unattended 69.00 12.47 14 1
544 OREM, UT Distribution Unattended 46.00 12.47 48 2
545 PANGUITCH, UT Distribution Unattended 69.00 12.47 5 1
546 PARIETTE, UT Distribution Unattended 69.00 24.90 14 1
547 PARK CITY, UT Distribution Unattended 46.00 12.47 42 2
548 PARKSIDE, UT Distribution Unattended 138.00 12.47 60 2
549 PARKWAY, UT Distribution Unattended 138.00 12.47 50 2
550 PARLEYS, UT Distribution Unattended 46.00 12.47 16 2
551 PELICAN POINT, UT Distribution Unattended 46.00 12.47 6 1
552 PETERSON, UT Distribution Unattended 46.00 12.47 72 1
553 PINE CANYON, UT Distribution Unattended 138.00 12.47 55 2
554 PINE CREEK, UT Distribution Unattended 46.00 12.47 2 1
555 PINNACLE, UT Distribution Unattended 46.00 12.47 14 1
556 PLAIN CITY, UT Distribution Unattended 138.00 12.47 22 1
557 PLEASANT GROVE, UT Distribution Unattended 138.00 12.47 30 1
558 PLEASANT VIEW, UT Distribution Unattended 46.00 12.47 14 1
559 PONY EXPRESS, UT Distribution Unattended 138.00 12.47 60 2
560 PORTER ROCKWELL, UT Distribution Unattended 138.00 13.20 60 2
561 PROMONTORY, UT Distribution Unattended 46.00 12.47 2 1
562 QUAIL CREEK, UT Distribution Unattended 69.00 12.47 14 1
563 QUARRY, UT Distribution Unattended 138.00 12.47 60 2
564 QUICHAPA, UT Distribution Unattended 34.50 7.20 4 1
565 RAINS, UT Distribution Unattended 46.00 7.20 0 1
566 RANDOLPH, UT Distribution Unattended 46.00 12.47 2 1
567 RASMUSON, UT Distribution Unattended 46.00 12.47 1 3
568 RATTLESNAKE, UT Distribution Unattended 69.00 24.90 14 1
569 RED MOUNTAIN, UT Distribution Unattended 69.00 34.50 13 1
570 REDWOOD, UT Distribution Unattended 46.00 12.47 45 2
571 RESEARCH PARK, UT Distribution Unattended 46.00 12.47 45 2
572 RICH, UT Distribution Unattended 69.00 12.47 5 1
573 RICHFIELD, UT Distribution Unattended 46.00 12.47 35 2
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574 RICHMOND, UT Distribution Unattended 46.00 12.47 11 1
575 RIDGELAND, UT Distribution Unattended 138.00 12.47 40 2
576 RITER, UT Distribution Unattended 46.00 12.47 20 1
577 RIVERDALE, UT Distribution Unattended 138.00 46.00 6.60 180 3
578 ROCK CANYON, UT Distribution Unattended 69.00 12.47 5 1
579 ROCKVILLE, UT Distribution Unattended 34.50 12.47 4 1
580 ROCKY POINT, UT Distribution Unattended 138.00 12.47 30 1
581 ROSE PARK, UT Distribution Unattended 46.00 12.47 42 2
582 ROYAL, UT Distribution Unattended 46.00 4.16 0 3
583 SALINA, UT Distribution Unattended 46.00 12.47 11 1
584 SANDY, UT Distribution Unattended 138.00 12.47 60 2
585 SARATOGA, UT Distribution Unattended 138.00 13.20 60 2
586 SCHOO MINE, UT Distribution Unattended 46.00 12.47 9 1
587 SCOFIELD, UT Distribution Unattended 46.00 12.47 1 3
588 SCOFIELD RESERVOIR, UT Distribution Unattended 46.00 7.20 1 1
589 SEGO CANYON, UT Distribution Unattended 69.00 12.47 14 1
590 SEVEN MILE, UT Distribution Unattended 69.00 12.47 5 1 1
591 SHARON, UT Distribution Unattended 46.00 12.47 20 1
592 SHORELINE, UT Distribution Unattended 138.00 13.20 60 2
593 SIXTH SOUTH, UT Distribution Unattended 46.00 12.47 20 1
594 SKULL VALLEY, UT Distribution Unattended 46.00 12.47 2 1
595 SKYPARK, UT Distribution Unattended 138.00 13.20 40 1
596 SMITHFIELD, UT Distribution Unattended 138.00 46.00 6.60 63 2
597 SNARR, UT Distribution Unattended 46.00 12.47 40 2
598 SNOWVILLE, UT Distribution Unattended 69.00 12.47 5 1
599 SNYDERVILLE, UT Distribution Unattended 138.00 46.00 13.80 127 3
600 SOLDIER SUMMIT, UT Distribution Unattended 46.00 12.47 2 1
601 SOUTH JORDAN, UT Distribution Unattended 138.00 12.47 60 2
602 SOUTH MILFORD, UT Distribution Unattended 46.00 24.90 28 2
603 SOUTH MOUNTAIN, UT Distribution Unattended 138.00 12.47 60 2
604 SOUTH OGDEN, UT Distribution Unattended 46.00 12.47 25 1
605 SOUTH PARK, UT Distribution Unattended 138.00 12.47 30 1
606 SOUTH WEBER, UT Distribution Unattended 138.00 12.47 22 1
607 SOUTHEAST, UT Distribution Unattended 138.00 12.47 60 2
608 SOUTHWEST, UT Distribution Unattended 46.00 12.47 22 2
609 SPANISH VALLEY, UT Distribution Unattended 69.00 12.47 14 1
610 SPRINGDALE, UT Distribution Unattended 34.50 12.47 14 1
611 ST JOHN, UT Distribution Unattended 46.00 12.47 4 1
612 STANSBURY, UT Distribution Unattended 46.00 12.47 20 1
613 SUMMIT CREEK, UT Distribution Unattended 138.00 13.80 30 1
614 SUMMIT PARK, UT Distribution Unattended 46.00 12.47 7 1
615 SUNRISE, UT Distribution Unattended 138.00 12.47 60 2
616 SUTHERLAND, UT Distribution Unattended 46.00 24.90 9 1
617 TAMARISK, UT Distribution Unattended 138.00 12.47 20 1
618 TAYLOR, UT Distribution Unattended 46.00 12.47 14 1
619 THIEF CREEK, UT Distribution Unattended 138.00 24.90 14 1
620 THIRD WEST, UT Distribution Unattended 138.00 13.20 100 2
621 THIRTEENTH SOUTH, UT Distribution Unattended 46.00 12.47 22 1
622 TOOELE DEPOT, UT Distribution Unattended 46.00 12.47 25 1
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623 TOQUERVILLE, UT Distribution Unattended 69.00 34.50 34 2
624 TRI-CITY, UT Distribution Unattended 138.00 12.47 30 1 1
625 UINTAH, UT Distribution Unattended 46.00 12.47 39 2
626 UNION, UT Distribution Unattended 46.00 12.47 50 2
627 VALLEY CENTER, UT Distribution Unattended 46.00 12.47 22 1
628 VERMILLION, UT Distribution Unattended 46.00 12.47 3 1
629 VERNAL, UT Distribution Unattended 69.00 12.47 33 2
630 VICKERS, UT Distribution Unattended 46.00 12.47 4 1
631 VINEYARD, UT Distribution Unattended 138.00 13.20 30 1
632 WALLSBURG, UT Distribution Unattended 138.00 12.47 13 1
633 WALNUT GROVE, UT Distribution Unattended 138.00 12.47 30 1
634 WARREN, UT Distribution Unattended 138.00 12.47 30 1
635 WASATCH STATE PARK, UT Distribution Unattended 46.00 12.47 2 3
636 WASHAKIE, UT Distribution Unattended 138.00 4.16 14 1
637 WELBY, UT Distribution Unattended 46.00 12.47 42 2
638 WELFARE, UT Distribution Unattended 46.00 12.47 11 1
639 WEST COMMERCIAL, UT Distribution Unattended 46.00 12.47 22 1
640 WEST JORDAN, UT Distribution Unattended 138.00 12.47 28 1
641 WEST OGDEN, UT Distribution Unattended 138.00 12.47 60 2
642 WEST POINT, UT Distribution Unattended 138.00 13.20 40 1
643 WEST ROY, UT Distribution Unattended 46.00 12.47 25 1
644 WEST TEMPLE, UT Distribution Unattended 46.00 7.20 53 3
645 WESTFIELD, UT Distribution Unattended 138.00 12.47 20 1
646 WESTWATER, UT Distribution Unattended 69.00 12.47 5 1
647 WHITE ROCK, UT Distribution Unattended 138.00 13.20 30 1
648 WILLOWCREEK, UT Distribution Unattended 46.00 12.47 1 1
649 WILLOWRIDGE, UT Distribution Unattended 46.00 12.47 25 1
650 WINCHESTER HILLS, UT Distribution Unattended 34.50 12.47 4 1
651 WINKLEMAN, UT Distribution Unattended 46.00 7.20 0 1
652 WOLF CREEK, UT Distribution Unattended 69.00 12.47 6 1
653 WOODRUFF, UT Distribution Unattended 46.00 12.47 2 1
654 WOODS CROSS, UT Distribution Unattended 46.00 12.47 20 1
655 CUTLER, UT Transmission Attended 138.00 46.00 6.60 50 1
656 EMERY, UT Transmission Attended 345.00 138.00 12.47 411 3
657 GADSBY, UT Transmission Attended 138.00 46.00 13.80 318 2
658 90TH SOUTH, UT Transmission Unattended 345.00 138.00 12.47 1604 6
659 ABAJO, UT Transmission Unattended 138.00 69.00 13.80 67 2
660 ASHLEY, UT Transmission Unattended 138.00 69.00 12.47 134 2
661 BEN LOMOND, UT Transmission Unattended 345.00 230.00 13.80 2202 6
662 BLACK ROCK, UT Transmission Unattended 230.00 69.00 13.20 75 1
663 BLACKHAWK, UT Transmission Unattended 138.00 69.00 7.20 100 2
664 BUTLERVILLE, UT Transmission Unattended 138.00 46.00 13.80 205 4
665 CAMERON, UT Transmission Unattended 138.00 46.00 6.60 100 4
666 CAMP WILLIAMS, UT Transmission Unattended 345.00 138.00 24.90 169 2 0
667 CLOVER, UT Transmission Unattended 345.00 138.00 24.90 400 1
668 COLUMBIA, UT Transmission Unattended 138.00 46.00 6.60 71 2
669 COTTONWOOD, UT Transmission Unattended 138.00 46.00 12.47 312 7
670 EL MONTE, UT Transmission Unattended 138.00 46.00 12.47 313 3
671 EMMA PARK, UT Transmission Unattended 138.00 12.47 8 1
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672 GARKANE, UT Transmission Unattended 69.00 46.00 2.40 33 1
673 GREEN CANYON, UT Transmission Unattended 138.00 46.00 6.60 67 2
674 HALE, UT Transmission Unattended 138.00 46.00 12.47 114 2
675 HELPER, UT Transmission Unattended 138.00 46.00 12.47 77 2
676 HORSESHOE, UT Transmission Unattended 138.00 46.00 6.60 80 2
677 HUNTINGTON, UT Transmission Unattended 345.00 138.00 12.47 270 4
678 JERUSALEM, UT Transmission Unattended 138.00 46.00 6.60 67 1
679 JORDAN, UT Transmission Unattended 138.00 46.00 12.47 204 3
680 MATHINGTON, UT Transmission Unattended 138.00 46.00 13.20 189 6
681 MCCLELLAND, UT Transmission Unattended 138.00 46.00 13.80 340 3
682 MCFADDEN, UT Transmission Unattended 138.00 69.00 13.80 45 1
683 MIDDLETON, UT Transmission Unattended 138.00 69.00 6.60 137 3
684 MIDVALLEY, UT Transmission Unattended 345.00 138.00 13.80 450 1
685 MIDWAY CITY, UT Transmission Unattended 138.00 46.00 12.47 67 1
686 MINERAL PRODUCTS, UT Transmission Unattended 69.00 46.00 6.60 13 1
687 MOAB, UT Transmission Unattended 138.00 69.00 6.60 67 1
688 NEBO, UT Transmission Unattended 138.00 46.00 6.60 67 1
689 OQUIRRH, UT Transmission Unattended 345.00 138.00 13.80 835 4
690 PAROWAN VALLEY, UT Transmission Unattended 230.00 138.00 13.80 138 2
691 PARRISH, UT Transmission Unattended 138.00 46.00 13.80 97 2
692 PAVANT, UT Transmission Unattended 230.00 46.00 13.80 133 2
693 PINTO, UT Transmission Unattended 345.00 138.00 13.80 257 (t)3
694 PURGATORY FLAT, UT Transmission Unattended 138.00 69.00 12.47 300 2
695 RED BUTTE, UT Transmission Unattended 345.00 138.00 24.90 764 6 2
696 SCIPIO, UT Transmission Unattended 46.00 12.47 2 3
697 SEVIER, UT Transmission Unattended 138.00 46.00 6.60 34 4
698 SIGURD, UT Transmission Unattended 345.00 230.00 13.80 1075 (u)6
699 SILVER CREEK, UT Transmission Unattended 138.00 46.00 13.80 100 2
700 SPANISH FORK, UT Transmission Unattended 345.00 138.00 13.80 1100 2
701 SYRACUSE, UT Transmission Unattended 345.00 138.00 13.80 1300 6
702 TAYLORSVILLE, UT Transmission Unattended 138.00 46.00 12.47 358 4
703 TERMINAL, UT Transmission Unattended 345.00 138.00 12.47 1610 5
704 THREE PEAKS, UT Transmission Unattended 345.00 138.00 12.47 450 1
705 TIMP, UT Transmission Unattended 138.00 46.00 7.20 130 2
706 TOOELE, UT Transmission Unattended 138.00 46.00 13.20 249 3
707 WEST CEDAR, UT Transmission Unattended 230.00 138.00 12.47 147 2
708 ATTALIA, WA Distribution Unattended 69.00 12.47 25 1
709 BOWMAN, WA Distribution Unattended 69.00 12.47 45 2
710 CASCADE KRAFT, WA Distribution Unattended 69.00 12.47 151 7
711 CENTRAL, WA Distribution Unattended 69.00 12.47 14 1
712 CLINTON, WA Distribution Unattended 115.00 12.47 25 1
713 DAYTON, WA Distribution Unattended 69.00 12.47 23 2
714 DODD ROAD, WA Distribution Unattended 69.00 20.80 25 4
715 GRANDVIEW, WA Distribution Unattended 115.00 69.00 12.47 58 2
716 GROMORE, WA Distribution Unattended 115.00 12.47 25 1
717 HOPLAND, WA Distribution Unattended 115.00 12.47 50 2
718 MILL CREEK, WA Distribution Unattended 69.00 12.47 45 2
719 NACHES, WA Distribution Unattended 115.00 12.47 25 1
720 NOB HILL, WA Distribution Unattended 115.00 12.47 42 2
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721 NORTH PARK, WA Distribution Unattended 115.00 12.47 45 2
722 ORCHARD, WA Distribution Unattended 115.00 12.47 50 2
723 PACIFIC, WA Distribution Unattended 115.00 12.47 28 3
724 POMEROY, WA Distribution Unattended 69.00 12.47 9 1
725 POMONA HEIGHTS, WA Distribution Unattended 230.00 115.00 12.47 325 3
726 PROSPECT POINT, WA Distribution Unattended 69.00 12.47 40 2
727 PUNKIN CENTER, WA Distribution Unattended 115.00 13.20 44 3
728 RIVER ROAD, WA Distribution Unattended 115.00 12.47 76 5
729 SELAH, WA Distribution Unattended 115.00 12.47 45 2
730 SULPHUR CREEK, WA Distribution Unattended 115.00 12.47 25 1
731 SUNNYSIDE, WA Distribution Unattended 115.00 12.47 45 2
732 TIETON, WA Distribution Unattended 115.00 34.50 29 2 1
733 TOPPENISH, WA Distribution Unattended 115.00 12.47 50 2
734 TOUCHET, WA Distribution Unattended 69.00 12.47 13 1
735 VOELKER, WA Distribution Unattended 115.00 12.47 25 1
736 WAITSBURG, WA Distribution Unattended 69.00 12.47 9 1
737 WAPATO, WA Distribution Unattended 115.00 12.47 45 2
738 WENAS, WA Distribution Unattended 115.00 12.47 25 2
739 WHITE SWAN, WA Distribution Unattended 115.00 12.47 22 2
740 WILEY, WA Distribution Unattended 115.00 12.47 45 2
741 FLINT SUBSTATION, WA Distribution Unattended 115.00 13.20 30 1
742 (o)DRY GULCH, WA Transmission Unattended 115.00 69.00 50 1
743 OUTLOOK, WA Transmission Unattended 230.00 115.00 12.47 250 1
744 PASCO, WA Transmission Unattended 115.00 69.00 7.20 39 9
745 UNION GAP, WA Transmission Unattended 230.00 115.00 13.20 595 5
746 (p)WALLA WALLA, WA Transmission Unattended 230.00 69.00 300 3
747 WALLULA, WA Transmission Unattended 230.00 69.00 120 2 1
748 WINE COUNTRY, WA Transmission Unattended 230.00 115.00 250 1
749 ANTELOPE MINE, WY Distribution Unattended 230.00 34.50 13.20 25 1
750 ARROWHEAD, WY Distribution Unattended 230.00 34.50 13.20 150 2
751 ASTLE STREET, WY Distribution Unattended 34.50 13.20 13 1
752 BAILEY DOME, WY Distribution Unattended 57.00 4.16 2 1
753 BAIROIL, WY Distribution Unattended 115.00 69.00 13.20 53 3
754 BAR X, WY Distribution Unattended 230.00 34.50 13.20 25 1
755 BARR NUNN, WY Distribution Unattended 115.00 12.47 30 1
756 BATTLE SPRINGS, WY Distribution Unattended 34.50 13.80 2 1
757 BELLAMY 2, WY Distribution Unattended 69.00 4.16 5 1
758 BIG MUDDY, WY Distribution Unattended 69.00 12.47 7 1
759 BIG PINEY, WY Distribution Unattended 69.00 24.90 14 1
760 BLACKS FORK, WY Distribution Unattended 230.00 34.50 13.20 225 3 1
761 BRIDGER PUMP, WY Distribution Unattended 230.00 34.50 7.20 73 4
762 BRYAN, WY Distribution Unattended 115.00 12.47 25 1
763 BUFFALO, WY Distribution Unattended 230.00 20.80 20 1 1
764 BYRON, WY Distribution Unattended 34.50 4.16 2 3
765 CASSA, WY Distribution Unattended 57.00 20.80 2 6
766 CENTER STREET, WY Distribution Unattended 115.00 12.47 13 1
767 CHAPMAN, WY Distribution Unattended 46.00 12.47 4 1
768 CHUKAR, WY Distribution Unattended 12.47 4.16 1 3
769 COKEVILLE, WY Distribution Unattended 46.00 24.90 8 1
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770 COLUMBIA GENEVA, WY Distribution Unattended 230.00 12.47 45 2
771 COMMUNITY PARK, WY Distribution Unattended 115.00 12.47 50 2
772 CROOKS GAP, WY Distribution Unattended 34.50 12.47 6 1
773 DEAVER, WY Distribution Unattended 34.50 4.16 0 3
774 DEER CREEK, WY Distribution Unattended 69.00 12.47 9 1
775 DJ COAL MINE, WY Distribution Unattended 69.00 34.50 13 1
776 DRY FORK, WY Distribution Unattended 69.00 4.16 9 1
777 ELK BASIN, WY Distribution Unattended 34.50 7.20 5 1
778 ELK HORN, WY Distribution Unattended 115.00 12.47 25 1
779 EMIGRANT, WY Distribution Unattended 115.00 12.47 13 1
780 EVANS, WY Distribution Unattended 115.00 12.47 9 1
781 EVANSTON, WY Distribution Unattended 138.00 12.47 40 2
782 FIREHOLE, WY Distribution Unattended 230.00 34.50 13.20 50 2
783 FORT CASPER, WY Distribution Unattended 69.00 12.47 28 1
784 FORT SANDERS, WY Distribution Unattended 115.00 13.20 20 1
785 FRANNIE, WY Distribution Unattended 230.00 34.50 2.40 50 2
786 FRONTIER, WY Distribution Unattended 69.00 4.16 6 1
787 GARLAND, WY Distribution Unattended 230.00 34.50 13.20 45 2
788 GRASS CREEK, WY Distribution Unattended 230.00 34.50 25 1
789 GREAT DIVIDE, WY Distribution Unattended 115.00 34.50 20 1
790 GREEN MOUNTAIN, WY Distribution Unattended 34.50 4.16 5 1
791 GREYBULL, WY Distribution Unattended 34.50 4.16 3 1
792 HANNA, WY Distribution Unattended 34.50 13.20 6 1
793 HILLTOP, WY Distribution Unattended 115.00 34.50 13.20 45 2 1
794 HOLLY SUGAR, WY Distribution Unattended 34.50 4.16 5 1
795 JACKALOPE, WY Distribution Unattended 115.00 13.20 55 2
796 KEMMERER, WY Distribution Unattended 69.00 24.90 14 1
797 KIRBY CREEK, WY Distribution Unattended 34.50 4.16 2 3
798 KIRBY CREEK PUMPING, WY Distribution Unattended 34.50 2.40 2 3
799 LABARGE, WY Distribution Unattended 69.00 24.90 8 6
800 LANDER, WY Distribution Unattended 34.50 12.47 25 2
801 LARAMIE, WY Distribution Unattended 115.00 13.20 50 2
802 LATHAM, WY Distribution Unattended 230.00 46.00 575 3
803 LINCH, WY Distribution Unattended 69.00 13.80 12 1
804 LITTLE MOUNTAIN, WY Distribution Unattended 230.00 34.50 20 1
805 LOVELL, WY Distribution Unattended 34.50 4.16 4 1
806 MANSFACE, WY Distribution Unattended 230.00 34.50 2.40 20 1
807 MILL IRON, WY Distribution Unattended 34.50 13.80 12 1
808 MILLS, WY Distribution Unattended 12.47 4.16 2 3
809 MINERS, WY Distribution Unattended 230.00 34.50 7.20 20 1
810 MOUNTAIN GAS, WY Distribution Unattended 34.50 12.47 4.16 3 1
811 MURPHY DOME, WY Distribution Unattended 34.50 12.47 13 1
812 NAUGHTON CONSTRUCTION, WY Distribution Unattended 69.00 12.47 2 3
813 NUGGETT, WY Distribution Unattended 69.00 7.20 0 1
814 OPAL, WY Distribution Unattended 69.00 24.90 8 1
815 OREGON BASIN, WY Distribution Unattended 230.00 69.00 13.20 100 2
816 ORIN, WY Distribution Unattended 57.00 7.20 1 1 1
817 OWL CREEK PUMP #1, WY Distribution Unattended 34.50 4.16 2 3
818 PARADISE, WY Distribution Unattended 69.00 24.90 30 1
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819 PARCO, WY Distribution Unattended 34.50 13.20 3 1
820 PHILLIPS GAS PLANT PIPELINE, WY Distribution Unattended 12.47 2.40 1 3
821 PINEDALE, WY Distribution Unattended 69.00 24.90 20 1
822 PITCHFORK, WY Distribution Unattended 69.00 24.90 14 3 1
823 PLATTE, WY Distribution Unattended 230.00 115.00 13.20 140 3
824 PLATTE PIPE BYRON, WY Distribution Unattended 34.50 4.16 2 3
825 PLATTE PIPE OREGON BASIN, WY Distribution Unattended 34.50 4.16 2 3
826 PLATTE RIVER DJ, WY Distribution Unattended 69.00 12.47 2 3
827 POINT OF ROCKS, WY Distribution Unattended 230.00 34.50 13.20 25 1
828 POISON SPIDER, WY Distribution Unattended 69.00 2.40 3 1
829 RAINBOW, WY Distribution Unattended 34.50 13.20 13 1
830 RAVEN, WY Distribution Unattended 230.00 34.50 12.47 200 2
831 RED BUTTE, WY Distribution Unattended 115.00 13.20 30 1
832 REFINERY, WY Distribution Unattended 115.00 12.47 45 2
833 RIVERTON, WY Distribution Unattended 230.00 34.50 13.20 77 4
834 ROCK SPRINGS 230, WY Distribution Unattended 230.00 34.50 13.20 50 2 1
835 SAGE HILL, WY Distribution Unattended 34.50 13.20 9 1
836 SHOSHONI, WY Distribution Unattended 34.50 2.40 2 3
837 SINCLAIR PIPELINE, WY Distribution Unattended 34.50 4.16 5 1
838 SLATE CREEK, WY Distribution Unattended 69.00 13.80 1 1
839 SOUTH CODY, WY Distribution Unattended 69.00 24.90 14 3 1
840 SOUTH ELK BASIN, WY Distribution Unattended 34.50 4.16 2 6
841 SOUTH TRONA, WY Distribution Unattended 230.00 34.50 13.20 150 2
842 SPRING CREEK, WY Distribution Unattended 115.00 13.20 28 1
843 SVILAR, WY Distribution Unattended 34.50 4.16 2 3
844 TEN MILE, WY Distribution Unattended 69.00 12.47 5 1
845 THERMOPOLIS TOWN, WY Distribution Unattended 34.50 4.16 5 1
846 THERMOPOLIS(WAPA), WY Distribution Unattended 115.00 34.50 25 1
847 THUNDER CREEK, WY Distribution Unattended 69.00 12.47 14 1
848 VETERANS, WY Distribution Unattended 34.50 13.20 25 2
849 WAMSUTTER AMOCO, WY Distribution Unattended 34.50 4.16 2 3
850 WARM SPRINGS SPL, WY Distribution Unattended 115.00 4.16 9 1
851 WERTZ SINCLAIR, WY Distribution Unattended 57.00 4.16 3 6
852 WEST ADAMS, WY Distribution Unattended 34.50 4.16 3 1
853 WESTVACO, WY Distribution Unattended 230.00 34.50 25 1
854 WHISKEY GULCH, WY Distribution Unattended 57.00 12.47 9 1
855 WORLAND TOWN, WY Distribution Unattended 34.50 4.16 4 1
856 WYCO BEAR CREEK, WY Distribution Unattended 20.80 2.40 1 3
857 WYCO STROUD, WY Distribution Unattended 13.20 4.16 2 3
858 WYOPO, WY Distribution Unattended 230.00 34.50 20 1 1
859 YELLOWCAKE, WY Distribution Unattended 230.00 34.50 13.20 100 2
860 (q)DAVE JOHNSTON, WY Transmission Attended 230.00 115.00 13.20 283 2 2
861 (r)JIM BRIDGER, WY Transmission Attended 345.00 230.00 34.50 675 4
862 NAUGHTON, WY Transmission Attended 230.00 138.00 13.80 661 4
863 AEOLUS, WY Transmission Unattended 500.00 230.00 34.50 1600 3
864 ANTICLINE, WY Transmission Unattended 500.00 345.00 1600 3 1
865 CASPER, WY Transmission Unattended 230.00 115.00 13.80 575 4
866 CHAPPEL CREEK, WY Transmission Unattended 230.00 69.00 12.47 75 1
867 CHIMNEY BUTTE, WY Transmission Unattended 230.00 69.00 12.47 75 1
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868 FOOTE CREEK, WY Transmission Unattended 230.00 34.50 12.47 196 2
869 GLENDO AUTO, WY Transmission Unattended 69.00 57.00 8 1 1
870 MIDWEST, WY Transmission Unattended 230.00 69.00 13.20 158 3
871 MUSTANG, WY Transmission Unattended 230.00 115.00 13.20 100 1
872 RAILROAD, WY Transmission Unattended 230.00 138.00 24.90 448 1
873 SAGE, WY Transmission Unattended 69.00 46.00 2.40 22 1
874 STANDPIPE, WY Transmission Unattended 230.00 12.47 75 2
875 THERMOPOLIS, WY Transmission Unattended 230.00 115.00 12.47 84 1 1
876 TotalDistributionSubstationAttendedMember 133
877 TotalDistributionSubstationUnttendedMember 19,829
878 TotalTransmissionSubstationAttendedMember 3,387
879 TotalTransmissionSubstationUnattendedMember 39,168
880 Total 62,517 0
FERC FORM NO. 1 (ED. 12-96)Page 426-427
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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.
LineNo.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, 501 120,755,953
3 Equipment purchase Bridger Coal Company 107 355,950
4 Coal purchases Trapper Mining Inc.151, 501 17,739,447
5 (a)Administrative services under the IASA Berkshire Hathaway Energy Company 107, 165, 232, 426.1, 426.4, 426.5, 920, 921, 923,924, 925, 930.2 111,695,370
6 Employee relocation services HomeServices of America, Inc.501, 506, 548, 549, 557, 560, 561.2, 580, 581, 590,
597, 908, 921 387,750
7 Administrative services under the IASA Kern River Gas Transmission Company 923 31,755
8 Gas transportation services Kern River Gas Transmission Company 547 3,116,253
9 Administrative services under the IASA MidAmerican Energy Company 107, 146, 165, 426.4, 426.5, 921, 923, 930.2 10,087,401
10 Administrative services under the IASA Nevada Power Company 107, 923 1,023,927
11 Operational support services Nevada Power Company 570 32,556
12 Administrative services under the IASA Northern Natural Gas 107, 921, 923 316,638
13 Banking services Bank of America Corporation 427, 431 47,826
14 Underwriting services BofA Securities, Inc.181 618,750
15 Banking services (b)The Bank of New York Mellon Corporation 426.5, 427, 431, 930.2 (e)188,290
16 Underwriting services (c)BNY Mellon Capital Markets, LLC 181 123,750
17 Rail services and right-of-way fees BNSF Railway Company 151, 501, 507, 567, 589, 593 (f)21,275,510
18 Materials and supplies Marmon Utility LLC 107 7,744,058
19 Rating agency fees Moody's Investors Service, Inc.186 552,500
20 Travel services NetJets, Inc.426.5, 923 417,595
21 Banking services (d)U.S. Bancorp 419, 427, 431, 537, 557, 903, 920, 921, 928, 930.2 371,319
22 Operational support services Western Midstream Holdings, LLC 107 1,667,747
19
20 Non-power Goods or Services Provided for Affiliated
21 Information technology and administrative support services Bridger Coal Company 426.5, 501, 557, 923, 925, 930.1, 930.2, 931 1,974,932
22 Administrative services under the IASA Berkshire Hathaway Energy Company 426.5, 557, 903, 921, 923, 930.2, 931, 935, 107 14,249,833
23 Administrative services under the IASA BHE GT&S, LLC 920, 921, 923, 931, 935, 107 1,917,265
24 Administrative services under the IASA BHE Renewables, LLC 426.5, 557, 921, 923, 931, 107 404,815
25 Administrative services under the IASA BHE Turbo Machinery, LLC 426.5 834,521
26 Administrative services under the IASA MidAmerican Energy Company 426.5, 580, 903, 920, 921, 923, 931, 107 1,631,347
27 Administrative services under the IASA MTL Canyon Holdings, LLC 923, 931, 107 396,097
28 Administrative services under the IASA Nevada Power Company 920, 921, 923, 931, 107 389,352
29 Administrative services under the IASA Northern Natural Gas Company 426.5, 921, 931, 107 393,713
30 Administrative services under the IASA Northern Powergrid Holding Company 426.5, 921, 923, 931, 107 284,498
31 Administrative services under the IASA NV Energy, Inc.592, 903, 920, 921, 923, 931, 107 1,285,471
32 Equipment sale NV Energy, Inc.107 357,758
42
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Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/18/2023 Year/Period of ReportEnd of: 2022/ 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. Four 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. Two combinations of this allocator are used for allocating costs that benefit different companies within the BHE organization. Weighted Customer/Customer Service Agents: An allocation based on a combination of customer counts and customer service agents. Two combinations of this allocator are used for allocating costs that benefit different companies within the BHE organization. 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: NameOfAssociatedAffiliatedCompany
On December 31, 2022, The Bank of New York Mellon Corporation and BNY Mellon Capital Markets, LLC ceased being affiliated companies when the ownership of the number of shares of The Bank of New York Mellon Corporation common stock by PacifiCorp's ultimate direct parent company, Berkshire Hathaway Inc., fell below the 5% threshold used to define an associated (affiliated) company for purposes of this page.
(c) Concept: NameOfAssociatedAffiliatedCompany
On December 31, 2022, The Bank of New York Mellon Corporation and BNY Mellon Capital Markets, LLC ceased being affiliated companies when the ownership of the number of shares of The Bank of New York Mellon Corporation common stock by PacifiCorp's ultimate direct parent company, Berkshire Hathaway Inc., fell below the 5% threshold used to define an associated (affiliated) company for purposes of this page.
(d) Concept: NameOfAssociatedAffiliatedCompany
On October 31, 2022, U.S. Bancorp ceased being an affiliated company when the ownership of the number of shares of U.S. Bancorp common stock by PacifiCorp's ultimate direct parent company, Berkshire Hathaway Inc., fell below the 5% threshold used to define an associated (affiliated) company for purposes of this page
(e) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies
The following item is excluded from the total in column (d):The Bank of New York Mellon Trust Company is the trustee and custodian for PacifiCorp's pension plan master trust and post-retirement health and welfare benefit plan trust during the year ended December 31, 2022. Trustee fees are paid by the trusts, however the expenses flow through to PacifiCorp's net periodic benefit cost. For the year ended December 31, 2022, the plans paid $148,568 for these trustee and custodial services.
(f) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies
Non-power goods or services provided by BNSF Railway Company are as follows: $ 21,202,984 Rail services 72,526 Right-of-way $ 21,275,510
FERC FORM NO. 1 ((NEW))Page 429