2021Annual Report FERC Form 1.pdf

1407 West North Temple, Suite 330 Salt Lake City, Utah 84116
April 26, 2022
VIA ELECTRONIC DELIVERY
Idaho Public Utilities Commission 11331 W Chinden Blvd.
Building 8 Suite 201A
Boise, ID 83714
Attention: Jan Noriyuki Commission Secretary
RE: FERC Form 1
PacifiCorp (d.b.a. Rocky Mountain Power) submits for filing one copy of PacifiCorp’s annual FERC Form 1 report for the year ended December 31, 2021.
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
Please direct any informal questions to Ted Weston, Regulatory Manager, at [phone].
Sincerely,
Joelle Steward Senior Vice President, Regulation and Customer Solutions
Enclosure
RECEIVED
2022 APR 26 AM 9:31
IDAHO PUBLIC
UTILITIES COMMISSION
PAC-E
THIS FILING IS
Item 1: ☑ An Initial (Original) Submission OR ☐ Resubmission No.
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sections 3, 4(a),304 and 309, and 18 CFR 141.1 and 141.400. Failure to report may result incriminal fines, civil penalties and other sanctions as provided by law. The
Federal Energy Regulatory Commission does not consider these reports to be
of confidential nature
Exact Legal Name of Respondent (Company)
PacifiCorp
Year/Period of ReportEnd of: 2021/ Q4
FERC FORM NO. 1 (REV. 02-04)
INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q
GENERAL INFORMATION
Purpose
FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electricutilities, licensees and others (18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q)is a quarterly regulatory requirement which supplements the annual financial reportingrequirement (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 alsoconsidered to be non-confidential public use forms.
Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission’s UniformSystem of Accounts Prescribed for Public Utilities, Licensees, and Others Subject To the
Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18
C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).
Note: Major means having, in each of the three previous calendar years, sales or
transmission service that exceeds one of the following:
one million megawatt hours of total annual sales,
100 megawatt hours of annual sales for resale,
500 megawatt hours of annual power exchanges delivered, or
500 megawatt hours of annual wheeling for others (deliveries plus losses).
What and Where to Submit
Submit FERC Form Nos. 1 and 3-Q electronically through the eCollection portal at
https://eCollection.ferc.gov, and according to the specifications in the Form 1 and 3-Q taxonomies.
The Corporate Officer Certification must be submitted electronically as part of the
FERC Forms 1 and 3-Q filings.
Submit immediately upon publication, by either eFiling or mail, two (2) copies to theSecretary of the Commission, the latest Annual Report to Stockholders. UnlesseFiling the Annual Report to Stockholders, mail the stockholders report to theSecretary of the Commission at: Secretary Federal Energy Regulatory Commission 888 First Street, NE Washington, DC 20426 For the CPA Certification Statement, submit within 30 days after filing the FERCForm 1, a letter or report (not applicable to filers classified as Class C or Class D
prior to January 1, 1984). The CPA Certification Statement can be either eFiled or
mailed to the Secretary of the Commission at the address above.
The CPA Certification Statement should:
Attest to the conformity, in all material aspects, of the below listed (schedulesand pages) with the Commission's applicable Uniform System of Accounts(including applicable notes relating thereto and the Chief Accountant's
published accounting releases), and
Be signed by independent certified public accountants or an independentlicensed public accountant certified or licensed by a regulatory authority of aState or other political subdivision of the U. S. (See 18 C.F.R. §§ 41.10-41.12for specific qualifications.)
Schedules Pages Comparative Balance Sheet 110-113
Statement of Income 114-117
Statement of Retained Earnings118-119
Statement of Cash Flows 120-121
Notes to Financial Statements 122-123
The following format must be used for the CPA Certification Statement unlessunusual circumstances or conditions, explained in the letter or report, demand that it
be varied. Insert parenthetical phrases only when exceptions are reported.
“In connection with our regular examination of the financial statements of[COMPANY NAME] for the year ended on which we have reported separately under
date of [DATE], we have also reviewed schedules [NAME OF SCHEDULES] of
FERC Form No. 1 for the year filed with the Federal Energy RegulatoryCommission, for conformity in all material respects with the requirements of theFederal Energy Regulatory Commission as set forth in its applicable UniformSystem of Accounts and published accounting releases. Our review for this purpose
included such tests of the accounting records and such other auditing procedures as
we considered necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the
preceding paragraph (except as noted below) conform in all material respects with
the accounting requirements of the Federal Energy Regulatory Commission as setforth in its applicable Uniform System of Accounts and published accountingreleases.” The letter or report must state which, if any, of the pages above do notconform 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 theCommission’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
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 thefollowing 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, searchingexisting data sources, gathering and maintaining the data-needed, and completing andreviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated to average 168 hours per response.
Send comments regarding these burden estimates or any aspect of these collections ofinformation, including suggestions for reducing burden, to the Federal Energy RegulatoryCommission, 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 FederalEnergy Regulatory Commission). No person shall be subject to any penalty if anycollection 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. (Entercents for averages and figures per unit where cents are important. The truncating of centsis 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 forreporting purposes, use for balance sheet accounts the balances at the end of the currentreporting period, and use for statement of income accounts the current year's year to date
amounts.
Complete each question fully and accurately, even if it has been answered in a previousreport. 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 bedebits or credits, must be reported as positive. Numbers having a sign that is different
from the expected sign must be reported by enclosing the numbers in parentheses.
For any resubmissions, please explain the reason for the resubmission in a footnote tothe data field.
Do not make references to reports of previous periods/years or to other reports in lieu ofrequired 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 anappropriate explanation given as to why the different figures were used.
Schedule specific instructions are found in the applicable taxonomy and on the applicableblank rendered form.
Definitions for statistical classifications used for completing schedules for transmission systemreporting are as follows:
FNS - Firm Network Transmission Service for Self. "Firm" means service that can not beinterrupted for economic reasons and is intended to remain reliable even under adverseconditions. "Network Service" is Network Transmission Service as described in Order No. 888and the Open Access Transmission Tariff. "Self" means the respondent.
FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted foreconomic reasons and is intended to remain reliable even under adverse conditions. "NetworkService" is Network Transmission Service as described in Order No. 888 and the Open Access
Transmission Tariff.
LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one
year or longer and” firm" means that service cannot be interrupted for economic reasons and is
intended to remain reliable even under adverse conditions. "Point-to-Point TransmissionReservations" are described in Order No. 888 and the Open Access Transmission Tariff. For alltransactions identified as LFP, provide in a footnote the termination date of the contract definedas the earliest date either buyer or seller can unilaterally cancel the contract.
OLF - Other Long-Term Firm Transmission Service. Report service provided under contractswhich do not conform to the terms of the Open Access Transmission Tariff. "Long-Term" meansone year or longer and “firm” means that service cannot be interrupted for economic reasons
and is intended to remain reliable even under adverse conditions. For all transactions identified
as OLF, provide in a footnote the termination date of the contract defined as the earliest dateeither 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 isless 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 foreachentry.
FERC FORM NO. 1 (ED. 03-07)
https://www.ferc.gov/general-information-0/electric-industry-forms.
When to Submit
each entry.
AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" forservice provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment.
DEFINITIONS
Commission Authorization (Comm. Auth.) -- The authorization of the Federal EnergyRegulatory 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 entityor 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 thisAct, to with:
’Corporation' means any corporation, joint-stock company, partnership, association,
business trust, organized group of persons, whether incorporated or not, or a receiver orreceivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, ashereinafter defined;
'Person' means an individual or a corporation;
'Licensee, means any person, State, or municipality Licensed under the provisions of
section 4 of this Act, and any assignee or successor in interest thereof;
'municipality means a city, county, irrigation district, drainage district, or other political
subdivision or agency of a State competent under the Laws thereof to carry and the
business of developing, transmitting, unitizing, or distributing power; ......
"project' means. a complete unit of improvement or development, consisting of a power
house, all water conduits, all dams and appurtenant works and structures (including
navigation structures) which are a part of said unit, and all storage, diverting, or fore bayreservoirs directly connected therewith, the primary line or lines transmitting power therefrom 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 appropriatein 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 thewater 'resources of any region to be developed, the water-power industry and its relation
to other industries and to interstate or foreign commerce, and concerning the location,
capacity, development costs, and relation to markets of power sites; ... to the extent theCommission may deem necessary or useful for the purposes of this Act."
"Sec. 304.
Every Licensee and every public utility shall file with the Commission such annual andother 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 inwhich such reports shall be made, and require from such persons specific answers to allquestions upon which the Commission may need information. The Commission mayrequire that such reports shall include, among other things, full information as to assets
and Liabilities, capitalization, net investment, and reduction thereof, gross receipts,
interest due and paid, depreciation, and other reserves, cost of project and other facilities,cost of maintenance and operation of the project and other facilities, cost of renewals andreplacement of the project works and other facilities, depreciation, generation,transmission, distribution, delivery, use, and sale of electric energy. The Commission may
require any such person to make adequate provision for currently determining such costs
and other facts. Such reports shall be made under oath unless the Commission otherwisespecifies*.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 mayprescribe 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, andthe 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
REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent
PacifiCorp
02 Year/ Period of Report
End of: 2021/ 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)
04/13/2022
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 therespondent 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)
04/13/2022
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any false, fictitious or fraudulent statements as to
any matter within its jurisdiction.
FERC FORM No. 1 (REV. 02-04)Page 1
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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
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 IncTax
Taxes Accrued, Prepaid and Charged During the Year
36 266
37 269
38 272
39 274
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 Investment Tax Credits
Other Deferred Credits
Accumulated Deferred Income Taxes-Accelerated Amortization
Property
Accumulated Deferred Income Taxes-Other Property
Accumulated Deferred Income Taxes-Other
Other Regulatory Liabilities
Electric Operating Revenues
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)
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 whereany 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 notincorporated, 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 nameto 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. Theresulting Oregon corporation was re-named PacifiCorp, which is the operating entity today.
State of Incorporation:
Date of Incorporation:
Incorporated Under Special Law:
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the
authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not applicable.
(a) Name of Receiver or Trustee Holding Property of the Respondent:
(b) Date Receiver took Possession of Respondent Property:
(c) Authority by which the Receivership or Trusteeship was created:
(d) Date when possession by receiver or trustee ceased:
4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated.
PacifiCorp is a United States regulated electric utility company headquartered in Oregon that serves approximately 2.0 million retail electric customers, including residential, commercial,industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp is principally engaged in the business of generating, transmitting,distributing and selling electricity. In addition to retail sales, PacifiCorp buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions
and other market participants. PacifiCorp delivers electricity to customers in Utah, Wyoming and Idaho under the trade name Rocky Mountain Power and to customers in Oregon, Washington
and California under the trade name Pacific Power.
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant for your previous year's certified financial statements?
(1) ☐ Yes
(2) ☑ No
FERC FORM No. 1 (ED. 12-87)Page 101
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 controllingcorporation 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 mainparent 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 91.1% 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, and Mr. Gregory E. Abel,BHE's Chair, in the amounts of 7.9% and 1.0%, respectively.
FERC FORM No. 1 (ED. 12-96)Page 102
1
1
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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, oreach 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 meaningof the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
LineNo.(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 VotingStock Owned Footnote Ref.
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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. On January 1, 2021, Tri-State Generation and Transmission Association, Inc. terminated its membership in the cooperative. As of December 31, 2021, 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, 2021, the Foundation's two directors are also directors of PacifiCorp.
FERC FORM No. 1 (ED. 12-96)
Page 103
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 wasmade.
LineNo.(a)(b)(c)(d)(e)
1 (a)
Executive Officers as of December 31, 2021:
2 Chair of the Board of Directors and ChiefExecutive Officer, PacifiCorp
(b)
William J. Fehrman
3 President and Chief Executive Officer, PacificPower Stefan A. Bird 473,011
4 President and Chief Executive Officer, Rocky
Mountain Power Gary W. Hoogeveen 473,011
5 Vice President, Chief Financial Officer and
Treasurer, PacifiCorp Nikki L. Kobliha 262,260
FERC FORM No. 1 (ED. 12-96)
Page 104
Title Name of Officer Salary for Year Date Started in Period Date Ended in Period
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: OfficerTitle
PacifiCorp sets forth compensation information for its "named executive officers" for the year ended December 31, 2021 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
Mr. Fehrman received no direct compensation from PacifiCorp. PacifiCorp reimbursed its indirect parent company, Berkshire Hathaway Energy Company ("BHE"), for the cost of Mr. Fehrman’s time
spent on matters supporting PacifiCorp, including compensation paid to him by BHE, pursuant to an intercompany administrative services agreement among BHE and its subsidiaries. For further
information on executive compensation, refer to BHE’s Annual Report on Form 10-K for the year ended December 31, 2021.
FERC FORM No. 1 (ED. 12-96)Page 104
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 thedirectors who are officers of the respondent.2. Provide the principle place of business in column (b), designate members of the Executive Committee in column (c), and the Chairman of the Executive Committee in column (d).
Line
No.(a)(b)(c)(d)
1 William J. Fehrman (Chair of the Board ofDirectors and Chief Executive Officer,PacifiCorp)
666 Grand Avenue, 27th Floor, Des Moines,
IA 50309 false false
2 Stefan A. Bird (President and ChiefExecutive Officer, Pacific Power)825 N.E. Multnomah Street, Suite 2000,Portland, OR 97232 false false
3 Gary W. Hoogeveen (President and Chief
Executive Officer, Rocky Mountain Power)
1407 West North Temple, Suite 310, Salt
Lake City, UT 84116 false false
4 Nikki L. Kobliha (Vice President, Chief
Financial Officer and Treasurer, PacifiCorp)
825 N.E. Multnomah Street, Suite 1900,
Portland, OR 97232 false false
5 Calvin D. Haack 666 Grand Avenue, 27th Floor, Des Moines,IA 50309 false false
6 Natalie L. Hocken 825 N.E. Multnomah Street, Suite 2000,Portland, OR 97232 false false
FERC FORM No. 1 (ED. 12-95)Page 105
Name (and Title) of Director Principal Business Address Member of the Executive Committee Chairman of the Executive Committee
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 theaccepted rate.
LineNo.(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
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2022
Year/Period of Report
End of: 2021/ Q4
INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commissionannual (or more frequent) filings containing the
inputs to the formula rate(s)?
☑ Yes
☐ No
If yes, provide a listing of such filings as contained on the Commission's eLibrary website.
Line
No.(a)(b)(c)(d)(e)
1 20210106-5040 01/06/2021 ER21-711 (a)
See footnote PacifiCorp's Volume No. 11 OpenAccess Transmission Tariff
2 20210329-5097 03/29/2021 ER21-1547 (b)
See footnote PacifiCorp's Volume No. 11 OpenAccess Transmission Tariff
3 20210419-5095 04/19/2021 ER21-1711 (c)
See footnote PacifiCorp's Volume No. 11 OpenAccess Transmission Tariff
4 20210514-5206 05/14/2021 ER11-3643 (d)
See footnote PacifiCorp's Volume No. 11 Open
Access Transmission Tariff
5 20211007-5097 10/07/2021 ER22-65 (e)
See footnote PacifiCorp's Volume No. 11 Open
Access Transmission Tariff
FERC FORM NO. 1 (NEW. 12-08)Page 106a
Accession No.Document Date / FiledDate Docket No.Description Formula Rate FERC Rate ScheduleNumber or Tariff Number
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionOfFiling
PacifiCorp submits tariff filing per 35.17(b): OATT Revised Attachment H-1 (Rev Dep Rates) - Supplemental Filing to be effective 1/1/2021 under ER21-711
(b) Concept: DescriptionOfFiling
PacifiCorp submits tariff filing per 35.13(a)(2)(iii: OATT Revised Attachment H-1 (Rev Depreciation Rates 2021) to be effective 6/1/2021 under ER21-1547
(c) Concept: DescriptionOfFiling
PacifiCorp submits tariff filing per 35.13(a)(2)(iii: OATT Formula Rate - Schedule 10 Loss Factor for June 2021 to be effective 6/1/2021 under ER21-1711
(d) Concept: DescriptionOfFiling
Transmission Formula Rate Annual Update Informational Filing of PacifiCorp under ER11-3643
(e) Concept: DescriptionOfFiling
PacifiCorp submits tariff filing per 35.13(a)(2)(iii: OATT Formula Rate - Schedule 10 Dist System Loss Factor January 2022 to be effective 1/1/2022 under ER22-65
FERC FORM NO. 1 (NEW. 12-08)
Page 106a
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 fromamounts 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.
LineNo.(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
18 320-323 Electric Operation and Maintenance Expenses (b)185
19 320-323 Electric Operation and Maintenance Expenses (b)196
20 320-323 Electric Operation and Maintenance Expenses (b)197
FERC FORM No. 1 (NEW. 12-08)Page 106b
Page No(s).Schedule Column LineNo.
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 thetransactions, 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 wasrequired. 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 Commissionauthorization, 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 companymust also state major new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and approximate total gas
volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having a maturity of oneyear 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 105of 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 ortransactions 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
Siskiyou County 11/05/2021 11/05/2036 2.0%
Idaho
St. Anthony 04/01/2021 04/01/2031 —%
Oregon
Canyonville 12/15/2021 12/15/2031 7.0%
Junction City 09/17/2021 09/17/2031 5.0%
Mosier 12/03/2021 12/03/2031 7.0%
Phoenix 09/20/2021 09/20/2026 5.0%
Prineville 04/01/2021 04/01/2026 5.0%
Sutherlin 12/17/2021 12/17/2031 3.5%
Umatilla 12/20/2021 12/20/2041 3.5%
Utah
Bear River 03/01/2021 03/01/2026 —%
Cedar Hills 03/01/2021 03/01/2041 —%
Centerville 12/31/2021 12/31/2026 —%
Garland 11/01/2021 11/01/2031 —%
Hideout 09/01/2021 09/01/2031 —%
North Logan 08/01/2021 08/01/2031 —%
North Salt Lake 04/01/2021 04/01/2026 —%
Orem 12/01/2021 12/31/2031 —%
Randolph 04/01/2021 04/01/2026 —%
Tremonton 06/01/2021 06/01/2026 —%
Woodruff 10/01/2021 10/01/2031 —%
Woods Cross 03/01/2021 03/01/2026 —%
Washington
Dayton 02/12/2021 02/12/2031 —%
Naches 04/15/2021 04/15/2041 —%
Wyoming
None
(1) In California, franchise agreement fees are an expense to PacifiCorp and are embedded in rates.
(2) In Idaho, PacifiCorp collects franchise agreement fees from customers and remits them directly to the applicable municipalities.
(3) In Oregon, the first 3.5% of the franchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 3.5% is collected from customers and remitted directly to the applicable municipalities.
(4) In Utah, PacifiCorp collects associated taxes from customers and remits them directly to the applicable municipalities. If applicable, franchise agreement fees are an expense to PacifiCorp and are embedded in rates.
(5) In Washington, PacifiCorp collects associated taxes from customers and remits them directly to the applicable municipalities.
(6) In Wyoming, the first 1.0% of the franchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 1.0% is collected from customers and remitted directly to the applicable municipalities.
ITEM 2.
None.
ITEM 3.
None.
(1)
(2)
(3)
(4)
(5)
(6)
ITEM 4.
None.
ITEM 5.
During the year ended December 31, 2021, 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 regardingtransmission lines added or removed during the year.
ITEM 6.
Long-term Debt
In November 2021, PacifiCorp exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed $450 million of its 2.95% Series First Mortgage Bonds that was originally due February 2022.
In July 2021, PacifiCorp issued $1 billion of its 2.90% First Mortgage Bonds due June 2052. PacifiCorp used the net proceeds to finance a portion of the capital expenditures disbursed during the period from July 1, 2019 to May 31, 2021 with respect toinvestments, primarily from the Energy Vision 2020 initiative, in the repowering of certain of its existing wind-powered generating facilities and the construction and acquisition of new wind-powered generating facilities, which were previouslyfinanced with PacifiCorp's general funds.
As of December 31, 2021, PacifiCorp had regulatory authority from the OPUC and the IPUC to issue an additional $2 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. Also, as of December 31,2021, PacifiCorp had an effective shelf registration statement with the United States Securities and Exchange Commission to issue an indeterminate amount of first mortgage bonds through September 2023. State commission authorizations for theabove issuance and to issue an additional $2 billion of long-term debt are as follows:
•IPUC – Case No. PAC-E-20-15, Order 34831, dated November 12, 2020, effective through September 30, 2025.
•OPUC – Docket No. UF-4318, Order No. 20-393, dated November 3, 2020.
PacifiCorp's Mortgage and Deed of Trust creates a lien on most of PacifiCorp's electric utility property, allowing the issuance of bonds based on a percentage of utility property additions, bond credits arising from retirement of previously outstandingbonds 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, 2021, PacifiCorp estimated it would be able to issue up to $11.8 billion of new first mortgage bonds under themost restrictive issuance test in the mortgage. Any issuances are subject to market conditions and amounts may be further limited by regulatory authorizations or commitments or by covenants and tests contained in other financing agreements.PacifiCorp also has the ability to release property from the lien of the mortgage on the basis of property additions, bond credits or deposits of cash.
For further discussion, refer to Note 8 of Notes to Financial Statements in this Form No. 1.
ITEM 7.None.
ITEM 8.
For the year ended December 31, 2021, PacifiCorp's bargaining unit wage scale changes were as follows:
Unions Represented % Increase Effective Date(s)
Estimated Annual
Financial Impact
IBEW 57 Combustion Turbine (UT)2.33%01/26/2021 $80,500
IBEW 57 Laramie (WY)1.30%06/26/2021 8,856
IBEW 57 Power Delivery (UT, ID & WY)2.33%01/26/2021 1,959,964
IBEW 57 Power Supply (UT, ID & WY)2.33%01/26/2021 865,341
IBEW 125 (OR, WA)2.33%01/26/2021 653,003
IBEW 659 (OR, CA)3.57%04/26/2021 1,121,990
UWUA 127 (WY)0.53%09/26/2021 239,887
UWUA 197 (OR)1.52%05/26/2021 22,208
Total $4,951,749
(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 wildfires in California and Oregon that occurred during calendar year 2020, 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 officer, director or security holder transactions during the year ended December 31, 2021, other than preferred and common stock dividends declared and paid.
ITEM 12.
None.
ITEM 13.
None.
ITEM 14.
Not applicable
FERC FORM No. 1 (ED. 12-96)Page 108-109
(1)(2)
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of Quarter/YearBalance(c)
Prior Year End Balance 12/31
(d)
1
2 200 32,293,100,959 30,752,136,973
3 200 1,131,734,692 1,539,838,861
4 33,424,835,651 32,291,975,834
5 200 11,632,340,710 10,874,594,134
6 21,792,494,941 21,417,381,700
7 202
8
9
10
11
12 202
13
14 21,792,494,941 21,417,381,700
15
16
17
18 21,197,450 12,333,949
19 3,221,891 3,224,650
20 69,928 69,928
21 224 115,816,829 137,091,815
23 228
24 118,042,168 106,378,001
25
26
27
28 106,001,549 35,358,662
29
30 19,559,679 6,372,711
31
32 377,465,712 294,380,416
33
34
35 1,470,795 11,310,312
36 69,648
37
38 151,097,351 52,513
39 1,361,714 1,374,246
40 479,505,475 472,567,933
41 49,554,169 39,312,444
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)
42 17,701,164 17,084,938
43
44 (a)55,652,195 (b)28,457,757
45 227 192,078,435 222,141,625
46 227
47 227
48 227 281,877,967 260,235,105
49 227
50 227
51 202/227
52 228
53 228
54 227
55
56
57 81,560,111 80,191,819
58
59 1,965
60 1,181,610 1,184,888
61 263,654,000 253,806,000
62 11,101,465
63 95,643,511 33,026,440
64 19,559,679 6,372,711
65
66
67 1,617,378,455 1,391,374,546
68
69 42,678,915 37,670,714
70 230a
71 230b
72 232 1,278,010,867 1,296,157,597
73 9,534,716 1,673,810
74
75
76
77
78 233 107,087,451 101,368,220
79
80 352
81 2,836,085 3,388,709
82 234 701,421,321 777,003,313
83
84 2,141,569,355 2,217,262,363
85 25,928,908,463 25,320,399,025
FERC FORM No. 1 (REV. 12-03)
(Less) Accum. Prov. for Uncollectible Acct.-Credit (144)
Notes Receivable from Associated Companies (145)
Accounts Receivable from Assoc. Companies (146)
Fuel Stock (151)
Fuel Stock Expenses Undistributed (152)
Residuals (Elec) and Extracted Products (153)
Plant Materials and Operating Supplies (154)
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)
Page 110-111
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) 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.
(b) Concept: AccountsReceivableFromAssociatedCompanies
As of December 31, 2020, Account 146, Accounts receivable from associated companies, included $27,548,045 of income tax receivable from Berkshire Hathaway Energy Company, PacifiCorp's
indirect parent company.
FERC FORM No. 1 (REV. 12-03)Page 110-111
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of Quarter/YearBalance(c)
Prior Year End Balance 12/31
(d)
1
2 250 3,417,945,896 3,417,945,896
3 250 2,397,600 2,397,600
4
5
6
7 253 1,102,063,956 1,102,063,956
8 252
9 254
10 254b 41,101,061 41,101,061
11 118 5,387,352,868 4,628,196,840
12 118 61,817,828 83,092,814
13 250
14
15 122(a)(b)(17,132,153)(19,097,488)
16 9,913,344,934 9,173,498,557
17
18 256 (a)8,797,150,000 8,667,150,000
19 256
20 256
21 256
22 2,945 13,970
23 24,493,189 18,031,923
24 8,772,659,756 8,649,132,047
25
26 19,860,468 20,983,471
27 5,351,421 4,731,983
28 153,152,301 153,031,206
29 75,091,507 171,735,512
30 32,368,828 32,574,469
31 8,549,918 9,239,918
32 7,091,366 19,164,041
33
34 303,597,269 270,152,870
35 605,063,078 681,613,470
36
37 93,000,000
38 617,255,909 722,327,719
39 (b)24,836,545
40 139,954,550 143,269,702
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)
41 45,305,524 42,224,507
42 262 56,245,950 69,730,217
43 122,543,764 128,769,917
44 40,475 40,475
45
46
47 21,220,657 21,412,558
48 87,320,483 95,233,583
49 3,638,134 7,686,260
50 37,762,438 26,335,953
51 7,091,366 19,164,041
52
53
54 1,124,196,518 1,355,703,395
55
56 120,471,243 105,190,481
57 266 11,945,656 12,326,236
58
59 269 237,702,175 216,557,492
60 278 1,563,255,203 1,700,242,286
61
62 272 143,583,856 152,581,995
63 3,054,144,040 2,908,481,325
64 382,542,004 365,071,741
65 5,513,644,177 5,460,451,556
66 25,928,908,463 25,320,399,025
FERC FORM No. 1 (REV. 12-03)Page 112-113
Customer Deposits (235)
Taxes Accrued (236)
Interest Accrued (237)
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)
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: Bonds
Refer to Item 6 in Important Changes During the Year and Note 8 in Notes to FinancialStatements in this Form No. 1 for a discussion of PacifiCorp's long-term debt.
(b) Concept: NotesPayableToAssociatedCompanies
Represents amounts due to Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp, pursuant to an umbrella loan agreement for which the interest rate is determined daily and is equal
to the lowest cost of short-term borrowings PacifiCorp could otherwise incur externally. At December 31, 2020, the interest rate on the outstanding loan balance was 0.16%.
FERC FORM No. 1 (REV. 12-03)Page 112-113
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 incolumn (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 otherutility 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 theamount(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 andthe tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gaspurchases.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 andapportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line
No.
Title of Account
(a)
(Ref.)Page
No.
(b)
Total Current
Year to DateBalance forQuarter/Year(c)
Total Prior
Year to DateBalance forQuarter/Year(d)
Current 3
Months
Ended -QuarterlyOnly - No4th Quarter
(e)
Prior 3
Months
Ended -QuarterlyOnly - No4th Quarter
(f)
ElectricUtilityCurrent Year
to Date (in
dollars)(g)
ElectricUtilityPrevious
Year to Date
(in dollars)(h)
GasUtiityCurrentYear to
Date
(indollars)(i)
Gas
Utility
PreviousYear toDate (indollars)
(j)
OtherUtilityCurrentYear to
Date
(indollars)(k)
Other
Utility
PreviousYear toDate (indollars)
(l)
1
2 300 5,292,889,125 5,333,490,161 5,292,889,125 5,333,490,161
3
4 320 2,523,615,762 2,600,315,603 2,523,615,762 2,600,315,603
5 320 382,291,665 425,975,941 382,291,665 425,975,941
6 336 (a)986,207,765 1,132,669,721 986,207,765 1,132,669,721
7 336 (b)0 (e)0
8 336 58,932,504 48,015,712 58,932,504 48,015,712
9 336 3,113,124 7,826,626 3,113,124 7,826,626
10
11
12 11,401,911 1,993,985 11,401,911 1,993,985
13 1,037,696 1,037,696
14 262 (c)213,406,731 208,904,338 213,406,731 208,904,338
UTILITYOPERATINGINCOME
OperatingRevenues (400)
Operating
Expenses
Operation
Expenses (401)
MaintenanceExpenses (402)
DepreciationExpense (403)
DepreciationExpense for Asset
Retirement Costs
(403.1)
Amort. & Depl. ofUtility Plant (404-405)
Amort. of Utility
Plant Acq. Adj.
(406)
Amort. PropertyLosses, UnrecovPlant andRegulatory Study
Costs (407)
Amort. of
ConversionExpenses (407.2)
Regulatory Debits(407.3)
(Less) RegulatoryCredits (407.4)
15 262 (165,049,160)9,029,531 (165,049,160)9,029,531
16 262 5,479,455 29,923,616 5,479,455 29,923,616
17 234,272 833,817,129 1,085,922,871 833,817,129 1,085,922,871
18 234,272 757,999,686 1,203,873,466 757,999,686 1,203,873,466
19 266 (1,339,178)(2,252,575)(1,339,178)(2,252,575)
20
21
22 47 62 47 62
23
24 (d)0
25 4,093,877,975 4,343,414,145 4,093,877,975 4,343,414,145
27 1,199,011,150 990,076,016 1,199,011,150 990,076,016
28
29
30
31 2,662,913 1,377,228
32 2,873,018 1,478,109
33
34 25,341 29,731
35 296,773 371,308
36 119 18,855,602 17,675,307
37 24,486,132 10,121,094
38 49,860,757 98,115,567
Taxes Other Than
Income Taxes
(408.1)
Income Taxes -Federal (409.1)
Income Taxes -Other (409.1)
Provision forDeferred Income
Taxes (410.1)
(Less) Provision for
Deferred IncomeTaxes-Cr. (411.1)
Investment TaxCredit Adj. - Net(411.4)
(Less) Gains from
Disp. of Utility Plant
(411.6)
Losses from Disp.of Utility Plant(411.7)
(Less) Gains fromDisposition of
Allowances (411.8)
Losses from
Disposition ofAllowances (411.9)
Accretion Expense(411.10)
TOTAL Utility
Operating
Expenses (EnterTotal of lines 4 thru24)
Net Util Oper Inc(Enter Tot line 2
less 25)
Other Income and
Deductions
Other Income
Nonutilty OperatingIncome
Revenues FromMerchandising,Jobbing and
Contract Work
(415)
(Less) Costs andExp. ofMerchandising,Job. & Contract
Work (416)
Revenues From
NonutilityOperations (417)
(Less) Expenses ofNonutility
Operations (417.1)
Nonoperating
Rental Income(418)
Equity in Earningsof SubsidiaryCompanies (418.1)
Interest and
Dividend Income
(419)
Allowance for OtherFunds Used DuringConstruction(419.1)
39 5,733,860 5,504,193
40 2,363,941 2,117,405
41 101,361,619 133,774,262
42
43 1,472 4,975
44 1,331,000 1,329,358
45 2,445,690 2,572,991
46 (10,128,246)(7,233,756)
47 50,152 40,713
48 1,146,393 1,275,212
49 7,903,583 6,124,235
50 2,750,044 4,113,728
51
52 262 332,818 317,911
53 262 4,382,388 1,519,317
54 262 992,489 344,083
55 234,
272 91,464,238 99,704,873
56 234,272 91,395,252 99,314,436
57
58 1,105,184 (1,431,198)
59 4,671,497 4,002,946
60 93,940,078 125,657,588
61
62 405,404,301 395,447,394
63 4,541,192 4,430,043
64 607,365 582,467
65 9,640 11,026
Miscellaneous
Nonoperating
Income (421)
Gain on Dispositionof Property (421.1)
TOTAL OtherIncome (Enter Totalof lines 31 thru 40)
Other Income
Deductions
Loss on Disposition
of Property (421.2)
MiscellaneousAmortization (425)
Donations (426.1)
Life Insurance(426.2)
Penalties (426.3)
Exp. for CertainCivic, Political &
Related Activities
(426.4)
Other Deductions(426.5)
TOTAL OtherIncome Deductions
(Total of lines 43
thru 49)
Taxes Applic. toOther Income andDeductions
Taxes Other ThanIncome Taxes
(408.2)
Income Taxes-
Federal (409.2)
Income Taxes-Other (409.2)
Provision forDeferred Inc. Taxes(410.2)
(Less) Provision for
Deferred Income
Taxes-Cr. (411.2)
Investment TaxCredit Adj.-Net(411.5)
(Less) InvestmentTax Credits (420)
TOTAL Taxes on
Other Income and
Deductions (Totalof lines 52-58)
Net Other Incomeand Deductions
(Total of lines 41,
50, 59)
Interest Charges
Interest on Long-Term Debt (427)
Amort. of DebtDisc. and Expense(428)
Amortization of
Loss on Reaquired
Debt (428.1)
(Less) Amort. ofPremium on Debt-Credit (429)
66
67 8,260 68,131
68 18,094,181 24,017,899
69 23,737,375 47,853,687
70 404,908,284 376,681,221
71 888,042,944 739,052,383
72
73
74
75
76 262
77
78 888,042,944 739,052,383
FERC FORM No. 1 (REV. 02-04)Page 114-117
(Less) Amortization
of Gain on
Reaquired Debt-Credit (429.1)
Interest on Debt toAssoc. Companies(430)
Other Interest
Expense (431)
(Less) Allowance
for Borrowed FundsUsed DuringConstruction-Cr.(432)
Net Interest
Charges (Total of
lines 62 thru 69)
Income BeforeExtraordinary Items(Total of lines 27,60 and 70)
Extraordinary Items
Extraordinary
Income (434)
(Less)
ExtraordinaryDeductions (435)
Net ExtraordinaryItems (Total of line
73 less line 74)
Income Taxes-
Federal and Other(409.3)
Extraordinary ItemsAfter Taxes (line 75less line 76)
Net Income (Total
of line 71 and 77)
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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, 2021 and 2020, depreciation expense associated with transportation equipment was $21,897,241 and $17,001,326, 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, 2021 and 2020, payroll taxes were $41,389,456 and $41,280,714, respectively.
(d) Concept: AccretionExpense
Generally, PacifiCorp records the accretion expense of asset retirement obligations as a regulatory asset.
(e) Concept: DepreciationExpenseForAssetRetirementCosts
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as a regulatory asset.
FERC FORM No. 1 (REV. 02-04)
Page 114-117
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022
Year/Period of Report
End of: 2021/ 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 accountaffected 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 bereserved 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.
LineNo.Item(a)
Contra Primary
Account Affected
(b)
Current Quarter/Year Year to Date
Balance
(c)
Previous Quarter/Year Year to Date
Balance
(d)
1 4,574,204,823 3,798,019,657
2
3
4
9
10
15
16 869,187,342 721,377,076
17
17.1 215.1 (4,673,767)(5,177,730)
22 (4,673,767)(5,177,730)
23
23.1 238 (a)(161,902)(d)(161,902)
29 (161,902)(161,902)
30
30.1 238 (150,000,000)
36 (150,000,000)
37 216.1 (b)40,130,588 (e)60,147,722
38 5,328,687,084 4,574,204,823
39
45
46 (c)58,665,784 (f)53,992,017
47 58,665,784 53,992,017
48 5,387,352,868 4,628,196,840
49 83,092,814 125,565,229
50 18,855,602 17,675,307
51
52
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 generatingfacilities
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. SubsidiaryEarnings
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)
52.1 (40,130,588)(60,147,722)
53 61,817,828 83,092,814
FERC FORM No. 1 (REV. 02-04)Page 118-119
TOTAL other Changes in unappropriated undistributed subsidiary
earnings for the year
Transfers to/from Unappropriated Retained Earnings (Account 216)
Balance-End of Year (Total lines 49 thru 52)
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022
Year/Period of Report
End of: 2021/ Q4
FOOTNOTE DATA
(a) 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
(b) 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
(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, 2020 and declared dividends on preferred stock during the twelve-month period ended December 31, 2020 were as follows:
Shares Dividend
6.00% Serial Preferred 5,930 $35,580
7.00% Serial Preferred 18,046 126,322
23,976 $161,902
(e) Concept: TransfersFromUnappropriatedUndistributedSubsidiaryEarnings
For the twelve-month period ended December 31, 2020, paid distributions from subsidiaries of PacifiCorp were as follows:
Pacific Minerals, Inc.$60,000,000
Fossil Rock Fuels, LLC 87,149
Trapper Mining Inc.60,573
$60,147,722
(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
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 CashEquivalents 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 thoseactivities. 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 amountof leases capitalized with the plant cost.
LineNo.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
2 888,042,944 739,052,383
3
4 (a)1,013,325,570 1,151,239,762
5
5.1
5.2 60,263,504 49,345,070
5.3 3,113,124 7,826,626
5.4 11,277,621 831,998
8 75,886,429 (117,560,158)
9 (2,444,362)(821,377)
10 (13,561,927)(177,191,411)
11 8,420,328 (87,948,821)
12
13 (3,178,644)369,736,250
14 (124,842,614)(173,153,044)
15 (63,774,428)(55,931,765)
16 49,860,757 98,115,567
17 (21,274,986)(42,472,415)
18
18.1 (34,978,927)(49,558,460)
18.2 18,900,000 23,200,000
18.3
18.4 2,539,731 2,076,277
18.5 (2,788,571)(2,412,688)
18.6 3,748,044 5,949,328
18.7 (10,097,198)(7,204,947)
18.8 4,580,196 4,419,017
18.9 (417,772)(661,895)
18.10 (2,486,295)(1,613,469)
22 1,802,940,982 1,623,975,524
24
25
26 (1,562,755,515)(2,637,870,331)
27
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
Change in derivative contact assets and liabilities, net
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
28
29
30 (49,860,757)(98,115,567)
31
34 (1,512,894,758)(2,539,754,764)
36
37 (b)13,387,785 (c)5,817,459
39
40 22,337,771
41
42
44
45
46
47
49
50
51
52
53
53.1
53.2 487,069 3,279,838
53.3 (2,310,144)(1,234,808)
57 (1,501,330,048)(2,509,554,504)
59
60
61 983,978,493 987,159,337
62
63
64
66
67
70 983,978,493 987,159,337
72
73 (870,000,000)(38,125,000)
74
75
76
76.1 (24,835,000)(35,165,000)
76.2 (1,287,340)(78,234)
76.3 (24,738)
76.4 (5,220,564)(1,568,715)
78 (92,998,346)(36,935,028)
80 (161,902)(161,902)
81 (150,000,000)
Gross Additions to Common Utility Plant
Gross Additions to Nonutility Plant
(Less) Allowance for Other Funds Used During Construction
Other (provide details in footnote):
Cash Outflows for Plant (Total of lines 26 thru 33)
Acquisition of Other Noncurrent Assets (d)
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
Investment in long-term incentive plan 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, PacificMinerals, 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
83 (160,549,397)875,125,458
85
86 141,061,537 (10,453,522)
88 18,210,834 28,664,356
90 159,272,371 18,210,834
FERC FORM No. 1 (ED. 12-96)Page 120-121
Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)
Net Increase (Decrease) in Cash and Cash Equivalents
Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and
83)
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at End of Period
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: DepreciationAndDepletion
Includes depreciation expense associated with transportation equipment and finance lease assets of $27,117,805 and $18,570,041 during the years ended December 31,2021 and 2020, 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
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 Serviceinvolving 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 briefexplanation 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 giventhese 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 duplicatethe disclosures contained in the most recent FERC Annual Report may be omitted.8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent.Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the
preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes
resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant changesince 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 aboveinstructions, such notes may be included herein.
Organization and OperationsPacifiCorp is a United States regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp
owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other
utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp 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").
Summary of Significant Accounting PoliciesBasis 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 acomprehensive 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 andinclude 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 subsidiariesas 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 ontransactions with equity investees as would be required under GAAP. The accounting treatment described above has no effect on net income or the combined retained earnings of PacifiCorp and undistributed earnings of subsidiaries.
Costs of Removal
Estimated removal costs that are recovered through approved depreciation rates, but that do not meet the requirements of a legal asset retirement obligation ("ARO") are reflected in the cost of removal regulatory liability under GAAP and asaccumulated 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 withFERC guidance. For GAAP, unrecognized tax benefits associated with temporary differences are reflected as other liabilities while for FERC the income tax impact of uncertain tax positions associated with temporary differences are reflectedin 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 arisingfrom 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 capitalizationunder GAAP. In accordance with FERC guidance, PacifiCorp continues to report the components of net periodic benefit costs for pension and PBOP on the statement of income and follows GAAP guidance to capitalize only the service costcomponent 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 reportedamounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; certain assumptions made in accounting for pension and other postretirement benefits; AROs; income taxes; unbilled revenue;
valuation of certain financial assets and liabilities, including derivative contracts; and accounting for loss contingencies, including those related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") described in Note 14. Actualresults 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 isprobable 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 periodsthe 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 orquoted 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 totransfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value.Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or futuremarket exchange.
Cash Equivalents and Restricted Cash and Cash Equivalents and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability isrestricted 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 decommissioningfunds.Cash and cash equivalents and restricted cash and cash equivalents consist of the following amounts as of December 31 (in millions):
2021 2020
Cash (131)$1 $11
Other special funds (128)7 7
Temporary cash investments (136)151 —
Total cash and cash equivalents and restricted cash and cash equivalents 159 18
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, 2021 and2020, 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 theallowance for credit losses for trade receivables, PacifiCorp primarily utilizes credit loss history. However, PacifiCorp may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate fromhistorical 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 (inmillions):
2021 2020
Beginning balance $17 $8
Charged to operating costs and expenses, net 13 18
Write-offs, net (12)(9)
Ending balance $18 $17
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 arerecorded 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 reflectoffsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are notmarked-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 inclusionin 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 completedperiodically 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 recordedthrough 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 iscomputed 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 usefullives 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 AROliability 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 tothe 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. Thedifference 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 atriggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the
estimated recoverable amounts, the appropriate FERC accounts are adjusted to write down the asset to the estimated fair value and any resulting impairment loss is reflected on the Statement of Income. The impacts of regulation are considered whenevaluating 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 leasesgenerally 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 constructionor maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting
rent to reflect changes in price indices. PacifiCorp does not include options in its lease calculations unless there is a triggering event indicating PacifiCorp is reasonably certain to exercise the option. PacifiCorp's accounting policy is to not recognize
right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associatedwith 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 canyield 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 PacifiCorpexpects 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 haveperformance 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 generallydue 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 separateperformance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and classified in accordance with FERC accounting standards.
Unamortized Debt, Premiums, Discounts and Debt Issuance Costs
Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
Income Taxes
Berkshire Hathaway includes PacifiCorp in its United States federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for income taxes has been computed on a stand-alone basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected toreverse. 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 associatedwith certain property-related basis differences and other various differences that PacifiCorp deems probable to be passed on to its customers in most state jurisdictions are charged or credited directly to a regulatory asset or liability and will be includedin regulated rates when the temporary differences reverse or as otherwise approved by PacifiCorp's various regulatory commissions. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense.Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established whennecessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.
Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions.
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 benefitsrecognized 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 of events occurring after December 31, 2021 up to February 25, 2022, the date that PacifiCorp's GAAP financial statements were filed with the United States Securities and Exchange Commission and has updatedsuch evaluation for disclosure purposes through April 13, 2022. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.Net Utility Plant
The average depreciation and amortization rate applied to depreciable utility plant was 3.5% and 4.1% for the years ended December 31, 2021 and 2020, respectively, including the impacts of $23 million in 2021 related to Utah’s, Wyoming’s andWashington’s shares of incremental decommissioning costs for certain coal-fueled units, accelerated depreciation totaling $376 million in 2020 for Utah's share of certain thermal plant units in 2020, including Cholla Unit No. 4 in 2020 for whichoperations ceased in December 2020; Oregon's and Idaho's shares of Cholla Unit No. 4 in 2020; and Oregon's share of certain retired wind equipment associated with wind repowering projects in 2020. As discussed in Note 9, existing regulatoryliabilities primarily associated with the Utah Sustainability and Transportation Plan and the Tax Cuts and Jobs Act enacted on December 22, 2017, were utilized to accelerate depreciation of these assets.
Effective January 1, 2021, PacifiCorp revised its depreciation rates based on its recent depreciation study that was approved by its state regulatory commissions, other than in California. The approved depreciation rates resulted in an increase indepreciation expense of approximately $158 million for the year ended December 31, 2021, as compared to the year ended December 31, 2020, based on historical utility plant balances and including depreciation of certain coal-fueled generating units
in Washington over accelerated periods.
Jointly Owned Utility FacilitiesUnder 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 andexpenses on the Statement of Income include PacifiCorp's share of the expenses of these facilities.The amounts shown in the table below represent PacifiCorp's share in each jointly owned facility included in net utility plant as of December 31, 2021 (dollars in millions):
PacifiCorp Share Facility in Service Accumulated Depreciation andAmortization Construction Work-in-Progress
Jim Bridger Nos. 1 - 4 67 %$1,528 $836 $15
Hunter No. 1 94 489 219 8
Hunter No. 2 60 306 137 1
Wyodak 80 477 270 8
Colstrip Nos. 3 and 4 10 260 164 3
Hermiston 50 185 102 —
Craig Nos. 1 and 2 19 369 184 —
Hayden No. 1 25 77 48 —
Hayden No. 2 13 44 28 —
Transmission and distribution facilities Various 879 320 118
Total $4,614 $2,308 $153
LeasesThe following table summarizes PacifiCorp's leases recorded on the Comparative Balance Sheet as of December 31 (in millions):
2021 2020
Right-of-use assets:
Operating leases $11 $11
Finance leases 13 18
Total right-of-use assets $24 $29
Lease liabilities:
Operating leases $11 $11
Finance leases 12 18
Total lease liabilities $23 $29
The following table summarizes PacifiCorp's lease costs for the years ended December 31 (in millions):
2021 2020
Variable $56 $60
Operating 3 3
Finance:
Amortization 5 2
Interest 2 2
Short-term 3 1
Total lease costs $69 $68
Weighted-average remaining lease term (years):
Operating leases 12.7 13.9
Finance leases 10.1 8.4
Weighted-average discount rate:
Operating leases 3.7 %3.8 %
Finance leases 11.1 %10.5 %
Cash payments associated with operating and finance lease liabilities approximated lease cost for the years ended December 31, 2021 and 2020.
PacifiCorp has the following remaining lease commitments as of December 31, 2021 (in millions):
Operating Finance Total
2022 $3 $3 $6
2023 2 2 4
2024 1 2 3
2025 1 2 3
2026 1 2 3
Thereafter 6 10 16
Total undiscounted lease payments 14 21 35
Less - amounts representing interest (3)(9)(12)
Lease liabilities $11 $12 $23
Regulatory MattersRegulatory Assets
PacifiCorp had regulatoryassets not earninga returnon investmentof$720millionand$704million asofDecember31 2021and 2020 respectively
PacifiCorp had regulatory assets not earning a return on investment of $720 million and $704 million as of December 31, 2021 and 2020, respectively.Short-term Debt and Credit FacilitiesThe following table summarizes PacifiCorp's availability under its credit facilities as of December 31 (in millions):
2021:
Credit facilities $1,200
Less:
Short-term debt —
Tax-exempt bond support (218)
Net credit facilities $982
2020:
Credit facilities $1,200
Less:
Short-term debt (93)
Tax-exempt bond support (218)
Net credit facilities $889
As of December 31, 2021, 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 2024 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which supports PacifiCorp's commercial paper program and certain seriesof its tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its seniorunsecured long-term debt securities. As of December 31, 2021, PacifiCorp did not have any commercial paper borrowings outstanding. As of December 31, 2020, PacifiCorp had $93 million of commercial paper outstanding with a weighted averageinterest rate of 0.16%.
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.
As of December 31, 2021 and 2020, PacifiCorp had $19 million and $11 million, respectively, of fully available letters of credit issued under committed arrangements in support of certain transactions required by third parties and generally have
provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.
Long-term Debt
PacifiCorp's long-term debt generally includes provisions that allow PacifiCorp to redeem the first mortgage bonds in whole or in part at any time through the payment of a make-whole premium. Variable-rate tax-exempt bond obligations are generallyredeemable at par value.
PacifiCorp currently has regulatory authority from the Oregon Public Utility Commission and the Idaho Public Utilities Commission to issue an additional $2.0 billion of long-term debt. PacifiCorp must make a notice filing with the WashingtonUtilities and Transportation Commission prior to any future issuance. PacifiCorp currently has an effective shelf registration statement filed with the United States Securities and Exchange Commission to issue an indeterminate amount of first mortgagebonds 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 $31 billion of PacifiCorp's eligible property (based on original cost) was subject to the lienof the mortgage as of December 31, 2021.
In November 2021, PacifiCorp exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed $450 million of its 2.95% Series First Mortgage Bonds that was originally due February 2022.As of December 31, 2021, the annual principal maturities of long-term debt for 2022 and thereafter are as follows (in millions):
Long-term Debt
2022 $155
2023 449
2024 591
2025 302
2026 100
Thereafter 7,200
Total $8,797
Unamortized discount (24)
Total $8,773
Income TaxesIncome tax (benefit) expense consists of the following for the years ended December 31 (in millions):
2021 2020
Current:
Federal $(161)$11
State 6 30
Total $(155)$41
Deferred:
Federal 34 (120)
State 42 2
Total $76 $(118)
Investment tax credits (2)(1)
Total income tax benefit $(81)$(78)
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:
2021 2020
Federal statutory income tax rate 21 %21 %
State income taxes, net of federal income tax benefit 4 3
Effects of ratemaking (14)(22)
Federal income tax credits (20)(14)
Other (1)—
Effective income tax rate (10)%(12)%
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 producedand sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.
Effects of ratemaking is primarily attributable to activity associated with excess deferred income taxes. Excess deferred income tax amortization, net of deferrals, was $112 million for 2021, including the use of $4 million to amortize certain regulatoryasset balances in Wyoming and Idaho. Excess deferred income tax amortization, net of deferrals, was $132 million for 2020, including the use of $118 million to accelerate depreciation of certain retired equipment and to amortize certain regulatorybalances in Idaho, Oregon and Utah.
The net deferred income tax liability consists of the following as of December 31 (in millions):
2021 2020
Deferred income tax assets:
Regulatory liabilities $404 $442
Employee benefits 68 93
State carryforwards 73 73
Loss contingencies 34 35
Asset retirement obligations 73 65
Other 49 69
$701 $777
Deferred income tax liabilities:
Property, plant and equipment (3,198)(3,061)
Regulatory assets (332)(343)
Other (50)(22)
(3,580)(3,426)
Net deferred income tax liability $(2,879)$(2,649)
The following table provides PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December 31, 2021 (in millions):
State
Net operating loss carryforwards $1,138
Deferred income taxes on net operating loss carryforwards $53
Expiration dates 2023 - 2032
Tax credit carryforwards $20
Expiration dates 2022 - indefinite
The United States Internal Revenue Service has closed or effectively settled its examination of PacifiCorp's income tax returns through December 31, 2013. The statute of limitations for PacifiCorp's state income tax returns have expired throughDecember 31, 2011, with the exception of Idaho, where the statute has expired through December 31, 2017, for all adjustments other than federal audit adjustments. The statute of limitations expiring for state filings may not preclude the state fromadjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.Employee Benefit PlansPacifiCorp 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 trusteepension 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 January 1, 2017, non-union employee participants with a cash balance benefit in the Retirement Plan are no longer eligible to receive pay credits in their cash balance formula. In general forunion 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 RetirementPlan participants continue to earn benefits under the Retirement Plan based on the employee's years of service and a final average pay formula. The SERP was closed to new participants as of March 21, 2006 and froze future accruals for activeparticipants 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 2021 as a result of the amount of lump sum distributions in the Retirement Plan during 2021 exceeding the service and interest cost threshold. This resulted in an interim July 31, 2021 remeasurement ofthe 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 year ended December 31, 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 periodbeginning after the first year in which they occur.
Net periodic benefit cost (credit) for the plans included the following components for the years ended December 31 (in millions):
Pension Other Postretirement
2021 2020 2021 2020
Service cost $— $— $2 $2
Interest cost 29 36 7 9
Expected return on plan assets (51)(56)(9)(14)
Settlement 6 — — —
Net amortization 21 18 1 3
Net periodic benefit cost (credit)$5 $(2)$1 $—
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
2021 2020 2021 2020
Plan assets at fair value, beginning of year $1,064 $1,036 $327 $334
Employer contributions 5 5 1 —
Participant contributions — — 6 4
Actual return on plan assets 109 124 14 15
Settlement (52)— — —
Benefits paid (68)(101)(24)(26)
Plan assets at fair value, end of year $1,058 $1,064 $324 $327
(1)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
2021 2020 2021 2020
Benefit obligation, beginning of year $1,202 $1,167 $307 $304
Service cost — — 2 2
Interest cost 29 36 7 9
Participant contributions — — 6 4
Actuarial (gain) loss (63)100 (10)14
Settlement (52)— — —
Benefits paid (68)(101)(24)(26)
Benefit obligation, end of year $1,048 $1,202 $288 $307
Accumulated benefit obligation, end of year $1,048 $1,202
(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
2021 2020 2021 2020
Plan assets at fair value, end of year $1,058 $1,064 $324 $327
Less - Benefit obligation, end of year 1,048 1,202 288 307
d d
(1)
(2)
(1)
Funded status $10 $(138)$36 $20
Amounts recognized on the Comparative Balance Sheet:
Other special funds (128)$63 $8 $36 $20
Miscellaneous current and accrued liabilities (242)(4)(4)— —
Accumulated provision for pension and benefits (228.3)(49)(142)— —
Amounts recognized $10 $(138)$36 $20
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 policiesincluded in the Rabbi trust, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $69 million and $61 million as of December 31, 2021 and 2020, respectively. These assets are notincluded in the plan assets in the above table, but are reflected primarily in other investments as of December 31, 2021 and 2020, respectively, on the Comparative Balance Sheet.
As of December 31, 2021, 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
2021 2020 2021 2020
Net loss (gain)$298 $455 $(28)$(13)
Regulatory deferrals 11 2 2 3
Total $309 $457 $(26)$(10)
(1)Includes $9 million of deferrals associated with 2021 pension settlement losses..A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2021 and 2020 is as follows (in millions):
Regulatory Asset
Accumulated Other
Comprehensive Loss Total
Pension
Balance, December 31, 2019 $422 $21 $443
Net loss arising during the year 27 5 32
Net amortization (17)(1)(18)
Total 10 4 14
Balance, December 31, 2020 432 25 457
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
Regulatory Liability
Other Postretirement
Balance, December 31, 2019 $(20)
Net loss arising during the year 13
Net amortization (3)
Total 10
Balance, December 31, 2020 (10)
Net gain arising during the year (15)
Net amortization (1)
Total (16)
Balance, December 31, 2021 (26)
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
Pension Other Postretirement
2021 2020 2021 2020
Benefit obligations as of December 31:
Discount rate 2.90 %2.50 %2.90 %2.50 %
Rate of compensation increase N/A N/A N/A N/A
Interest crediting rates for cash balance plan - non-union
2019 N/A N/A N/A N/A
2020 N/A 2.27 %N/A N/A
2021 0.82 %0.82 %N/A N/A
2022 0.88 %0.82 %N/A N/A
2023 0.88 %2.00 %N/A N/A
2024 and beyond 1.90 %2.00 %N/A N/A
Interest crediting rates for cash balance plan - union
2019 N/A N/A N/A N/A
2020 N/A 2.16 %N/A N/A
2021 1.42 %1.42 %N/A N/A
2022 1.94 %1.42 %N/A N/A
2023 1.94 %2.40 %N/A N/A
2024 and beyond 2.30 %2.40 %N/A N/A
Net periodic benefit cost for the years ended December 31:
Discount rate 2.50 %3.25 %2.50 %3.20 %
Expected return on plan assets 6.00 6.50 2.90 4.92
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 2022. 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 amountsfrom time to time in order to achieve certain funding levels specified under the PPA of 2006. PacifiCorp evaluates a variety of factors, including funded status, income tax laws and regulatory requirements, in determining contributions to its otherpostretirement benefit plan.The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2022 through 2026 and for the five years thereafter are summarized below (in millions):
Projected Benefit Payments
Pension Other Postretirement
2022 $96 $24
(1)
2022 $96 $24
2023 85 23
2024 79 22
2025 76 21
2026 71 20
2027-2031 304 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 aremanaged to targets consistent with prudent risk tolerances. The plans retain outside investment advisors to manage plan investments within the parameters outlined by the Berkshire Hathaway Energy Company Investment Committee. The investmentportfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments.
In 2020, the assets of the PacifiCorp Master Retirement Trust were transferred into the BHE Master Retirement Trust.
The target allocations (percentage of plan assets) for PacifiCorp's pension and other postretirement benefit plan assets are as follows as of December 31, 2021:
Pension Other Postretirement
%%
Debt securities 55 - 85 70 - 80
Equity securities 25 - 35 20 - 30
Other 0 - 10 0 - 1
(1)The trust in which the PacifiCorp Retirement Plan is invested includes a separate account that is used to fund benefits for the other postretirement benefit plan. In addition to this separate account, the assets for the other postretirement benefit plan are held in Voluntary Employees' Beneficiary Association("VEBA") trusts, each of which has its own investment allocation strategies. Target allocations for the other postretirement benefit plan include the separate account of the Retirement Plan trust and the VEBA trusts.
(2)For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities.Fair Value Measurements
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit pension plan (in millions):
Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Total
As of December 31, 2021:
Cash equivalents $— $15 $— $15
Debt securities:
United States government obligations 51 — — 51
Corporate obligations — 299 — 299
Municipal obligations — 22 — 22
Agency, asset and mortgage-backed obligations — 38 — 38
Equity securities:
United States 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
As of December 31, 2020:
Cash equivalents $— $32 $— $32
Debt securities:
United States government obligations 14 — — 14
Corporate obligations — 231 — 231
Municipal obligations — 21 — 21
Equity securities:
United States companies 91 — — 91
Total assets in the fair value hierarchy $105 $284 $— 389
Investment funds measured at net asset value 587
Limited partnership interests measured at net asset value 88
Investments at fair value $1,064
(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 59% and 41%, respectively for 2021 and 78% and 22%, respectively, for 2020, and are invested in United States and international securities ofapproximately 84% and 16%, respectively, for 2021 and 74% and 26%, respectively, for 2020.
(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, 2021:
Cash equivalents $4 $1 $— $5
Debt securities:
United States government obligations 24 — — 24
Corporate obligations — 79 — 79
Municipal obligations — 15 — 15
Agency, asset and mortgage-backed obligations — 35 — 35
Equity securities:
United States 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
As of December 31, 2020:
Cash equivalents $8 $1 $— $9
Debt securities:
United States government obligations 11 — — 11
Corporate obligations — 86 — 86
Municipal obligations — 16 — 16
Agency, asset and mortgage-backed obligations — 44 — 44
Equity securities:
United States companies 4 — — 4
Total assets in the fair value hierarchy $23 $147 $— 170
Investment funds measured at net asset value 153
Limited partnership interests measured at net asset value 4
Investments at fair value $327
(1)Refer to Note 13 for additional discussion regarding the three levels of the fair value hierarchy.
(1)(1)
(2)
(2)
(1)(1)(1)
(2)
(3)
(2)
(3)
(1)(1)(1)
(2)
(3)
(2)
(3)
()g g y
(2)Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 39% and 61%, respectively, for 2021 and 38% and 62%, respectively, for 2020, and are invested in United States and international securities ofapproximately 90% and 10%, respectively, for 2021 and 93% and 7%, respectively, for 2020.
(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 onobservable 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 assetvalue per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.
Multiemployer and Joint Trustee Pension Plans
PacifiCorp contributes to the PacifiCorp/IBEW Local 57 Retirement Trust Fund ("Local 57 Trust Fund") (plan number 001) and its subsidiary, Energy West Mining Company, previously contributed to the UMWA 1974 Pension Plan (plan number 002).Contributions to these pension plans are based on the terms of collective bargaining agreements.As a result of the Utah Mine Disposition and UMWA labor settlement, PacifiCorp's subsidiary, Energy West Mining Company, triggered involuntary withdrawal from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceasedperforming 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 regulatoryasset. PacifiCorp has subsequently revised its estimate due to changes in facts and circumstances for a withdrawal occurring by July 2015. As communicated in a letter received in August 2016, the plan trustees determined a withdrawal liability of $115
million. Energy West Mining Company began making installment payments in November 2016 and has the option to elect a lump sum payment to settle the withdrawal obligation. The ultimate amount paid by Energy West Mining Company to settle theobligation 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 andalthough 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 andplan 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 WestMining Company's withdrawal from the UMWA 1974 Pension Plan. If participating employers withdraw from a multiemployer plan, the unfunded obligations of the plan may be borne by the remaining participating employers.
The following table presents PacifiCorp's participation in individually significant joint trustee and multiemployer pension plans for the years ended December 31 (dollars in millions):
PPA of 2006 zone status or plan funded status percentage for planyears beginning July 1,Contributions
Plan name
Employer Identification Number 2021 2020 Funding improvement plan Surcharge imposed under PPA of2006 2021 2020 Year contributions to plan exceeded more than 5% oftotal contributions
Local 57 Trust Fund 87-0640888 At least 80%At least 80%None None $6 $6 2019, 2018
(1)PacifiCorp's minimum contributions to the plan are based on the amount of wages paid to employees covered by the Local 57 Trust Fund collective bargaining agreements, subject to ERISA minimum funding requirements.
(2)For the Local 57 Trust Fund, information is for plan years beginning July 1, 2019 and 2018. Information for the plan year beginning July 1, 2020 is not yet available.
The current collective bargaining agreements governing the Local 57 Trust Fund expire in 2023.
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, 2021, all participants receive contributions based on eligible pre-tax annualcompensation. Contributions cannot exceed the maximum allowable for tax purposes. PacifiCorp's contributions to the 401(k) Plan were $40 million and $41 million for the years ended December 31, 2021 and 2020, respectively.Asset Retirement ObligationsPacifiCorp 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 discountedat a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.PacifiCorp does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain transmission, distribution and other assets cannotcurrently 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 $1,187 million and $1,125 million as of December 31, 2021 and 2020, respectively.
The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 31 (in millions):
2021 2020
Beginning balance $270 $257
Change in estimated costs 40 (11)
Additions — 25
Retirements (15)(10)
Accretion 9 9
Ending balance $304 $270
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 ofthe 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.
Risk Management and Hedging ActivitiesPacifiCorp 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 inits 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 wholesaleelectricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage,and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.
PacifiCorp has established a risk management process that is designed to identify, assess, manage and report each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodityderivative 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 swapsor 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 tochanges 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 grossbasis, and reconciles those amounts to the amounts presented on a net basis on the Comparative Balance Sheet (in millions):
Current Assets Long-term Assets Current Liabilities Long-term Liabilities Total
As of December 31, 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
As of December 31, 2020
Not designated as hedging contracts :
Commodity assets $29 $6 $1 $— $36
Commodity liabilities (2)— (23)(28)(53)
Total 27 6 (22)(28)(17)
Total derivatives 27 6 (22)(28)(17)
Cash collateral receivable — — 15 9 24
Total derivatives - net basis $27 $6 $(7)$(19)$7
(1)PacifiCorp's commodity derivatives are generally included in rates. As of December 31, 2021 a regulatory liability of $53 million was recorded related to the net derivative asset of $53 million. As of December 31, 2020 a regulatory asset of $17 million was recorded related to the net derivative liability of$17 million.
(1)
(1)(2)
(1)
(1)
The following table reconciles the beginning and ending balances of PacifiCorp's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified toearnings for the years ended December 31 (in millions):
2021 2020
Beginning balance $17 $62
Changes in fair value recognized in regulatory assets (171)(11)
Net (losses) gains reclassified to operating revenue (23)3
Net gains (losses) reclassified to energy costs 124 (37)
Ending balance $(53)$17
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 2021 2020
Electricity purchases (sales), net Megawatt hours 2 (1)
Natural gas purchases Decatherms 106 100
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 tothe 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 eachsignificant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterpartycredit 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 underthese 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 ofthe 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, 2021, 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 $37 million and $51 million as of December 31, 2021 and 2020, respectively, for which PacifiCorp had postedcollateral of $5 million and $24 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, 2021 and 2020, PacifiCorp would havebeen required to post $23 million and $25 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or otherfactors.
Fair Value MeasurementsThe 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 hasvarious 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 thelowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset orliability 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 informationavailable, including its own data.The following table presents PacifiCorp's financial assets and liabilities recognized on the Comparative Balance Sheet and measured at fair value on a recurring basis (in millions):
Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Other Total
As of December 31, 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)
As of December 31, 2020
Assets:
Commodity derivatives $— $36 $— $(3)$33
Money market mutual funds 6 — — — 6
Investment funds 24 — — — 24
$30 $36 $— $(3)$63
Liabilities - Commodity derivatives $— $(53)$— $27 $(26)
(1)Represents netting under master netting arrangements and a net cash collateral receivable of $5 million and $24 million as of December 31, 2021 and 2020, respectively.
Derivative contracts are recorded on the Comparative Balance Sheet as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP.When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forwardprice 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, whenavailable, 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 periodsreflect 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 thatare not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is afunction 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 hedgingactivities.
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 thefair 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 thepresent 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 theseinstruments at market rates. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt as of December 31 (in millions):
2021 2020
Carrying Value
Fair Value
Carrying Value
Fair Value
Long-term debt $8,773 $10,374 $8,649 $10,995
Commitments and ContingenciesLegal 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 onits 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.
California and Oregon 2020 Wildfires
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damage, personal injuries and loss of life and widespread power outages inOregon 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 andare being conducted by various entities, including the United States Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged byPacifiCorp.
Several lawsuits have been filed in Oregon and California, including a putative class action complaint in Oregon, on behalf of citizens and businesses who suffered damages from fires allegedly caused by PacifiCorp. Additionally, multiple insurancecarriers 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 be made following comprehensive investigations andlitigation processes.
(1)
(2)
(2)
In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages without the utility being found negligent and regardless of fault. California law also permits inversecondemnation 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 topay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could nevertheless be found liable for all damages proximately caused by negligence, including property and naturalresource damage; fire suppression costs; personal injury and loss of life damages; and interest.
PacifiCorp has accrued $136 million as its best estimate of the potential losses net of expected insurance recoveries associated with the 2020 Wildfires that are considered probable of being incurred. These accruals include estimated losses for firesuppression costs, property damage, personal injury damages and loss of life damages. It is reasonably possible that PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range ofpossible additional losses that could be incurred due to the number of properties and parties involved. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover at least a portion ofthe losses.Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid wastedisposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.
Hydroelectric Relicensing
PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA establishes a processfor 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 fromPacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the FERC license to a third-party dam removal
entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.
In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four mainstem Klamath dams from PacifiCorp to the KRRC. The FERC approved partial transfer of the Klamath license in a July 2020order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and itscustomers. 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 andKRRC to file a new license transfer application to remove PacifiCorp from the license for the Klamath Hydroelectric Project and add the States and KRRC as co-licensees for the purposes of surrender. In addition, the MOA provides for additionalcontingency funding of $45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to
ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In June 2021, the FERC approved transfer of the four mainstem Klamath dams from PacifiCorp to theKRRC and the States as co-licensees. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions conditionally approved the required property transfer applications. In August 2021, PacifiCorp notified the Public ServiceCommission of Utah of the property transfer, however no formal approval is required in Utah. The transfer will be effective within 30 days following the issuance of a license surrender from the FERC for the project, which remains pending.
As of December 31, 2021, PacifiCorp's assets included $14 million of costs associated with the Klamath hydroelectric system's mainstem dams and the associated relicensing and settlement costs, which are being depreciated and amortized inaccordance with state regulatory approvals in Utah, Wyoming and Idaho through December 31, 2022.
Hydroelectric Commitments
Certain of PacifiCorp's hydroelectric licenses contain requirements for PacifiCorp to make certain capital and operating expenditures related to its hydroelectric facilities, which are estimated to be approximately $193 million over the next 10 years.
Included in these estimates are commitments associated with the KHSA.Commitments
PacifiCorp has the following firm commitments that are not reflected on the Comparative Balance Sheet. Minimum payments as of December 31, 2021 are as follows (in millions):
2022 2023 2024 2025 2026 2027 and Thereafter Total
Contract type:
Purchased electricity contracts -
commercially operable $372 $223 $212 $194 $192 $2,190 $3,383
Fuel contracts 586 366 310 134 129 468 1,993
Construction commitments 51 106 27 — — — 184
Transmission 108 106 90 62 51 431 848
Easements 20 20 19 19 19 518 615
Maintenance, service and —
other contracts 113 56 53 52 51 253 578
Total commitments $1,250 $877 $711 $461 $442 $3,860 $7,601
Purchased Electricity Contracts - Commercially Operable
As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-term purchases and exchange agreements. PacifiCorp has several PPAs with solar-powered or wind-powered generating facilities that are not included in
the table above as the payments are based on the amount of energy generated and there are no minimum payments. Certain of these PPAs qualify as leases as described in Note 2. Refer to Note 5 for variable lease costs associated with these leasecommitments.
Included in the minimum fixed annual payments for purchased electricity above are commitments to purchase electricity from several hydroelectric systems under long-term arrangements with public utility districts. These purchases are made on a"cost-of-service" basis for a stated percentage of system output and for a like percentage of system operating expenses and debt service. These costs are included in operations expenses on the Statement of Income. PacifiCorp is required to pay its
portion of operating costs and its portion of the debt service, whether or not any electricity is produced. These arrangements accounted for less than 5% of PacifiCorp's 2021 and 2020 energy sources.
Fuel Contracts
PacifiCorp has "take or pay" coal and natural gas contracts that require minimum payments.
Construction Commitments
PacifiCorp's construction commitments included in the table above relate to firm commitments and include costs associated with certain generating plant, transmission, and distribution projects.
Transmission
PacifiCorp has contracts for the right to transmit electricity over other entities' transmission lines to facilitate delivery to PacifiCorp's customers.
Easements
PacifiCorp has non-cancelable easements for land on which certain of its assets, primarily wind-powered generating facilities, are located.
Guarantees
PacifiCorp has entered into guarantees as part of the normal course of business and the sale or transfer of certain assets. These guarantees are not expected to have a material impact on PacifiCorp's financial results.Preferred StockIn 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.Common Shareholder's EquityThrough 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 wouldreduce PacifiCorp's common equity below specified percentages of defined capitalization. As of December 31, 2021, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to PPW Holdings or BHE without prior
state regulatory approval to the extent that it would reduce PacifiCorp's common equity below 44% of its total capitalization, excluding short-term debt and current maturities of long-term debt. As of December 31, 2021, PacifiCorp's actual commonequity percentage, as calculated under this measure, was 54%, and PacifiCorp would have been permitted to dividend $3.2 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 byMoody's Investor Service, as indicated by two of the three rating services. As of December 31, 2021, 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.
Supplemental Cash Flow DisclosuresThe summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
2021 2020
Interest paid, net of amounts capitalized $395 $348
Income taxes (received) paid, net $(128)$98
Supplemental disclosure of non-cash investing and financing activities:
Accounts payable related to utility plant additions $254 $344
(1)PacifiCorp is party to a tax-sharing agreement and is part of the Berkshire Hathaway United States federal income tax return. Amounts substantially represent income taxes paid to BHE.
FERC FORM No. 1 (ED. 12-96)
Page 122-123
(1)
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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)
UnrealizedGains andLosses on
Available-For-
Sale Securities(b)
MinimumPensionLiability
Adjustment
(net amount)(c)
ForeignCurrency
Hedges
(d)
OtherAdjustments(e)
Other Cash
Flow
HedgesInterestRateSwaps
(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 219at Beginning ofPreceding Year (15,916,633)(15,916,633)
2
Preceding Quarter/Yearto Date Reclassificationsfrom Account 219 to NetIncome
786,253 786,253
3 Preceding Quarter/Yearto Date Changes in FairValue (3,967,108)(3,967,108)
4 Total (lines 2 and 3)(3,180,855)(3,180,855)739,052,383 735,871,528
5 Balance of Account 219at End of PrecedingQuarter/Year (19,097,488)(19,097,488)
6 Balance of Account 219at Beginning of CurrentYear (19,097,488)(19,097,488)
7
Current Quarter/Year toDate Reclassificationsfrom Account 219 to NetIncome
1,024,956 1,024,956
8 Current Quarter/Year toDate Changes in FairValue 940,379 940,379
9 Total (lines 7 and 8)1,965,335 1,965,335 888,042,944 890,008,279
10
Balance of Account 219
at End of CurrentQuarter/Year (17,132,153)(17,132,153)
FERC FORM No. 1 (NEW 06-02)Page 122 (a)(b)
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.
Line
No.
Classification
(a)
Total Company For
the Current
Year/Quarter Ended(b)
Electric
(c)
Gas
(d)
Other (Specify)
(e)
Other (Specify)
(f)
Other(Specify)(g)
Common
(h)
1
2
3 31,384,556,251 31,384,556,251
4 23,611,803 23,611,803
5
6 713,653,419 713,653,419
7
8 32,121,821,473 32,121,821,473
9
10 14,811,003 14,811,003
11 1,131,734,692 1,131,734,692
12 156,468,483 156,468,483
13 33,424,835,651 33,424,835,651
14 11,632,340,710 11,632,340,710
15 21,792,494,941 21,792,494,941
16
17
18 10,763,643,074 10,763,643,074
19
20
21 725,504,660 725,504,660
22 11,489,147,734 11,489,147,734
23
24
25
26
27
28
29
30
31
32 143,192,976 143,192,976
33 11,632,340,710 11,632,340,710
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 forDepreciation, Amortization, &Depletion
Net Utility Plant (13 less 14)
DETAIL OF ACCUMULATED
PROVISIONS FOR
DEPRECIATION, AMORTIZATIONAND DEPLETION
In Service:
Depreciation
Amortization and Depletion ofProducing Natural Gas Land andLand 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 (NaturalGas)
Amortization of Plant AcquisitionAdjustment
Total Accum Prov (equals 14)(22,26,30,31,32)
FERC FORM No. 1 (ED. 12-89)Page 200-201
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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.
LineNo.Description of item(a)
Balance Beginning of
Year
(b)
Changes during Year
Additions
(c)
Changes during Year
Amortization
(d)
Changes during YearOther Reductions(Explain in a footnote)(e)
Balance End of Year(f)
1 Nuclear Fuel in process of Refinement,Conv, Enrichment & Fab (120.1)
2 Fabrication
3 Nuclear Materials
4 Allowance for Funds Used duringConstruction
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 ofNuclear 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 Materialsin Chemical Processing
18 Nuclear Materials held for Sale (157)
19 Uranium
20 Plutonium
21 Other (Provide details in footnote)
22 TOTAL Nuclear Materials held for Sale
(Total 19, 20, and 21)
FERC FORM No. 1 (ED. 12-89)
Page 202-203
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 toprimary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account foraccumulated depreciation provision. Include also in column (d) distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentativeaccount 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 fromdistribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., andshow in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications.8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such
plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposedjournal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date.
Line
No.
Account
(a)
Balance Beginning ofYear(b)
Additions
(c)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at Endof Year(g)
1 1. INTANGIBLE PLANT
2 (301) Organization
3 (302) Franchise and Consents 209,752,933 5,793,803 123,397 215,423,339
4 (303) Miscellaneous Intangible Plant 844,621,680 63,851,145 17,370,978 (50,388)891,051,459
5 TOTAL Intangible Plant (Enter Total
of lines 2, 3, and 4)1,054,374,613 69,644,948 17,494,375 (50,388)1,106,474,798
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights 91,620,243 119,792 25,083 91,714,952
9 (311) Structures and Improvements 997,012,716 9,768,374 2,171,567 1,004,609,523
10 (312) Boiler Plant Equipment 4,337,648,373 80,058,797 32,020,813 4,385,686,357
11 (313) Engines and Engine-Driven
Generators
12 (314) Turbogenerator Units 941,784,721 12,857,509 6,088,393 948,553,837
13 (315) Accessory Electric Equipment 424,234,732 3,449,193 1,119,818 426,564,107
14 (316) Misc. Power Plant Equipment 30,788,447 1,276,013 347,340 31,717,120
15 (317) Asset Retirement Costs forSteam Production 156,343,007 43,340,623 29,653,867 (6,849,800)163,179,963
16 TOTAL Steam Production Plant(Enter Total of lines 8 thru 15)6,979,432,239 150,870,301 71,426,881 (6,849,800)7,052,025,859
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 forNuclear Production
25 TOTAL Nuclear Production Plant(Enter Total of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights 38,801,763 168,254 38,970,017
28 (331) Structures and Improvements 289,377,697 7,860,898 755,446 296,483,149
29 (332) Reservoirs, Dams, and
Waterways
533,915,462 6,336,330 2,125,768 538,126,024
30 (333) Water Wheels, Turbines, andGenerators 146,463,461 1,385,969 156,893 147,692,537
31 (334) Accessory Electric Equipment 86,921,041 1,833,003 186,803 88,567,241
32 (335) Misc. Power Plant Equipment 2,572,135 589,264 4,044 3,157,355
33 (336) Roads, Railroads, and Bridges 26,317,434 191,537 20,440 26,488,531
34 (337) Asset Retirement Costs forHydraulic Production
35 TOTAL Hydraulic Production Plant
(Enter Total of lines 27 thru 34)1,124,368,993 18,365,255 3,249,394 1,139,484,854
36 D. Other Production Plant
37 (340) Land and Land Rights 52,747,960 75,933 11,578 52,835,471
38 (341) Structures and Improvements 268,960,711 5,879,874 109,833 (11,578)274,719,174
39 (342) Fuel Holders, Products, andAccessories 16,401,063 11,266 16,412,329
40 (343) Prime Movers 3,388,890,852 699,203,488 57,818,172 4,030,276,168
41 (344) Generators 552,922,683 40,649,487 1,848,909 591,723,261
42 (345) Accessory Electric Equipment 402,779,576 56,486,278 2,589,084 456,676,770
43 (346) Misc. Power Plant Equipment 22,571,639 2,626,199 114,590 25,083,248
44 (347) Asset Retirement Costs for
Other Production 48,665,167 2,369,363 3,531,744 47,502,786
44.1 (348) Energy Storage Equipment -
Production
45 TOTAL Other Prod. Plant (EnterTotal of lines 37 thru 44)4,753,939,651 807,301,888 66,012,332 5,495,229,207
46 TOTAL Prod. Plant (Enter Total oflines 16, 25, 35, and 45)(a)12,857,740,883 976,537,444 140,688,607 (6,849,800)(h)13,686,739,920
47 3. Transmission Plant
48 (350) Land and Land Rights 316,648,705 21,300,204 1,073,595 118,120 336,993,434
48.1 (351) Energy Storage Equipment -Transmission
49 (352) Structures and Improvements 307,051,390 49,566,280 29,023 683,000 357,271,647
50 (353) Station Equipment 2,692,741,773 64,329,166 5,682,056 (1,064,696)2,750,324,187
51 (354) Towers and Fixtures 1,342,612,357 175,177,698 382,446 1,517,407,609
52 (355) Poles and Fixtures 1,334,393,967 (g)(79,932,316)3,938,216 98,255 1,250,621,690
53 (356) Overhead Conductors andDevices 1,609,180,590 47,930,029 4,687,905 (98,255)1,652,324,459
54 (357) Underground Conduit 3,857,237 748 3,857,985
55 (358) Underground Conductors and
Devices 9,080,617 9,080,617
56 (359) Roads and Trails 12,146,013 4,545 12,141,468
57 (359.1) Asset Retirement Costs forTransmission Plant 2,528,190 2,528,190
58 TOTAL Transmission Plant (EnterTotal of lines 48 thru 57)(b)7,630,240,839 278,371,809 15,797,786 (263,576)(i)7,892,551,286
59 4. Distribution Plant
60 (360) Land and Land Rights 68,539,032 7,682,973 211,052 6,945 76,017,898
61 (361) Structures and Improvements 126,592,724 9,419,077 24,308 135,987,493
62 (362) Station Equipment 1,152,037,123 52,691,295 6,671,189 381,696 1,198,438,925
63 (363) Energy Storage Equipment –Distribution
64 (364) Poles, Towers, and Fixtures 1,336,560,426 94,203,966 4,841,268 1,425,923,124
65 (365) Overhead Conductors and
Devices 846,200,790 47,757,138 5,580,509 888,377,419
66 (366) Underground Conduit 418,714,601 25,936,468 2,531,355 442,119,714
67 (367) Underground Conductors andDevices 977,356,247 53,452,863 5,083,422 1,025,725,688
68 (368) Line Transformers 1,492,229,942 65,509,751 12,221,635 1,545,518,058
69 (369) Services 906,830,209 51,831,303 1,457,274 957,204,238
70 (370) Meters 251,189,373 21,049,072 7,072,494 265,165,951
71 (371) Installations on Customer
Premises 8,808,014 48,808 56,102 8,800,720
72 (372) Leased Property on CustomerPremises
73 (373) Street Lighting and SignalSystems 62,903,579 2,015,809 1,912,663 63,006,725
74 (374) Asset Retirement Costs forDistribution Plant 1,331,349 1,331,349
75 TOTAL Distribution Plant (Enter Total
of lines 60 thru 74)(c)7,649,293,409 431,598,523 47,663,271 388,641 (j)8,033,617,302
76 5. REGIONAL TRANSMISSION
AND MARKET OPERATION PLANT
77 (380) Land and Land Rights
78 (381) Structures and Improvements
79 (382) Computer Hardware
80 (383) Computer Software
81 (384) Communication Equipment
82
(385) Miscellaneous Regional
Transmission and Market Operation
Plant
83
(386) Asset Retirement Costs for
Regional Transmission and Market
Oper
84
TOTAL Transmission and Market
Operation Plant (Total lines 77 thru
83)
85 6. General Plant
86 (389) Land and Land Rights 23,863,596 (42,505)1,050 1,200 23,821,241
87 (390) Structures and Improvements 267,093,881 9,569,270 4,012,727 272,650,424
88 (391) Office Furniture andEquipment 85,373,133 16,254,845 9,684,033 5,233 91,949,178
89 (392) Transportation Equipment 130,141,333 12,554,339 2,429,256 7,604 140,274,020
90 (393) Stores Equipment 15,715,275 844,648 501,987 16,057,936
91 (394) Tools, Shop and GarageEquipment 63,799,815 3,546,143 2,306,085 (12,024)65,027,849
92 (395) Laboratory Equipment 35,926,482 1,845,361 673,479 37,098,364
93 (396) Power Operated Equipment 208,705,880 9,177,259 2,497,868 215,385,271
94 (397) Communication Equipment 510,180,404 32,075,029 37,662,747 49,575 504,642,261
95 (398) Miscellaneous Equipment 8,670,555 1,456,707 70,091 10,057,171
96 SUBTOTAL (Enter Total of lines 86
thru 95)1,349,470,354 87,281,096 59,839,323 51,588 1,376,963,715
97 (399) Other Tangible Property (d)1,822,901 (k)1,822,901
98 (399.1) Asset Retirement Costs forGeneral Plant 39,748 39,748
99 TOTAL General Plant (Enter Total oflines 96, 97, and 98)(e)1,351,333,003 87,281,096 59,839,323 51,588 (l)1,378,826,364
100 TOTAL (Accounts 101 and 106)30,542,982,747 1,843,433,820 281,483,362 (6,849,800)126,265 32,098,209,670
101 (102) Electric Plant Purchased (SeeInstr. 8)
102 (Less) (102) Electric Plant Sold (SeeInstr. 8)
103 (103) Experimental PlantUnclassified
104 TOTAL Electric Plant in Service(Enter Total of lines 100 thru 103)
(f)30,542,982,747 1,843,433,820 281,483,362 (6,849,800)126,265 (m)32,098,209,670
FERC FORM No. 1 (REV. 12-05)Page 204-207
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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)12,857,740,883
Less: (317) Asset Retirement Costs for Steam Production 15 (b)156,343,007
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)48,665,167
Revised TOTAL Production Plant $12,652,732,709
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)$7,630,240,839
Less: (359.1) Asset Retirement Costs for Transmission Plant 57 (b)2,528,190
Revised TOTAL Transmission Plant $7,627,712,649
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 assetretirement 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)$7,649,293,409
Less: (374) Asset Retirement Costs for Distribution Plant 74 (b)1,331,349
Revised TOTAL Distribution Plant $7,647,962,060
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 ofthe 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)$1,351,333,003
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 $1,349,470,354
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)$1,054,374,613
Revised TOTAL Production Plant 12,652,732,709
Revised TOTAL Transmission Plant 7,627,712,649
Revised TOTAL Distribution Plant 7,647,962,060
Revised TOTAL General Plant 1,349,470,354
(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 $30,332,252,385
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: PolesAndFixturesTransmissionPlantAdditions
Negative addition is due to reduction associated with formal unitization in 2021 of the 500kV Aeolus-Bridger/Anticline transmission line and supporting segments that were placed into service in November 2020 and for which costs were reflected in FERC Account 106, Completed Construction not Classified at December 31, 2020. For purposes of reporting this page as of December 31, 2020, these amounts were allocated to FERC account 355, Poles and Fixtures based on the initial estimation for allocating FERC Account 106 balances but were determined to be appropriately recorded to FERC account 354, Towers and Fixtures, upon completion of the unitization process in 2021.
(h) Concept: ProductionPlant
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(2)
(1)
(2)
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(2)
(3)
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(2)
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(4)
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)$13,686,739,920
Less: (317) Asset Retirement Costs for Steam Production 15 (g)163,179,963
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)47,502,786
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 ofthe asset retirement costs in rates, must remove all asset-retirement-obligations-related cost components from the cost of service supporting its proposed rates.
(i) Concept: TransmissionPlant
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)$7,892,551,286
Less: (359.1) Asset Retirement Costs for Transmission Plant 57 (g)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.
(j) Concept: DistributionPlant
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:
Account (a)Ref. Line No. (Column)Balance End of Year (g)
TOTAL Distribution Plant 75 (g)$8,033,617,302
Less: (374) Asset Retirement Costs for Distribution Plant 74 (g)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.
(k) Concept: OtherTangibleProperty
Account 399.21, Land owned in fee
(l) Concept: GeneralPlant
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:
Account (a)Ref. Line No. (Column)Balance End of Year (g)
TOTAL General Plant 99 (g)$1,378,826,364
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 $1,376,963,715
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 ofthe asset retirement costs in rates, must remove all asset-retirement-obligations-related cost components from the cost of service supporting its proposed rates.
(m) Concept: ElectricPlantInService
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:
Account (a)Ref. Line No. (Column)Balance End. of Year (g)
TOTAL Intangible Plant 5 (g)$1,106,474,798
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 (g)—
(Less) (102) Electric Plant Sold 102 (g)—
(103) Experimental Plant Unclassified 103 (g)—
Revised TOTAL Electric Plant in Service $31,881,804,733
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)
(1)
(1)
(1)
(1)
(1)
(1)
(2)
(1)
(2)
(1)
(2)
(3)
(4)
(1)
(2)
(3)
(4)
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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
Name of Lessee
*(Designationof
Associated
Company)
Description of Property Leased CommissionAuthorization Expiration Date ofLease Balance at End ofYear
41
42
43
44
45
46
47 TOTAL
FERC FORM No. 1 (ED. 12-95)Page 213
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 12/31/2030 284,996
5 Hoggard Substation 02/21/2009 12/31/2025 254,397
6 Oquirrh-Terminal 345kV Transmission Line 02/21/2009 12/31/2024 396,020
7 Bend Service Center 07/06/2010 12/31/2023 2,981,121
8 (a)
126th South Substation 12/22/2010 12/31/2022 547,284
9 Populus Substation 02/28/2011 12/31/2023 254,753
10 Lassen Substation 05/25/2012 12/31/2022 683,318
11 Old Mill Substation 11/30/2012 12/31/2027 1,838,281
12 Chimney Butte-Paradise 230kV Transmission Line 03/11/2013 12/31/2026 598,457
13 Fiddlers Canyon Substation 06/29/2016 12/31/2028 1,136,587
14 (b)
Banfield Substation 12/29/2017 12/31/2025 3,166,188
15 (c)
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
Description and Location of Property Date Originally Included in ThisAccount Date Expected to be used inUtility Service Balance at End of Year
43
44
45
46
47 TOTAL 14,811,003
FERC FORM No. 1 (ED. 12-96)
Page 214
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: ElectricPlantHeldForFutureUseDescription
126th South Substation formerly called Legacy Substation.
(b) Concept: ElectricPlantHeldForFutureUseDescription
Banfield Substation formerly called Gateway Area Substation.
(c) Concept: ElectricPlantHeldForFutureUseDescription
Various dates properties were originally included FERC Account 105. Various dates properties are expected to be placed in service.
FERC FORM No. 1 (ED. 12-96)Page 214
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 ofAccounts).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 32,146,212
3 Field Ai-Field Asset Intelligence Software 21,981,373
4 Cutler Hydro Relicensing 4,712,110
5 2021 VXRail Common Use Virtual Server 2,416,451
6 Weather Forecast & Situational Awareness Software 1,620,410
7 UII Revenue Model Software 1,215,788
8 TIBCO TOM and Upgrade - Software 1,073,910
9 Production:
10 Wind Plant Equipment Purchases 43,788,577
11 Lewis River System Relicensing Implementation 17,901,499
12 Jim Bridger Coal Combustion Residual Flue Gas Desulfurization Pond 4 Stage 1 10,366,538
13 Yale Saddle Dam Seismic Remediation 5,386,515
14 Toketee Dam Rehabilitation Evaluation 5,149,415
15 Wyodak U1 - High Pressure Turbine Rotor Replacement 3,033,162
16 Colstrip U3-4: Dry Waste Disposal System 2,709,869
17 Viva Naughton FERC Production Compliance 2,619,067
18 Soda Hydro Spinning Reserve 1,812,542
19 Gadsby U6 Stage 1 HPT Blade Replacement 1,611,342
20 Yale Dam Spillway Upgrades Evaluation 1,560,958
21 Prospect 3 Hydro - South Fork Flowline Repairs 1,553,317
22 Lifton Pumping Station - Wing Wall Stabilization 1,411,640
23 Bear River Hydro Flood and Structural Assessment Project 1,393,095
24 Bigfork Hydro Fish Screen Rake 1,267,637
25 Huntington Land Application Conversion Development 1,263,377
26 Gadsby U6 Combustor Lining 1,202,078
27 Swift 1 Hydro Spillway Gate Retrofit 1,195,586
28 Hunter U1 HP/IP/LP Turbine Overhaul 1,137,100
29 Hunter U1 Spare Generator Step-Up Transformer Replacement 1,082,931
30 Transmission:
31 Aeolus - Mona 500kV Line 248,497,139
32 Boardman - Hemingway 500kV Line 99,222,992
33 Populus - Hemingway 500kV Line 78,865,833
34 Anticline - Populus 500kV Line 53,602,047
35 Windstar - Shirley Basin 230kV Line 30,477,105
36 Oquirrh - Terminal 345kV Line 17,446,279
37 Sams Valley New 500-230kV Substation 12,654,942
38 Jim Bridger 345-230kV Transformer 2 Upgrade 12,562,698
39 Goshen - Sugarmill - Rigby 161kV Line 10,378,496
Description of Project Construction work in progress - Electric (Account 107)
40 C7 Data Centers, Load Increase 7,615,387
41 Anticline 345 kV Phase Shifting Transformers 6,976,677
42 Future Comp. LLC, 4.3 MW Load 5,020,456
43 Midvalley Substation - Replace Transformer 4,814,085
44 Lebanon 115 kV Loop Reliability Upgrade 3,594,241
45 Outlook Substation - Replace Transformer 3,058,728
46 Path C Transmission Improvements 2,899,610
47 Nickel Mountain Substation - Replace Transformer 2,820,961
48 Madras Purchase 230-69kV (125 MVA) Transformer 2,533,205
49 BLM Permit Right-of-Way in Medford and Grants Pass Areas 2,008,884
50 Q846 Horseshoe Solar, LLC Interconnection 1,894,244
51 Nibley 138/25 kV Transformer and Nibley-Hyrum City Line Rebuild 1,636,559
52 Central Utah High Voltage Mitigation 1,504,525
53 Klamath Falls-Snow Goose 230kV No2 Line TPL 1,471,010
54 Tucker 69 kV Tie Line 1,415,690
55 Price City Tap-Helper 46kV Line Reconductor 2.5 miles 1,347,643
56 2020 Storm Damage Restoration 1,256,885
57 Goshen Substation Install 3rd 345-161kV (700 MVA) Transformer TPL 1,239,537
58 Purchase Spare Transformer 115-69 kV 75-MVA 1,197,767
59 OR BLM Right-of-Way Permit Renewals 10yr Malin-Midpoint 500kV Line 1,164,045
60 Aeolus - Freezeout 230 kV #2 Line 1,103,602
61 Jim Bridger - Goshen 345kV Line Structures Replacement 1,081,915
62 Jordanelle - Midway 138kV Line 1,026,948
63 Capitol-North Bench 138kV Line Rebuild for Wildfire 1,025,620
64 Lyons Loop into Santiam - New Tie Line 1,021,530
65 Distribution:
66 California Distribution Spacer Cable Installation 16,200,512
67 Flint Substation - Construct New 115-12.5kV Substation 10,705,343
68 Lassen Substation - New Substation 8,598,717
69 Utah Advanced Metering Infrastructure 6,864,905
70 Fire High Consequence Area (FHCA) - Rebuild Mountain Dell 11 with Hendrix Cable 6,409,649
71 126th South - New 138-12.47kV Substation 5,898,553
72 Utah Underground Cable Replacement 4,797,616
73 Oregon Distribution Spacer Cable Installation 4,548,580
74 Conser Road - Constuct New 115kV to 20.8 kV Substation 3,528,813
75 Portland Willamette River Crossing Project 3,389,121
76 Stayton, Oregon - Ice/Rain Storm 2-12-2021 2,456,536
77 Wildhorse Resort Phase 2 Load Addition 2,037,621
78 Riverbend Management, Inc, 6.865 MW 1,784,687
79 Corvallis-Washington Way Facilities Relocation -Oregon State University 1,782,986
80 Fire High Consequence Area (FHCA) - Rebuild New Harmony 11 with Hendrix Cable 1,751,995
81 Salt Lake Dept of Airports - 14.7 MW Load 1,614,684
82 Krah USA LLC Service Request 1,582,645
83 Fire High Consequence Area (FHCA) - Rebuild Columbia 11 with Hendrix Cable 1,322,423
84 Albany, Oregon - Ice/Rain Storm 2-12-2021 1,177,220
85 Russellville Distribution Automation Project - FLISR 1,154,910
86 Oregon Energy Storage Project 1,140,121
87 Tiller Substation - Replace/Rebuild Structure & Transformer 1,115,155
88 Shevlin Park Substation Increase Capacity 1,050,829
89 SouthEast Subtation: Install Control Building 1,038,149
90 General:
91 Monarch PAC6 Upgrade and Hardware 8,222,458
92 Lloyd Center Tower - Open Office Plan 3,356,599
93 Astoria Install Fiber Communications 1,401,448
94 North Temple Office ACI Network Build- Common Use 1,065,298
95 Miscellaneous Projects each under $1,000,000 228,687,335
43 Total 1,131,734,692
FERC FORM No. 1 (ED. 12-87)Page 216
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 respondenthas 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 totentatively 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 10,045,111,703 10,045,111,703
2 Depreciation Provisions for Year, Charged to
3 (a)986,207,765 986,207,765
4 (b)0
5
6
7
8
9.1 Account 143, Other accounts receivable:depreciation expense billed to joint owners 219,879 219,879
9.2 Account 182.3, Other Regulatory Assets: assetretirement obligations asset depreciation 22,439,662 22,439,662
9.3 Account 182.3, Other Regulatory Assets:depreciation deferrals 18,222,023 18,222,023
9.4 Transportation depreciation allocated to operations
and maintenance expense based on usage activity 21,897,241 21,897,241
9.5 Account 503, Steam from other sources: Blundell
depreciation 2,486,190 2,486,190
10 1,051,472,760 1,051,472,760
11 Net Charges for Plant Retired:
12 (261,137,398)(261,137,398)
13 (82,206,016)(82,206,016)
14 8,240,250 8,240,250
15 (335,103,164)(335,103,164)
16
17.1 Other Debit or Cr. Items (Describe, details in
footnote):
17.2
Reclassification of accrued removal and spend on
asset retirement obligations that were included in
lines 3 and 13
(5,000,859)(5,000,859)
17.3 Other items include:7,162,634 7,162,634
17.4 Recovery from third parties for asset relocationsand damaged property
17.5 Insurance recoveries
17.6 Adjustments of reserve related to electric plant sold
and/or purchased
17.7 Reclassifications from electric plant
18
19 10,763,643,074 (c)10,763,643,074
Balance Beginning of Year
(403) Depreciation Expense
(403.1) Depreciation Expense for Asset RetirementCosts
(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 3thru 9)
Book Cost of Plant Retired
Cost of Removal
Salvage (Credit)
TOTAL Net Chrgs. for Plant Ret. (Enter Total oflines 12 thru 14)
Other Debit or Cr. Items (Describe, details infootnote):
Book Cost or Asset Retirement Costs Retired
Section B. Balances at End of Year According to Functional Classification
20 4,151,246,191 (d)4,151,246,191
21
22 504,616,809 (e)504,616,809
23
24 397,965,429 (f)397,965,429
25 2,045,302,473 (g)2,045,302,473
26 3,144,745,016 (h)3,144,745,016
27
28 519,767,156 (i)519,767,156
29 10,763,643,074 (j)10,763,643,074
FERC FORM No. 1 (REV. 12-05)
Page 219
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
Regional Transmission and Market Operation
General
TOTAL (Enter Total of lines 20 thru 28)
FOOTNOTE DATA
(a) Concept: DepreciationExpenseExcludingAdjustments
For a discussion on provisions for depreciation that were made during the year, refer to Note 3 of Notes to Financial Statements in this Form No. 1.
(b) Concept: DepreciationExpenseForAssetRetirementCosts
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as a regulatory asset.
(c) Concept: AccumulatedProvisionForDepreciationOfElectricUtilityPlant
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item Ref. Line No.Electric Plant in Service
(a)(Column)(c)
Revised Steam Production $4,062,875,656
Nuclear Production 21 (c)—
Revised Hydraulic Production - Conventional 504,616,809
Hydraulic Production - Pumped Storage 23 (c)—
Revised Other Production 398,251,186
Revised Transmission 2,045,200,003
Revised Distribution 3,143,599,734
Regional Transmission and Market Operation 27 (c)—
Revised General 519,932,106
Revised TOTAL $10,674,475,494
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)$4,151,246,191
Less: Asset retirement obligations related cost components 88,370,535
Revised Steam Production $4,062,875,656
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)$504,616,809
Less: Asset retirement obligations related cost components —
Revised Hydraulic Production - Conventional $504,616,809
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)$397,965,429
Less: Asset retirement obligations related cost components (285,757)
Revised Other Production $398,251,186
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)$2,045,302,473
Less: Asset retirement obligations related cost components 102,470
Revised Transmission $2,045,200,003
In accordance with 18 C.F.R.§35.18 (a-c) a public utility that files a transmission rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an asset retirement obligation on its books, but is not seeking recovery of the asset retirement
costs in rates, must remove all asset retirement obligations-related cost components from the cost of service suppoorting its proposed rates.
(h) Concept: AccumulatedDepreciationDistribution
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item Ref. Line No.Electric Plant in Service
(a)(Column)(c)
Distribution 26 (c)$3,144,745,016
Less: Asset retirement obligations related cost components 1,145,282
Revised Distribution $3,143,599,734
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
(1)
(2)
(3)
(4)
(5)
(6)
(1)
(2)
(3)
(4)
(5)
(6)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item Ref. Line No.Electric Plant in Service
(a)(Column)(c)
General 28 (c)$519,767,156
Less: Asset retirement obligations related cost components (164,950)
Revised Distribution $519,932,106
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
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 $4,062,875,656
Nuclear Production 21 (c)—
Revised Hydraulic Production - Conventional 504,616,809
Hydraulic Production - Pumped Storage 23 (c)—
Revised Other Production 398,251,186
Revised Transmission 2,045,200,003
Revised Distribution 3,143,599,734
Regional Transmission and Market Operation 27 (c)—
Revised General 519,932,106
Revised TOTAL $10,674,475,494
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)
(1)
(1)
(2)
(3)
(4)
(5)
(6)
(1)
(2)
(3)
(4)
(5)
(6)
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 theamounts 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 anote 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 ordocket 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. - CommonStock 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 UndistributedSubsidiary Earnings 12/10/1973 73,981,802 18,677,373 (b)52,659,175
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 9,111,012 178,229 (c)9,158,653
42 Total Cost of Account 123.1 $
53,999,001 Total 137,091,815 18,855,602 115,816,829
FERC FORM No. 1 (ED. 12-89)
Page 224-225
Description of Investment Date Acquired Date of Maturity Amount ofInvestment atBeginning of Year
Equity inSubsidiaryEarnings of Year
Revenues
for Year
Amount of
Investment
at End ofYear
Gain orLoss fromInvestmentDisposed
of
FOOTNOTE DATA
(a) Concept: DescriptionOfInvestmentsInSubsidiaryCompanies
Pacific Minerals, Inc. is a wholly owned subsidiary of PacifiCorp that holds a 66.67% ownership interest in Bridger Coal Company.
(b) Concept: InvestmentInSubsidiaryCompanies
During the year ended December 31, 2021, Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp, declared and paid a dividend of $40 million to PacifiCorp.
(c) Concept: InvestmentInSubsidiaryCompanies
During the year ended December 31, 2021, Trapper Mining Inc., a subsidiary of PacifiCorp, paid a distribution of $130,588 to PacifiCorp.FERC FORM No. 1 (ED. 12-89)
Page 224-225
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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)222,141,625 192,078,435 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)176,943,869 203,514,526 Electric
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)68,021,729 63,327,074 Electric
8 Transmission Plant (Estimated)1,231,929 815,425 Electric
9 Distribution Plant (Estimated)14,018,480 14,220,942 Electric
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote)19,098
12 TOTAL Account 154 (Enter Total of lines 5 thru 11)260,235,105 281,877,967
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 482,376,730 473,956,402
FERC FORM No. 1 (REV. 12-05)Page 227
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 Systemof Accounts).8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies.
9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.
10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
Current Year Year One Year Two Year Three Future Years Totals
Line
No.(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)(l)(m)
1 Balance-Beginning of Year 1,202,360 156,647 156,646 156,645 4,072,752 5,745,050
2
3 Acquired During Year:
4 Issued (Less Withheld Allow)156,644 156,644
5 Returned by EPA
6
7
8 Purchases/Transfers:
9
10
11
12
13
14
15 Total
16
17 Relinquished During Year:
18 Charges to Account 509 22,435 22,435
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 1,179,925 156,647 156,646 156,645 4,229,396 5,879,259
30
31 Sales:
32
SO2 Allowances Inventory(Account 158.1)No.Amt.No.Amt.No.Amt.No.Amt.No.Amt.No.Amt.
Net Sales Proceeds(Assoc.
Co.)
33 Net Sales Proceeds (Other)
34 Gains
35 Losses
Allowances Withheld (Acct158.2)
36 Balance-Beginning of Year 2,259 2,259 2,259 2,259 110,921 119,957
37 Add: Withheld by EPA 4,528 4,528
38 Deduct: Returned by EPA
39 Cost of Sales 2,259 2,269 4,528
40 Balance-End of Year 2,259 2,259 2,259 113,180 119,957
41
42 Sales
43 Net Sales Proceeds (Assoc.Co.)
44 Net Sales Proceeds (Other)
45 Gains
46 Losses
FERC FORM No. 1 (ED. 12-95)Page 228(ab)-229(ab)a
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 Systemof 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
LineNo.(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:
NOx Allowances Inventory(Account 158.1)No.Amt.No.Amt.No.Amt.No.Amt.No.Amt.No.Amt.
32 Net Sales Proceeds(Assoc. Co.)
33 Net Sales Proceeds (Other)
34 Gains
35 Losses
Allowances Withheld (Acct158.2)
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
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 [Includein the description the date of Commission
Authorization to use Acc 182.1 and period
of amortization (mo, yr to mo, yr).]
Total Amount of Loss Losses Recognized
During Year
Account
Charged Amount Balance at End of Year
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 andRegulatory Study Costs [Include in the
description of costs, the date of
COmmission Authorization to use Acc182.2 and period of amortization (mo, yr tomo, yr)]
Total Amount of
Charges
Costs Recognized
During Year
Account
Charged Amount Balance at End of Year
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 Q2846 (967)561.6 (967)456
3 Q2847 152 456
4 Q2865-A 1,744 561.6
5 Q2865-B 1,822 561.6
6 Q2866-A 1,377 561.6
7 Q2866-B 404 561.6
8 Q2867-A 158 561.6
9 Q2867-B 3,571 561.6
10 Q2872 (2,561)561.6
11 Q2873 3,122 561.6
12 Q2901-A 2,598 561.6 2,598 456
13 Q2901-B 2,099 561.6 2,099 456
14 Q2904 157 561.6 157 456
15 Q2908 1,213 561.6 1,213 456
16 Q2909 157 561.6 157 456
17 Q2910 157 561.6 157 456
18 Q2911 158 561.6 158 456
19 Q2912 158 561.6 158 456
20 Q2913-A 979 561.6 979 456
21 Q2913-B 6,070 561.6 6,070 456
22 Q2914-A 1,025 561.6 1,025 456
23 Q2914-B 1,163 561.6 1,163 456
24 Q2917 417 561.6
25 Q2919 984 561.6
26 Q2936-A 984 561.6 984 456
27 Q2936-B 2,700 561.6 2,700 456
28 Q2939 1,351 561.6
29 Q2944 1,902 561.6 1,902 456
30 Q2945 433 561.6 433 456
31 Q2946 1,076 561.6 1,076 456
32 Q2947 2,085 561.6 2,085 456
33 Q2948 1,902 561.6 1,902 456
34 Q2949 1,718 561.6 1,718 456
35 Q2950 1,626 561.6 1,626 456
36 Q2951 2,230 561.6 2,230 456
Description Costs Incurred During Period Account Charged Reimbursements ReceivedDuring the Period
Account Credited
WithReimbursement
37 Q2952 158 561.6 158 456
38 Q2963 5,458 561.6 5,458 456
39 Q2964 551 561.6 551 456
40 Q2970 158 561.6 158 456
41 Q2974 158 561.6 158 456
42 Customer Studies Accrual 11,201 561.6
20 Total 61,696 38,258
21 Generation Studies
22 Customer Studies Accrual 227 561.7
23 CGIQ0013 620 561.7 620 456
24 CGIQ0014 124 561.7 124 456
25 CGIQ0015 124 561.7 124 456
26 CGIQ0016 103 561.7 103 456
27 GIQ0443 281 456
28 GIQ0671 26 561.7
29 GIQ0778 742 561.7 742 456
30 GIQ0805 150 561.7 150 456
31 GIQ0820-A 7,426 561.7
32 GIQ0820-B 3,537 561.7
33 GIQ0823 6,706 561.7
34 GIQ0905-A 83 561.7 83 456
35 GIQ0905-B 5,938 561.7 5,938 456
36 GIQ0907 472 561.7 472 456
37 GIQ1068 1,608 561.7 1,608 456
38 GIQ1069 1,542 561.7 1,542 456
39 GIQ1071 3,623 561.7 3,623 456
40 GIQ1072 2,367 561.7 2,367 456
41 GIQ1086 6,460 561.7 6,460 456
42 GIQ1117 4,370 561.7 4,370 456
43 GIQ1120 1,148 561.7 1,148 456
44 GIQ1149 1,691 561.7 1,691 456
45 GIQ1150 1,244 561.7 1,244 456
46 GIQ1151 1,203 561.7 1,203 456
47 GIQ1175 2,081 561.7 2,081 456
48 GIQ1184 41 561.7 41 456
49 GIQ1233 3,346 561.7 3,346 456
50 GIQ1234 893 561.7 893 456
51 ISGIQ0001 14,105 561.7 14,105 456
52 ISGIQ0003 4,198 561.7 4,198 456
53 ISGIQ0004 4,468 561.7 4,468 456
54 ISGIQ0005 742 561.7 742 456
55 ISGIQ0006 5,787 561.7 5,787 456
56 ISGIQ002 5,800 561.7 5,800 456
57 LGIQ0634 2,713 561.7 2,713 456
58 LGIQ0636 1,984 561.7 1,984 456
59 LGIQ0787 5,430 561.7 5,430 456
60 LGIQ0788 4,191 561.7 4,191 456
61 LGIQ0792 4,713 561.7 4,713 456
62 LGIQ0805 2,333 561.7 2,333 456
63 LGIQ0824 7,862 561.7 7,862 456
64 LGIQ0836 5,708 561.7 5,708 456
65 LGIQ0838 5,675 561.7 5,675 456
66 LGIQ0906 124 561.7 124 456
67 LGIQ0951 1,440 561.7 1,440 456
68 LGIQ0953 702 561.7 702 456
69 LGIQ1008 1,979 561.7 1,979 456
70 LGIQ1009 247 561.7 247 456
71 LQIQ0642 1,376 561.7 1,376 456
72 OCGIQ0042 614 561.7 614 456
73 OCSGIQ0001 455 561.7 455 456
74 OCSGIQ0020-A 909 561.7 909 456
75 OCSGIQ0020-B 123 561.7 123 456
76 OCSGIQ0024 370 561.7 370 456
77 OCSGIQ0027 41 561.7 41 456
78 OCSGIQ0034 269 561.7 269 456
79 OCSGIQ0035 267 561.7 267 456
80 OCSGIQ0036 1,948 561.7 1,948 456
81 OCSGIQ0037-A 44 561.7 44 456
82 OCSGIQ0037-B 123 561.7 123 456
83 OCSGIQ0038-A 1,768 561.7 1,768 456
84 OCSGIQ0038-B 270 561.7 270 456
85 OCSGIQ0039-A 1,713 561.7 1,713 456
86 OCSGIQ0039-B 1,140 561.7 1,140 456
87 OCSGIQ0040-A 905 561.7 905 456
88 OCSGIQ0040-B 194 561.7 194 456
89 OCSGIQ0041-A 673 561.7 673 456
90 OCSGIQ0041-B 1,505 561.7 1,505 456
91 OCSGIQ0043 965 561.7 965 456
92 OCSGIQ0044-A 3,141 561.7 3,141 456
93 OCSGIQ0044-B 1,257 561.7 1,257 456
94 OCSGIQ0045-A 2,020 561.7 2,020 456
95 OCSGIQ0045-B 1,526 561.7 1,526 456
96 OCSGIQ0046-A 3,439 561.7 3,439 456
97 OCSGIQ0046-B 1,263 561.7 1,263 456
98 OCSGIQ0047-A 990 561.7 990 456
99 OCSGIQ0047-B 1,567 561.7 1,567 456
100 OCSGIQ0048-A 4,568 561.7 4,568 456
101 OCSGIQ0048-B 966 561.7 966 456
102 OCSGIQ0049-A 4,690 561.7 4,690 456
103 OCSGIQ0049-B 1,716 561.7 1,716 456
104 OCSGIQ0050-A 4,362 561.7 4,362 456
105 OCSGIQ0050-B 1,725 561.7 1,725 456
106 OCSGIQ0051-A 4,084 561.7 4,084 456
107 OCSGIQ0051-B 5,722 561.7 5,722 456
108 OCSGIQ0052 2,011 561.7 2,011 456
109 OCSGIQ0053 4,778 561.7 4,778 456
110 OCSGIQ0054 7,057 561.7 7,057 456
111 OCSGIQ0055-A 6,458 561.7 6,458 456
112 OCSGIQ0055-B 1,303 561.7 1,303 456
113 OCSGIQ0056-A 5,304 561.7 5,304 456
114 OCSGIQ0056-B 1,854 561.7 1,854 456
115 OCSGIQ0057-A 6,392 561.7 6,392 456
116 OCSGIQ0057-B 1,584 561.7 1,584 456
117 OCSGIQ0058-A 6,635 561.7 6,635 456
118 OCSGIQ0058-B 870 561.7 870 456
119 OCSGIQ0059 5,732 561.7 5,732 456
120 OCSGIQ0060 978 561.7 978 456
121 OCSGIQ0061-A 4,567 561.7 4,567 456
122 OCSGIQ0061-B 2,039 561.7 2,039 456
123 OCSGIQ0062 16,365 561.7 16,365 456
124 OCSGIQ0063 10,243 561.7 10,243 456
125 OCSGIQ0064-A 7,154 561.7 7,154 456
126 OCSGIQ0064-B 1,625 561.7 1,625 456
127 OCSGIQ0065 4,662 561.7 4,662 456
128 OCSGIQ0066 8,300 561.7 8,300 456
129 OCSGIQ0067-A 5,101 561.7 5,101 456
130 OCSGIQ0067-B 1,810 561.7 1,810 456
131 OCSGIQ0068-A 4,433 561.7 4,433 456
132 OCSGIQ0068-B 1,687 561.7 1,687 456
133 OCSGIQ0069 1,177 561.7 1,177 456
134 OCSGIQ0070-A 11,276 561.7 11,276 456
135 OCSGIQ0070-B 1,065 561.7 1,065 456
136 OCSGIQ0071-A 3,733 561.7 3,733 456
137 OCSGIQ0071-B 400 561.7 400 456
138 OCSGIQ0072-A 5,745 561.7 5,745 456
139 OCSGIQ0072-B 581 561.7 581 456
140 OCSGIQ0074-A 4,507 561.7 4,507 456
141 OCSGIQ0074-B 1,131 561.7 1,131 456
142 OCSGIQ0075 165 561.7 165 456
143 OCSGIQ0076-A 4,685 561.7 4,685 456
144 OCSGIQ0076-B 581 561.7 581 456
145 OCSGIQ0077-A 5,664 561.7 5,664 456
146 OCSGIQ0077-B 111 561.7 111 456
147 OCSGIQ0078-A 3,549 561.7 3,549 456
148 OCSGIQ0078-B 987 561.7 987 456
149 OCSGIQ0079 455 561.7 455 456
150 OGIQ1158 3,558 561.7 3,558 456
151 OSCGIQ0011 226 561.7 226 456
152 SGIQ0815 5,579 561.7 5,579 456
153 SGIQ1191 285 561.7 285 456
154 (a)
OATT Cluster Studies - 2020 Transition Cluster Area 4 17,113 561.7 17,113 456
155 (b)
OATT Cluster Studies - 2020 Transition Cluster Area 5 25,142 561.7 25,142 456
156 (c)
OATT Cluster Studies - 2020 Transition Cluster Area 8 11,425 561.7 11,425 456
157 (d)
OATT Cluster Studies - 2020 Transition Cluster Area 9 3,803 561.7 3,803 456
158 2020 OATT Cluster Studies 452,696 561.7 452,861 456
159 2021 OATT Cluster Studies-A 97,126 561.7 97,126 456
160 2021 OATT Cluster Studies-B 563,342 561.7 572,069 456
161 Pre-Application Studies - East 3,804 561.7 3,804 456
162 Pre-Application Studies - West 4,270 561.7 4,270 456
163 AS0005 1,285 561.7 1,285 456
39 Total 1,551,212 1,542,463
40 Grand Total 1,612,908 1,580,721
FERC FORM No. 1 (NEW. 03-07)Page 231
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 144,945 144,945
2 DSM Balancing Account - ID 6,865 4,531,259 908,431 4,538,124
3 DSM Balancing Account - UT 184,618,685 36,124,595 908 24,964,893 195,778,387
4 DSM Balancing Account - WY 11,269,853 9,126,948 908 5,567,669 14,829,132
5 Irrigation Load Control - OR 207,124 235,137 908 139,392 302,869
6 (a)
Deferred Excess Net Power Costs - CA 4,027,902 658,532 555,254 4,486,313 200,121
7 (b)
Deferred Excess Net Power Costs - ID 23,803,252 20,879,130 555,431 18,225,251 26,457,131
8 (c)
Deferred Excess Net Power Costs - OR 1,564,306 79,973 555 1,599,465 44,814
9 (d)
Deferred Excess Net Power Costs - UT 41,326,958 84,225,344 555 35,149,320 90,402,982
10 Deferred Excess Net Power Costs - WA 12,941,832 12,941,832
11 (e)
Deferred Excess Net Power Costs - WY 6,932,372 20,410,136 555 6,475,750 20,866,758
12 Decoupling Mechanism - WA 5,102,748 206,140 440,442 5,168,547 140,341
13 Solar Investment Tax Credit Basis Adjustment 373,879 56,588 282,283 27,463 403,004
14 Corporate Activity Tax - OR 1,282,946 60,215 409.1 702,645 640,516
15 (f)
Pension 431,404,187 9,947,906 (o)155,029,503 286,322,590
16 Other Postretirement 735,190 19,644 754,834
17 Powerdale Decommissioning - ID (10)8,065 407.3 8,065
18 Deferred Steam Accelerated Depreciation -UT 4,851,954 4,851,954
19 Colstrip Unit No. 4 Deferred MaintenanceCosts - WA 258,904 258,904
20 Carbon Plant Inventory (5)1,078,260 523,252 407.3 347,613 1,253,899
21 Carbon Plant Inventory - CA (3)720,622 407.3 345,899 374,723
22 Cholla Unit No. 4 Closure Costs - CA 4,981,883 59,791 440, 442, 444,154, 407.3, 512,921, 410.1 278,560 4,763,114
23 Cholla Unit No. 4 Closure Costs - ID 236,825 920, 154, 407.3,512, 921, 410.1 272,337 (35,512)
24 Cholla Unit No. 4 Closure Costs - OR 288,206 791,484 512, 921, 154,407.3, 410.1 608,321 471,369
25 (g)
Cholla Unit No. 4 Closure Costs - UT 12,031,768 276,305 154, 407.3, 512,
921, 410.1 3,631,490 8,676,583
26 Cholla Unit No. 4 Closure Costs - WA 83,835 49,562 154, 407.3, 512,
921, 410.1 133,397 0
27 (h)
Cholla Unit No. 4 Closure Costs - WY 46,215,353 556,121 154, 407.3, 512,921, 410.1 2,740,020 44,031,454
28 Depreciation Study Deferral - ID (1)14,979,934 403 1,039,631 13,940,303
29 Depreciation Study Deferral - UT (17)1,344,454 403 128,043 1,216,411
30 Depreciation Study Deferral - WY (17)4,643,004 403 442,191 4,200,813
Description and Purpose of OtherRegulatory Assets Balance at Beginning ofCurrent Quarter/Year Debits
Written off
During
Quarter/YearAccountCharged
Written off During thePeriod Amount Balance at end ofCurrent Quarter/Year
31 (i)
Generating Plant Liquidated Damages - UT 455,000 557 35,000 420,000
32 (j)
Generating Plant Liquidated Damages - WY 1,081,552 557 54,288 1,027,264
33 (k)
Wind Test Energy Deferral - WY 229,312 407.3 8,281 221,031
34 Klamath Hydroelectric Relicensing Costs - UT
(10)8,160,607 203,291 404 4,217,412 4,146,486
35 Environmental Costs (10)88,897,735 26,545,270 514, 545, 554,598, 935 7,084,530 108,358,475
36 Asset Retirement Obligations RegulatoryDifference 158,208,512 12,416,209 170,624,721
37 (l)
Unamortized Contract Values 42,394,907 242 5,947,224 36,447,683
38 Greenhouse Gas Allowance Compliance
Costs - CA 1,588,786 4,689,459 456,431 3,361,070 2,917,175
39 Solar Feed-In Tariff Deferral - OR (1)5,717,575 4,920,052 555,908 5,969,397 4,668,230
40 Oregon Community Solar Program 1,383,745 562,509 908,431 1,946,254
41 Solar Incentive Subscriber Program - UT 1,940,715 139,698 908 159,181 1,921,232
42 Renewable Portfolio Standards Compliance -WA (1)651,908 100,000 555 542,975 208,933
43 Protocol - MSP Deferral - ID 300,000 440,442,444 300,000
44 Protocol - MSP Deferral - WY 4,000,000 440,442,444 4,000,000
45 Deferred Intervenor Funding Grants - CA 152,013 240,125 392,138
46 Deferred Intervenor Funding Grants - ID 103,348 928 103,348
47 Deferred Intervenor Funding Grants - OR 2,110,849 431,091 2,541,940
48 Deferred Independent Evaluator Costs - OR 38,048 475 38,523
49 Catastrophic Event - CA 257,113 135,658 392,771
50 Washington Low Income Program 1,793,733 812,896 2,606,629
51 Deferred Overburden Cost - ID 505,634 1,190,405 501 1,046,076 649,963
52 Deferred Overburden Cost - WY 1,422,725 3,157,015 501 2,876,101 1,703,639
53 BPA Balancing Account - OR 7,807,348 440,442 4,195,779 3,611,569
54 Property Sales Balancing Account - OR 1,921,319 680,700 421.1 426,102 2,175,917
55 Property Insurance Reserve - OR 13,765,693 18,041,827 924 8,602,538 23,204,982
56 Property Insurance Reserve - WA 1,163,694 924 1,144,819 18,875
57 Miscellaneous Regulatory Assets and
Liabilities - OR 447,835 6,102 440,442,444 194 453,743
58 (m)
Utah Mine Disposition 116,867,286 3,850,036 506 4,983,594 115,733,728
59 Preferred Stock Redemption Loss - UT (10)264,786 407.3 82,531 182,255
60 Preferred Stock Redemption Loss - WA (10)42,172 407.3 13,318 28,854
61 Preferred Stock Redemption Loss - WY (10)91,249 407.3 28,442 62,807
62 Mobile Home Park Conversion - CA 221,622 20,393 407.3 24,742 217,273
63 Transportation Electrification Program - OR 2,475,632 3,267,214 5,742,846
64 Transportation Electrification Program - WA 221,507 366,537 588,044
65 Fire Hazard and Wildfire Mitigation Plan - CA 13,816,458 8,451,815 22,268,273
66 AMI Replaced Meters - OR (5)16,126,628 572,548 407.3 2,835,936 13,863,240
67 COVID-19 Bill Assistance Program - OR 10,819,673 10,819,673
68 COVID-19 Bill Assistance Program - WA 3,006,060 3,006,060
69 Washington Colstrip Unit No. 3 (22)4,379 456 4,379
70 (n)
Unrealized Loss on Derivative Contracts 16,630,636 244 16,630,636
71 Oregon Outreach and Research Pilot 4,880 4,880
72 Equity Advisory Group for Clean Energy
Implementation Plan - WA 535,334 535,334
73 Metro Business Income Tax - OR 25,422 409.1 266 25,156
44 TOTAL 1,296,157,597 328,581,331 346,728,061 1,278,010,867
FERC FORM No. 1 (REV. 02-04)Page 232
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is approximately one year.
(b) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is approximately one year.
(c) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is approximately one year.
(d) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is approximately one year.
(e) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is approximately one year.
(f) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is 19 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 11 years.
(i) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is 12 years.
(j) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is 22 years.
(k) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is 29 years.
(l) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is two years. Represents frozen values of contracts previously accounted for as derivatives and recorded at fair value.
(m) 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 three
years.
(n) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Weighted average remaining life is one year.
(o) 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.
FERC FORM No. 1 (REV. 02-04)Page 232
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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)49,530 557 45,720 3,810
2 Bogus Creek (41)787,760 557 41,280 746,480
3
(a)
Mead Phoenix Availability and TransmissionCharge 7,218,293 565 6,663,040 555,253
4 Point-to-Point Transmission 1,061,472 1,198,525 131, 142 698,101 1,561,896
5 Hermiston Swap (40)2,675,551 557 171,693 2,503,858
6 Deferred Coal Costs - Wyodak Settlement(22)670,362 501 335,182 335,180
7 (b)
Long-Term Lease Commissions Prepaids 28,125 931 20,315 7,810
8 Lake Side Maintenance Prepaid 9,032,863 6,028,819 107 15,061,682
9 Lake Side 2 Maintenance Prepaid 18,910,764 5,083,218 23,993,982
10 Chehalis Maintenance Prepaid 22,716,944 4,859,618 27,576,562
11 Currant Creek Maint. Prepaid 20,124,993 5,917,217 107 24,844,252 1,197,958
12 Seven Mile Hill Maintenance Prepaid 2,039,806 1,359,871 107 66,343 3,333,334
13 Seven Mile Hill II Maintenance Prepaid 401,780 267,853 107 11,991 657,642
14 Dunlap Ranch I Maintenance Prepaid 762,352 1,524,703 2,287,055
15 Ekola Flats Maintenance Prepaid 1,469,192 1,469,192
16 Foote Creek Maintenance Prepaid 328,072 328,072
17 Glenrock I Maintenance Prepaid 2,039,806 1,359,871 107 67,732 3,331,945
18 Glenrock III Maintenance Prepaid 803,560 535,707 1,339,267
19 Goodnoe Hills Maintenance Prepaid 1,112,183 1,077,363 2,189,546
20 High Plains Maintenance Prepaid 2,039,806 1,359,871 3,399,677
21 Leaning Juniper Maintenance Prepaid 2,070,712 1,380,475 107 239,095 3,212,092
22 Marengo Maintenance Prepaid 1,400,714 1,671,327 3,072,041
23 Marengo II Maintenance Prepaid 696,156 823,191 1,519,347
24 McFadden Ridge I Maintenance Prepaid 587,217 391,478 978,695
25 Pryor Mountain Maintenance Prepaid 49,828 49,828
26 Rolling Hills Maintenance Prepaid 2,039,806 1,359,871 107 50,323 3,349,354
27 Lease Incentives 11,514 454 11,514
28 (c)
Credit Agreement Costs 1,010,017 1,289,706 427, 431 677,180 1,622,543
29 (d)
PCRB Mode Conversion Costs 290,228 427 68,978 221,250
30 1994 Series Restructuring Costs (16)225,283 427 58,769 166,514
31 Deferred S-3 Shelf Registration Costs 77,234 181 38,617 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 115,043 107 6,556 108,487
35 Other Deferred Charges 596 539,004 131, 181, 577 38,868 500,732
47 Miscellaneous Work in Progress
48 Deferred Regulatroy Comm. Expenses (See
pages 350 - 351)
49 TOTAL 101,368,220 107,087,451
FERC FORM No. 1 (ED. 12-94)
Page 233
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 one year.
(c) Concept: DescriptionOfMiscellaneousDeferredDebits
The weighted average remaining life is two years.
(d) Concept: DescriptionOfMiscellaneousDeferredDebits
The weighted average remaining life is three years.
FERC FORM No. 1 (ED. 12-94)Page 233
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 93,154,239 67,616,048
3 State Carryfowards 72,747,311 73,272,201
4 Asset Retirement Obligations 64,400,058 72,638,523
5 Regulatory Liabilities 442,453,306 403,728,517
6 Loss Contingencies 34,677,256 34,476,231
7 Other 69,571,143 49,689,801
8 TOTAL Electric (Enter Total of lines 2 thru 7)777,003,313 701,421,321
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)777,003,313 701,421,321
Notes
FERC FORM NO. 1 (ED. 12-88)Page 234
Description and Location Balance at Beginning of Year Balance at End of Year
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 purposeof pledge.
LineNo.
Class and Series of
Stock and Name ofStock Series(a)
Number ofSharesAuthorized by
Charter
(b)
Par or
Stated Valueper Share(c)
Call Price atEnd of Year
(d)
Outstanding perBal. Sheet (Totalamount
outstanding
withoutreduction foramounts held byrespondent)
Shares
(e)
Outstandingper Bal. Sheet(Total amount
outstanding
withoutreduction foramounts heldby respondent)
Amount
(f)
Held byRespondentAsReacquired
Stock (Acct
217) Shares(g)
Held byRespondentAsReacquired
Stock (Acct
217) Cost(h)
Held byRespondentIn Sinkingand Other
Funds
Shares(i)
Held byRespondentIn Sinkingand Other
Funds
Amount(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 and204) - Data Conversion
2
(e)
Authorized andUnissued Capital Stock
3 Total
FERC FORM NO. 1 (ED. 12-91)Page 250-251
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: CapitalStockDescription
Berkshire Hathaway Energy Company indirectly owns all of the shares of PacifiCorp's outstanding common stock. Therefore, there is no public market for PacifiCorp's common stock.
(b) Concept: CapitalStockDescription
This class of stock is not redeemable.
(c) Concept: CapitalStockDescription
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
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:2022-04-13 Year/Period of ReportEnd of: 2021/ 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 atotal 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 entrieseffecting 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 includingidentification 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 thetransactions 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
Donations Received from Stockholders (Account 208)
Beginning Balance Amount
Increases (Decreases) from Sales of Donations Received from Stockholders
Ending Balance Amount
Reduction in Par or Stated Value of Capital Stock (Account 209)
Beginning Balance Amount
Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
Ending Balance Amount
Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
Beginning Balance Amount
Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
Ending Balance Amount
Miscellaneous Paid-In Capital (Account 211)
Beginning Balance Amount
Increases (Decreases) Due to Miscellaneous Paid-In Capital
Ending Balance Amount
Historical Data - Other Paid in Capital
Beginning Balance Amount
Increases (Decreases) in Other Paid-In Capital
Ending Balance Amount
Total
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:2022-04-13 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: MiscellaneousPaidInCapital
Miscellaneous Paid-In Capital (Account 211):
Share based payments 1,973,218
Tax benefit from stock option exercises (2)14,422,979
Benefit plan separation (3,575,760)
Capital contributions (4)1,089,950,000
Gain on sale of ScottishPower plc stock 136,208
Qualified production activity tax deduction (1,275,241)
Contribution of Intermountain Geothermal Company (7)432,552
Total Miscellaneous Paid-In Capital (Account 211)1,102,063,956
Represents the fair value of stock options granted by ScottishPower plc for which certain performance measures were met in March 2005. These options became fully vested in May 2005.
Represents the income tax deduction attributable to the exercise of stock options granted by ScottishPower plc.
Represents the effect of transferring certain benefit plan obligations and assets to PPM Energy, Inc. as a result of the sale of PacifiCorp by ScottishPower plc.
Represents capital contributions to PacifiCorp (with no shares of stock issued) from its indirect parent Berkshire Hathaway Energy Company ("BHE"). During the year being reported, no capital contributions were made by BHE to PacifiCorp.
Represents a realized gain on stock related to separation of PPM Energy, Inc. participants from the deferred compensation plan, which invested in ScottishPower plc stock.
Represents amounts associated with Internal Revenue Code Section 199 qualified production activities.
Represents contribution of Intermountain Geothermal Company to PacifiCorp from BHE in March 2006, subsequent to the sale of PacifiCorp to BHE. Intermountain Geothermal Company was merged with and its direct parent, PacifiCorp, on
August 31, 2007, with PacifiCorp surviving
FERC FORM No. 1 (ED. 12-87)Page 253
(1)
(3)
(5)
(6)
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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.
LineNo.(a)(b)
1 Common Stock 41,101,061
22 TOTAL 41,101,061
FERC FORM No. 1 (ED. 12-87)Page 254b
Class and Series of Stock Balance at End of Year
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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: 3.85% Series due 2021 400,000,000 3,007,139 744,000 05/12/2011 06/15/2021 05/12/2011 06/15/2021 7,058,333
3 (a)
First Mortgage Bonds: 2.95% Series due 2022 - A 350,000,000 2,424,350 308,000 01/06/2012 02/01/2022 01/06/2012 02/01/2022 8,604,167
4 (b)
First Mortgage Bonds: 2.95% Series due 2022 - B 100,000,000 254,129 (81,000)03/06/2012 02/01/2022 03/06/2012 02/01/2022 2,458,333
5 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
6 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
7 First Mortgage Bonds: 3.35% Series due 2025 250,000,000 2,121,421 320,000 06/20/2015 07/01/2025 06/20/2015 07/01/2025 250,000,000 8,375,000
8 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
9 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
10 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
11 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
12 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
13 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
14 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
15 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
16 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
17 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
18 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
19 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
20 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
21 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
22 (c)
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 13,775,000
23 Secured Medium-Term Notes: 8.53% Series C due 2021 15,000,000 115,202 12/16/1991 12/16/2021 12/16/1991 12/16/2021 1,226,187
24 Secured Medium-Term Notes: 8.375% Series C due 2021 5,000,000 38,400 12/31/1991 12/31/2021 12/31/1991 12/31/2021 417,587
25 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 5,000,000 413,000
26 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 4,000,000 330,800
27 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 15,000,000 1,207,500
28 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 8,000,000 645,600
29 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 50,000,000 4,060,000
30 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 12,000,000 973,200
31 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 10,000,000 805,000
32 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 26,000,000 2,100,800
Class and Series of Obligation, Coupon Rate (For new issue,
give commission Authorization numbers and dates)Related Account Number Principal Amount of Debt Issued Total Expense, Premium or Discount Total Expense Total Premium Total
Discount
NominalDate ofIssue
Date of
Maturity
AMORTIZATIONPERIOD DateFrom
AMORTIZATIONPERIOD DateTo
Outstanding(Total amountoutstanding
without
reduction foramounts heldbyrespondent)
Interest for
Year Amount
33 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 25,000,000 2,020,000
34 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
35 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
36 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
37 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
38 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
39 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
40 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
41 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
42 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
43 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
44 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
45 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
46 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
47
(d)
Pollution Control Revenue Refunding Bonds - Secured: SweetwaterCounty, WY, Series 1994 21,260,000 510,479 11/17/1994 11/01/2024 11/17/1994 11/01/2024 21,260,000 92,970
48
(e)
Pollution Control Revenue Refunding Bonds - Secured: ConverseCounty, WY, Series 1994 8,190,000 209,777 11/17/1994 11/01/2024 11/17/1994 11/01/2024 8,190,000 33,062
49
(f)
Pollution Control Revenue Refunding Bonds - Secured: EmeryCounty, UT, Series 1994 121,940,000 3,274,246 11/17/1994 11/01/2024 11/17/1994 11/01/2024 121,940,000 459,701
50
(g)
Pollution Control Revenue Refunding Bonds - Secured: LincolnCounty, WY, Series 1994 15,060,000 422,858 11/17/1994 11/01/2024 11/17/1994 11/01/2024 15,060,000 77,246
51
(h)
Environment Improvement Revenue Bonds - Secured: ConverseCounty, WY, Series 1995 5,300,000 132,043 11/17/1995 11/01/2025 11/17/1995 11/01/2025 5,300,000 20,026
52
(i)
Environment Improvement Revenue Bonds - Secured: LincolnCounty, WY, Series 1995 22,000,000 404,262 11/17/1995 11/01/2025 11/17/1995 11/01/2025 22,000,000 104,318
53 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 83,571
54 Subtotal 9,667,150,000 77,936,011 (162,560)34,149,000 (j)8,797,150,000 (k)405,404,301
55 Reacquired Bonds (Account 222)
56
57
58
59 Subtotal
60 Advances from Associated Companies (Account 223)
61
62
63
64 Subtotal
65 Other Long Term Debt (Account 224)
66 (l)
Long-term debt authorized but unissued
67 Subtotal
33 TOTAL 9,667,150,000 8,797,150,000 405,404,301
FERC FORM No. 1 (ED. 12-96)
Page 256-257
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: ClassAndSeriesOfObligationCouponRateDescription
In November 2021, PacifiCorp exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed the 2.95% Series First Mortgage Bonds due February 2022 totaling $450m and transferred the associated unamortized debt expense, premium and discount to Account 189, Unamortized loss on reacquired debt.
(b) Concept: ClassAndSeriesOfObligationCouponRateDescription
In November 2021, PacifiCorp exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed the 2.95% Series First Mortgage Bonds due
February 2022 totaling $450m and transferred the associated unamortized debt expense, premium and discount to Account 189, Unamortized loss on reacquired debt.
(c) Concept: ClassAndSeriesOfObligationCouponRateDescription
In July 2021, PacifiCorp issued $1 billion of its 2.90% First Mortgage Bonds due June 2052. 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.
(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: 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.
(i) 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.
(j) Concept: Bonds
Refer to Item 6 in Important Changes During the Year and Note 8 in Notes to FinancialStatements in this Form No. 1 for a discussion of PacifiCorp's long-term debt.
(k) Concept: InterestExpenseBonds
Account represents interest expense charged to Account 427, Interest on long-term debt and does not include any amount charged to Account 430, Interest on debt to associated companies, as all such interest was accrued on amounts included in Account 233, Notes payable to associated companies during the year.
(l) Concept: ClassAndSeriesOfObligationCouponRateDescription
As of December 31, 2021, PacifiCorp had regulatory authorization from the OPUC and IPUC to issue an additional $2 billion of long-term debt and must make a notice filing with the Washington Utilities and Transportation Commission prior to future issuances. In addition, as of December 31, 2021, 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, 2021) 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, 2021) is as follows: (a) IPUC - Case No. PAC-E-08-05, Order No. 30606, dated August 4, 2008; and (b) OPUC - Docket No. UF-4250, Order No. 08-382, dated July 29, 2008.FERC FORM No. 1 (ED. 12-96)
Page 256-257
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in
the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for
the year. Indicate clearly the nature of each reconciling amount.2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating,however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment,or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic
reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line No.Particulars (Details)(a)Amount(b)
1 Net Income for the Year (Page 117)888,042,944
2 Reconciling Items for the Year
3
4 Taxable Income Not Reported on Books
5 Contribution in Aid of Construction 124,218,224
6 MCI F.O.G. Wire Lease 574
7 Regulatory Asset - 2017 Protocol - MSP Deferral - ID 300,000
8 Regulatory Asset - 2017 Protocol - MSP Deferral - WY 4,000,000
9 Regulatory Asset - BPA Balancing Account - OR 4,195,779
10 Regulatory Asset - WA Decoupling Mechanism 4,962,408
11 Regulatory Asset - Washington Unit No. 3 4,379
12 Regulatory Liability - 50% Bonus Tax Depr - WY 21,816
13 Regulatory Liability - Alt Rate for Energy Program (CARE) - CA 17,981
14 Regulatory Liability - BPA Balancing Account - WA 517,441
15 Regulatory Liability - Bridger Accelerated Depreciation - OR 3,639,439
16 Regulatory Liability - Bridger Accelerated Depreciation - WA 2,549,408
17 Regulatory Liability - California Greenhouse Gas Allowance Compliance 1,097,924
18 Regulatory Liability - Deferred Excess RECs in Rates - WY 250,908
19 Regulatory Liability - Excess Income Tax Deferral-WY 817,678
20 Regulatory Liability - Renewable Portfolio Standards Compliance - OR 303,967
21 Regulatory Liability - Sale of REC - WA 39,819
22 Regulatory Liability - WA Rate Refunds 2,847,187
23 Transmission Service Deposit 1,610,991
24 Trapper Mining Stock Basis 778,564
25 Unearned Joint Use Pole Contact Revenue 376,311
9 Deductions Recorded on Books Not Deducted for Return
10 Fed/State Tax Expense (80,752,761)
11 Fed/State Tax Expense-Interest 154,922
12 Accrued Royalties 493,859
13 Accrued Severance 575,267
14 Avoided Costs 40,589,711
15 Book Depreciation 1,065,140,968
16 Book Depreciation Allocated to Medicare and M&E 129,988
17 Capitalization of Test Energy 2,294,761
18 Capitalized labor and benefit costs 6,074,609
19 Company Plane 70,087
20 Deferred Compensation 458,898
21 Environmental Liability - Regulated 16,809,971
22 Executive Compensation - IRC Section 162(m) Limitation 673,079
23 Hermiston Swap 171,693
24 Hydro Relicensing Obligation 1,331,000
25 Idaho Disallowed Loss 2,089,076
26 Income Tax Interest 10,452
27 Injuries & Damages Reserve - OR 938,715
28 Lobbying Expenses 1,137,391
29 Long Term Incentive Plan 2,675,140
30 Meals and Entertainment 806,098
31 Miscellaneous Current and Accrued Liability 950,000
32 Nondeductible Fringe Benefits 161,391
33 Nondeductible Parking Costs 313,908
34 Operating Leases (Liability)147,997
35 Penalties 27,787
36 Prepaid - FSA O& M - East 157,284
37 Prepaid Aircraft Maintenance 103,009
38 Prepaid Membership Fees 10,294
39 Prepaid Surety Bond 219,828
40 Prepaid Taxes - ID PUC 77,407
41 Prepaid Water Rights 155,170
42 Property Insurance Reserve - CA 85,319
43 Property Insurance Reserve - ID 113,544
44 Property Insurance Reserve - WY 181,177
45 Regulatory Asset - Carbon Decommissioning - CA 345,899
46 Regulatory Asset - Carbon Plant Decom/Inventory 347,613
47 Regulatory Asset - Cholla U4 Closure 5,191,006
48 Regulatory Asset - Deferred Excess NPC - CA 3,827,781
49 Regulatory Asset - Deferred Excess NPC - OR 1,519,492
50 Regulatory Asset - Deferred Intervenor Funding Grants - ID 103,350
51 Regulatory Asset - Depreciation Increase - UT 128,043
52 Regulatory Asset - Depreciation Increase - WY 442,191
53 Regulatory Asset - Environmental Costs - WA 729,705
54 Regulatory Asset - FAS 158 Pension Liability 34,657,161
55 Regulatory Asset - Generating Plant Liquidated Damages - UT 35,000
56 Regulatory Asset - Generating Plant Liquidation Damages - WY 5,708
57 Regulatory Asset - Goodnoe Hills Settlement - WY 21,250
58 Regulatory Asset - Klamath Hydroelectric Relicensing Costs - UT 4,014,120
59 Regulatory Asset - Lake Side Settlement - WY 27,331
60 Regulatory Asset - Meters Replaced by AMI - OR 2,263,389
61 Regulatory Asset - Mobile Home Park Conversion - CA 4,350
62 Regulatory Asset - Post Employment Costs 4,652,854
63 Regulatory Asset - Post Merger Loss - Reacquired Debt 552,624
64 Regulatory Asset - Post-Retirement Settlement Loss 735,190
65 Regulatory Asset - Powerdale Decommissioning - ID 8,065
66 Regulatory Asset - Preferred Stock Redemption Loss - UT 82,531
67 Regulatory Asset - Preferred Stock Redemption Loss - WA 13,318
68 Regulatory Asset - Preferred Stock Redemption Loss - WY 28,442
69 Regulatory Asset - Renewable Portfolio Standards Compliance - WA 442,975
70 Regulatory Asset - Solar Feed-In Tariff Deferral - OR 1,049,346
71 Regulatory Asset - Solar Incentive Program - UT 6,420,614
72 Regulatory Asset - Subscriber Solar Program - Utah 19,483
73 Regulatory Asset - Utah Mine Disposition 1,133,557
74 Regulatory Asset - Wildland Fire Protection - UT 997,769
75 Regulatory Liability - ARO/Reg Diff - Trojan - WA Portion 29,516
76 Regulatory Liability - Blue Sky - ID 27,095
77 Regulatory Liability - Cholla Decommissioning - ID 2,518,308
78 Regulatory Liability - Clean Fuels Program - OR 2,494,578
79 Regulatory Liability - Deferred Excess NPC - CA 1,494,997
80 Regulatory Liability - FAS 158 Post Retirement 15,468,573
81 Regulatory Liability - Klamath River Dams Removal 261,298
82 Regulatory Liability - OR Energy Conservation Charge 149,839
83 Regulatory Liability - Plant Closure Cost - WA 1,355,736
84 Regulatory Liability - Steam Decommissioning - WA 3,569,616
85 Regulatory Liability - Steam Decommmissioning - UT 17,053,629
86 Regulatory Liability - Steam Decommmissioning - WY 2,834,420
87 Reimbursements 3,969,565
88 Trapper Mine Contract Obligation 1,161,456
14 Income Recorded on Books Not Included in Return
15 Book Fixed Asset Gain/Loss (2,788,571)
16 Dividend Received Deduction - Deferred Compensation (78,824)
17 Corporate Owned Life Insurance (9,807,014)
18 Regulatory Liability - BPA Balancing Account - ID (1,321,049)
19 Regulatory Liability - Deferred Excess NPC - OR (6,571,987)
20 Regulatory Liability - Deferred Excess RECs in Rates - UT (332,873)
21 Regulatory Liability - Depreciation Deferral - OR (2,578,012)
22 Regulatory Liability - Excess Income Tax Deferral-CA (2,527,835)
23 Regulatory Liability - Excess Income Tax Deferral-ID (237,610)
24 Regulatory Liability - Excess Income Tax Deferral-OR (5,699,535)
25 Regulatory Liability - Excess Income Tax Deferral-WA (421,490)
26 Regulatory Liability - OR Direct Access 5 Year Opt Out (1,211,384)
27 Regulatory Liability - Utah Home Energy Lifeline (409,283)
28 Regulatory Liability - WA Deferred Steam Depreciation (17,418,111)
29 Regulatory Liability - WA Low Energy Program (812,896)
30 Equity Earnings in Subsidiaries (18,855,602)
31 Intercompany Adjustment 178,229
19 Deductions on Return Not Charged Against Book Income
20 Accrued Final Reclamation (343,274)
21 Accrued Payroll Taxes (11,534,271)
22 Accrued Vacation (509,491)
23 Amortization NOPAs 99-00 RAR (28,449)
24 Basis Intangible Difference (287,911)
25 Bear River Settlement Agreement (127,126)
26 Capitalized Depreciation (9,611,130)
27 Contra Receivable from Joint Owners (53,123)
28 Cost of Removal (82,206,015)
29 CWIP Reserve (2,761,567)
30 Debt AFUDC (23,644,614)
31 Deferred Compensation Mark to Market Gain / Loss (867,186)
32 Deferred Revenue (14,059)
33 Deferred Revenue - Lease Incentives (31,062)
34 Deferred Revenue - Other (582,292)
35 Dividend Deduction at 50%(5)
36 Environmental Liability - Non-regulated (24,985)
37 Equity AFUDC (49,665,607)
38 FAS 112 Book Reserve - Postemployment Benefits (3,730,046)
39 FAS 158 Pension Asset (18,752,208)
40 FAS 158 Pension Liability (4,305,012)
41 FAS 158 Post-retirement Asset (1,168,874)
42 FAS 158 SERP Liability (1,774,048)
43 Federal Tax Depreciation (1,440,752,472)
44 Federal Tax Fixed Asset Gain/Loss (3,388,571)
45 Fuel Cost Adjustment (3,997,196)
46 Injuries and Damages Accrual (817,620)
47 Inventory Reserve (177,578)
48 Inventory Reserve - Cholla U4 (764,308)
49 Klamath Settlement Obligation (30,622,061)
50 Lease Depreciation - Timing Difference (408,210)
51 Lewis River Settlement Agreement (39,224)
52 Liquidated Damages - Cholla U4 (19,606,070)
53 Long Term Incentive Plan Mark to Market Gain/Loss (974,298)
54 N Umpqua Settlement Agreement (668,186)
55 Oregon Regulatory Asset/Regulatory Liability Consolidation (5,908)
56 Pension/Retirement Accrual (44,785)
57 Pre-1943 Preferred Stock Dividend - Deduction (107,935)
58 Prepaid Taxes - OR PUC (239,171)
59 Prepaid Taxes - Property Taxes (1,038,374)
60 Prepaid Taxes - UT PUC (356,601)
61 Property Insurance Reserve - OR (9,439,289)
62 Property Insurance Reserve - UT (760,602)
63 Regulatory Asset - CA Greenhouse Gas Allowance Compliance (1,328,390)
64 Regulatory Asset - Carbon Plant Decomm/Inventory-WY (523,253)
65 Regulatory Asset - Carbon Plant Deferred Depreciation - UT (4,851,954)
66 Regulatory Asset - Catastrophic Event Deferral - CA (135,659)
67 Regulatory Asset - Community Solar - OR (562,509)
68 Regulatory Asset - Covid-19 Bill Assist Program - OR (10,819,673)
69 Regulatory Asset - Covid-19 Bill Assist Program - WA (3,006,060)
70 Regulatory Asset - Deferred Excess NPC - ID (2,653,879)
71 Regulatory Asset - Deferred Excess NPC - UT (49,076,024)
72 Regulatory Asset - Deferred Excess NPC - WA (12,941,832)
73 Regulatory Asset - Deferred Excess NPC - WY (13,934,386)
74 Regulatory Asset - Deferred Independent Evaluator Fees - OR (474)
75 Regulatory Asset - Deferred Intervenor Funding Grants - CA (240,125)
76 Regulatory Asset - Deferred Intervenor Funding Grants - OR (431,091)
77 Regulatory Asset - Deferred Overburden Costs - ID (144,329)
78 Regulatory Asset - Deferred Overburden Costs - WY (280,914)
79 Regulatory Asset - Depreciation Increase - ID (14,090,814)
80 Regulatory Asset - Emergency Service Program-Battery Storage-CA (4,918)
81 Regulatory Asset - Environmental Costs (20,190,445)
82 Regulatory Asset - Equity Advisory Group - WA (535,334)
83 Regulatory Asset - FAS 158 Post Retirement Liability (15,468,572)
84 Regulatory Asset - Fire Risk Mitigation - CA (8,451,816)
85 Regulatory Asset - Independent Evaluator Costs - UT (355,981)
86 Regulatory Asset - Major Maintenance Expense Colstrip - WA (258,904)
87 Regulatory Asset - Pension Settlement - CA (315,966)
88 Regulatory Asset - Pension Settlement - OR (4,453,167)
89 Regulatory Asset - Pension Settlement - UT (1,783,111)
90 Regulatory Asset - Pension Settlement - WA (1,176,070)
91 Regulatory Asset - Pension Settlement - WY (2,043,980)
92 Regulatory Asset - Property Sales Balancing Account - OR (254,598)
93 Regulatory Asset - STEP Pilot Program Balance Account - Utah (6,420,614)
94 Regulatory Asset - Transportation Electrification Pilot - CA (89,402)
95 Regulatory Asset - Transportation Electrification Pilot - OR (3,272,094)
96 Regulatory Asset - Transportation Electrification Pilot - WA (366,538)
97 Regulatory Asset - Wind Test Energy Deferral - WY (221,031)
98 Regulatory Asset/Liability - Demand Side Management (15,330,213)
99 Regulatory Liability - Blue Sky - CA (107,257)
100 Regulatory Liability - Blue Sky - OR (108,136)
101 Regulatory Liability - Blue Sky - UT (1,471,565)
102 Regulatory Liability - Blue Sky - WA (88,057)
103 Regulatory Liability - Blue Sky - WY (109,902)
104 Regulatory Liability - California Energy Savings Assistance (146,458)
105 Regulatory Liability - Cholla Decommissioning - CA (50,140)
106 Regulatory Liability - Cholla Decommissioning - WY (155,360)
107 Regulatory Liability - Cholla Plant Unit No. 4 Decommissioning - OR (825,729)
108 Regulatory Liability - Cholla Plant Unit No. 4 Decommissioning - UT (1,396,313)
109 Regulatory Liability - Deferred Excess NPC - WA (21,786,652)
110 Regulatory Liability - Deferred Excess NPC - WY (586,639)
111 Regulatory Liability - Property Insurance Reserve - WA (18,875)
112 Regulatory Liability - UT Solar Incentive Subscriber Program (7,379,684)
113 Regulatory Liability - WA Decoupling Mechanism (1,676,606)
114 Repairs Deduction (168,246,128)
115 Reserve for Bad Debts (82,350)
116 Rogue River - Habitat Enhancement Liability (85,978)
117 ROU Asset (Operating Leases)(123,011)
118 Tax Depletion-SRC (183,605)
119 Tax Percentage Depletion - Blundell Steam Field (506,090)
120 Trojan Decommissioning (79,436)
121 Wasatch Workers Comp Reserve (168,151)
122 Western Coal Carrier Retiree Medical Accrual (1,119,000)
123 State Tax Deductions (4,220,948)
27 Federal Tax Net Income 23,498,713
28 Show Computation of Tax:
29 Federal Income Tax at 21.00%4,934,730
30 Provision to Return Adjustment (1,077,159)
31 Tax Reserve Changes 1,578
32 Tax Settlement (1)
33 Renewable Energy Production Tax Credits (164,180,328)
34 Other Federal Tax Credits (345,592)
35 (a)
Federal Income Tax Accrual (160,666,772)
FERC FORM NO. 1 (ED. 12-96)
Page 261
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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.Fishlake Power LLC MidAmerican Funding, LLC
ABA Management, L.L.C.Flat Top Holdings, LLC MidAmerican Geothermal Development Corporation
AC Eagle Corporation Flat Top Wind I, LLC MidAmerican Wind Tax Equity Holdings, LLC
AC Palm Desert Corporation Florida Network LLC Midland Escrow Services, Inc.
AC2015 Corporation Florida Network Property Management, LLC Mid-States Title Insurance Agency, LLC
Aeronavis, LLC Fluvanna Holdings 2, LLC Midwest Capital Group, Inc.
Alamo 6 Solar Holdings, LLC Fluvanna Wind Energy 2, LLC Midwest Power Midcontinent Transmission Development, LLC
Alamo 6, LLC For Rent, Inc.Midwest Power Transmission Arkansas, LLC
Alaska Gas Transmission Company, LLC Fort Dearborn Land Title Company, LLC Midwest Power Transmission Iowa, LLC
Alliance Relocations, Inc.FRTC, LLC Midwest Power Transmission Kansas, LLC
Alliance Title Group, LLC Geronimo Community Solar Gardens Holding Company, LLC Midwest Power Transmission Oklahoma, LLC
Ambassador Real Estate Company Geronimo Community Solar Gardens, LLC Midwest Power Transmission Texas, LLC
American Eagle Referral Service, LLC Gibraltar Title Services, LLC Midwest Preferred Realty, Inc.
Americana Arizona Referrals, LLC GPWH Holdings, LLC Midwest Realty Ventures, LLC
Americana Arizona, LLC Grande Prairie Land Holding, LLC Modern Transportation Services, Inc.
Americana, L.L.C.Grande Prairie Wind Holdings, LLC Modular LNG Holdings, Inc.
Apex Home Maintenance, LLC Grande Prairie Wind II, LLC Moholland Transfer, Inc.
ARE Commercial Real Estate, LLC Grande Prairie Wind, LLC Montana Alberta Tie LP Inc.
ARE Iowa, LLC Greater Metro, LLC Montana Alberta Tie US Holdings GP Inc.
Arizona HomeServices, L.L.C.Guarantee Appraisal Corporation MPT Heartland Development, LLC
Attorneys Title Holdings, Incorporated Guarantee Real Estate MTL Canyon Holdings, LLC
BDFH, Inc.Hegg Limited Referral Company, LLC NE Hub Partners, L.L.C.
Beach Properties of Florida, LLC HEGG, Realtors Inc.NE Hub Partners, L.P.
Bennion & Deville Fine Homes, Inc.HN Real Estate Group, L.L.C.Nebraska Referral, Inc.
Berkshire Hathaway Energy Company HN Real Estate Group, N.C., Inc.Nevada Electric Investment Company
BH2H Holdings, LLC HN Referral Corporation Nevada Power Company
BHE AC Holding, LLC HomeServices Insurance, Inc.Niche Storage Solutions, LLC
BHE America Transco, LLC HomeServices Lending, LLC NNGC Acquisition, LLC
BHE Canada, LLC HomeServices MidAtlantic, LLC Northeast Midstream GP, LLC
BHE Community Solar, LLC HomeServices Northeast, LLC Northeast Midstream Partners, LP
BHE Compression Services, LLC HomeServices of Alabama, Inc.Northeast Referral Group, LLC
BHE CS Holdings, LLC HomeServices of America, Inc Northern Natural Gas Company
BHE Gas, Inc.HomeServices of Arizona, LLC Northrop Realty, LLC
BHE Geothermal, LLC HomeServices of California, Inc.NRS Referral Services, LLC
BHE GT&S, LLC HomeServices of Colorado, LLC NV Energy, Inc.
BHE Hydro, LLC HomeServices of Connecticut, LLC NVE Holdings, LLC
BHE Infrastructure Group, LLC HomeServices of Florida, Inc.NVE Insurance Company, Inc.
BHE Infrastructure Services, LLC HomeServices of Georgia, LLC NW Referral Services, LLC
BHE Midcontinent Transmission Holdings, LLC HomeServices of Illinois Holdings, LLC Pacific Minerals, Inc.
BHE Pearl Solar Holdings, LLC HomeServices of Illinois, LLC PacifiCorp
BHE Pearl Solar, LLC HomeServices of Iowa, Inc.PCG Agencies, Inc.
BHE Pipeline Group, LLC HomeServices of Kentucky Real Estate Academy, LLC PCRE, L.L.C.
BHE Renewables, LLC HomeServices of Kentucky, Inc.Pickford Escrow Company, Inc.
BHE Solar, LLC HomeServices of Minnesota, LLC Pickford Holdings LLC
BHE Southwest Transmission Holdings, LLC HomeServices of MOKAN, LLC Pickford Real Estate, Inc.
BHE Texas Transco, LLC HomeServices of Nebraska, Inc.Pickford Services Company
BHE U.K. Electric, Inc.HomeServices of Nevada, LLC Pilot Butte, LLC
BHE U.K. Inc.HomeServices of New York, LLC Pinyon Pines Funding, LLC
BHE U.K. Power, Inc.HomeServices of Oregon, LLC Pinyon Pines I Holding Company, LLC
BHE U.S. Transmission, LLC HomeServices of Texas, LLC Pinyon Pines II Holding Company, LLC
BHE Wind, LLC HomeServices of the Carolinas, Inc.Pinyon Pines Projects Holding, LLC
BHER Flat Top Wind Holdings, LLC HomeServices of Washington, LLC Pinyon Pines Wind I, LLC
BHER Gopher Wind Holdings, LLC HomeServices of Wisconsin, LLC Pinyon Pines Wind II, LLC
BHER Independence Wind Holdco, LLC HomeServices Partnership Group, LLC Pivotal JAX LNG, LLC
BHER IWE Holdco, LLC HomeServices Property Management, LLC Pivotal LNG, LLC
BHER Market Operations, LLC HomeServices Referral Network, LLC PNW Referral, LLC
BHER Minerals, LLC HomeServices Relocation, LLC PPW Holdings LLC
BHER Power Resources, Inc.Houlihan Lawrence Associates, LLC Preferred Carolinas Realty, Inc.
BHER Santa Rita Holdings, LLC Houlihan/Lawrence, Inc.Premier Service Abstract, LLC
BHER Santa Rita Investment, LLC HS Franchise Holding, LLC Prime Alliance Real Estate Services, LLC
BHES CSG Holdings, LLC HSF Affiliates LLC Priority Title Corporation
BHES Pearl Solar Holdings, LLC HSGA Real Estate Group, L.L.C.Property Services Northeast, LLC
BHH Affiliates, LLC HSN Holdings, LLC Prosperity First Title, LLC
BHH Iowa Affiliates, LLC HSNV Title Holding, LLC Prosperity Home Mortgage, LLC
BHH KC Real Estate, LLC HSTX Title, LLC Pru-One, Inc.
Bishop Hill Energy II LLC HSW Affiliates Holding, LLC Real Estate Knowledge Services, LLC
Bishop Hill II Holdings, LLC Huff-Drees Realty, Inc.Real Estate Links, LLC
BPFLA Referrals, LLC IES Holding II, LLC Real Estate Referral Network, Inc.
BRER Affiliates LLC Imperial Magma LLC Real Living Real Estate, LLC
CalEnergy Company, Inc.Independence Wind Energy LLC Reece & Nichols Alliance, Inc.
CalEnergy Generation Operating Company Insight Home Inspections, LLC Reece & Nichols Realtors, Inc.
CalEnergy Geothermal Holding, LLC Intero Franchise Services, Inc.Reece Commercial, Inc.
CalEnergy International Services, Inc.Intero Nevada Referral Services, LLC Referral Associates of Georgia, LLC
CalEnergy Minerals LLC Intero Nevada, LLC Referral Network of IL, LLC
CalEnergy Operating Corporation Intero Real Estate Holdings, Inc.Referral Network of NY/NJ, LLC
CalEnergy Pacific Holdings Corp.Intero Real Estate Services, Inc.REV LNG SSL BC LLC
CalEnergy, LLC Intero Referral Services, Inc.RGS Settlements of Pennsylvania, LLC
California Energy Development Corporation Iowa Realty Co., Inc.RGS Title of Baltimore, LLC
California Energy Yuma Corporation Iowa Realty Insurance Agency, Inc.RGS Title, LLC
California Utility Holdco, LLC Iowa Title Company RHL Referral Company, L.L.C.
CanopyTitle, LLC Iroquois GP Holding Company, LLC Roberts Brothers, Inc.
Capitol Title Company Iroquois, Inc.Roy H. Long Realty Company, Inc.
Carolina Gas Services, Inc.JBRC, Inc.S.W. Hydro, Inc.
Carolina Gas Transmission, LLC Jim Huff Realty, Inc.Sage Title Group, LLC
CE Electric (NY), Inc Joe Moholland Inc.Salton Sea Power Company
CE Generation, LLC JRHBW Realty, Inc. d/b/a/ RealtySouth Salton Sea Power Generation Company
CE Geothermal, Inc.Jumbo Road Holdings, LLC Salton Sea Power L.L.C.
CE International Investments, Inc Kansas City Title, Inc.Santa Rita Wind Energy LLC
CE Leathers Company Kanstar Transmission, LLC Saranac Energy Company, Inc.
CE Turbo LLC Kentucky Residential Referral Service, LLC SCS Realty Investment Group, LLC
Champion Realty, Inc.Kentwood Commercial, LLC Sequoia Aviation Corporation
Chancellor Title Services, Inc.Kentwood Real Estate Cherry Creek, LLC Serls Prime Properties, Inc.
Columbia Title of Florida, Inc.Kentwood Real Estate City Properties, LLC Sierra Gas Holdings Company
Combined Van Lines, Inc.Kentwood Real Estate DTC, LLC Sierra Pacific Power Company
Commonsite, Inc.Kentwood Real Estate Services, LLC Silver State Property Holdings, LLC
Cordova Energy Company LLC Kentwood, LLC Silvermine Ventures LLC
Cove Point GP Holding Company, LLC Kern River Gas Transmission Company SoCal Services & Property Management
CPMLP Holdings Company, LLC Keystone Partners, LLC Solar San Antonio LLC
Crossroads Moving & Storage, Inc.KR Holding, LLC Solar Star 3, LLC
CTRE, L.L.C.L&F/Fonville Morisey Real Estate, LLC Solar Star 4, LLC
Dakota Dunes Development Company L&F/Fonville Morisey Title, LLC Solar Star California XIX, LLC
DCCO INC.Lands of Sierra, Inc.Solar Star California XX, LLC
Del Ranch Company Larabee School of Real Estate, Inc.Solar Star Funding, LLC
Denver Rental, LLC Legend Escrow Agency, Inc.Solar Star Projects Holding, LLC
Desert Valley Company LFFS, Inc.Southwest Settlement Services, LLC
DesertLink Investments, LLC Long & Foster Institute of Real Estate, LLC SSC XIX, LLC
Eastern Brine, LLC Long & Foster Insurance Agency, LLC SSC XX, LLC
Eastern Energy Field Services, Inc.Long & Foster Licensing Company, Inc.Texas Emergency Power Reserve, LLC
Eastern Energy Gas Holdings, LLC Long & Foster Mortgage Ventures, Inc.The Escrow Firm, Inc.
Eastern Gas Transmission and Storage, Inc Long & Foster Real Estate Ventures, Inc.The Long & Foster Companies, Inc.
Eastern Gathering and Processing Inc.Long & Foster Real Estate, Inc.The Referral Co.
Eastern MLP Holding Company II, LLC Long & Foster Settlement Services, LLC Thoroughbred Title Services, LLC
Ebby Halliday Alliance, LLC Lovejoy Realty, Inc.TIAC LLC
Ebby Halliday Properties, Inc.Lovejoy Referral Network LLC Tioga Properties, LLC
Ebby Halliday Real Estate, Inc.M & M Ranch Acquisition Company, LLC TLTC LLC
Edina Financial Services, Inc.M & M Ranch Holding Company, LLC Topaz Solar Farms LLC
Edina Realty Referral Network, Inc.Magma Land Company I TPZ Holding, LLC
Edina Realty Title, Inc.Magma Power Company TRMC LLC
Edina Realty, Inc.Marshall Wind Energy Holdings, LLC TX Jumbo Road Wind, LLC
Elmore Company Marshall Wind Energy LLC TX Referral Alliance, Inc.
Energy West Mining Company MEHC Investment, Inc.Volantes, LLC
Esslinger-Wooten-Maxwell, Inc.MES Holding, LLC Vulcan Power Company
E-W-M Referral Services, Inc.Metro Referral Associates, Inc.Vulcan/BN Geothermal Power Company
F&R/T LLC Metro Referrals, LLC Wailuku Holding Company, LLC
Falcon Power Operating Company MHC Inc.Wailuku Investment, LLC
Farmington Properties, Inc.MHC Investment Company Wailuku River Hydroelectric Power Company, Inc.
FFR, Inc.Mid-America Referral Network, Inc.Walnut Ridge Wind, LLC
First Network Realty, Inc.MidAmerican Central California Transco, LLC Watermark Realty Referral, Inc.
First Realty, Ltd.MidAmerican Energy Company Watermark Realty, Inc.
First Weber Illinois, LLC MidAmerican Energy Machining Services LLC Weathervane Referral Network, Inc.
First Weber Referral Associates, Inc.MidAmerican Energy Services, LLC Western Capital Group, LLC
First Weber, Inc.
With respect to members of the BHE Sub-Group, Berkshire Hathaway Energy Co. (BHE) requires all subsidiaries to pay to or receive from BHE an amount of tax based primarily on the stand-alone method of allocation. The computation includes all tax benefits from tax deductionsstemming from cost borne by utility customers.
Berkshire Hathaway Inc. Sub-Group:
121 Acquisition Co., LLC Fruit of the Loom, Inc. (Sub)NJE Holdings, LLC
21 SPC, Inc.FTI MANUFACTURING INC NJI Sales, Inc.
21st Communities, Inc.FTL Regional Sales Co., Inc.Noranco Manufacturing (USA) Ltd.
21st Mortgage Corporation Garan Central America Corp.NorGUARD Insurance Company
2K Polymer Systems, Inc.Garan Incorporated Northern States Agency, Inc.
ACCRA MANUFACTURING INC Garan Manufacturing Corp.Noveon Hilton Davis, Inc.
Accurate Installations, Inc.Garan Services Corp NSS TECHNOLOGIES INC
Acme Brick Company Garat Co. Ltd.Oak River Insurance Company
Acme Building Brands, Inc Gateway Underwriters Agency, Inc.Old United Casualty Company
Acme Management Company GEICO Advantage Insurance Company Old United Life Insurance Company
Acme Ochs Brick and Stone, Inc.GEICO Casualty Co.Orange Julius Of America
Acme Services Company, LLC GEICO Choice Insurance Company Oriental Trading Company, Inc.
Adalet/Scott Fetzer Company GEICO Corporation OTC Brands, Inc.
AEROCRAFT HEAT TREATING CO INC GEICO General Insurance Co.OTC Direct, Inc.
Aero-Hose Corporation GEICO Indemnity Co.OTC Worldwide Holdings, Inc.
AEROSPACE DYNAMICS INTERNATIONAL INC GEICO Marine Insurance Company Particle Sciences, Inc.
Affiliated Agency Operations Co.GEICO Products, Inc.PCC FLOW TECHNOLOGIES HOLDINGS INC
Affordable Housing Partners, Inc.GEICO Secure Insurance Company PCC FLOW TECHNOLOGIES INC.
AIPCF V CHI Blocker Inc Gen Re Intermediaries Corporation PCC ROLLMET INC
AJF Warehouse Distributors, Inc.General Re Corporation PCC STRUCTURALS INC
Albacor Shipping (USA) Inc.General Re Financial Products Corporation Penn Coal Land, Inc.
Albecca, Inc.General Re Life Corporation Perfection Hy-Test Company
Alpha Cargo Motor Express, Inc General Reinsurance Corporation PERMASWAGE HOLDINGS, INC.
Alu-Forge, Inc General Star Indemnity Company Pine Canyon Land Company
Ambucor Health Solutions, Inc.General Star Management Company Plaza Financial Services Co.
American All Risk Insurance Services Inc.General Star National Insurance Company Plaza Resources Co.
American Commercial Claims Administrators Inc Genesis Insurance Company PLICO
American Dairy Queen Corporation Genesis Management and Insurance Services Corporation Precision Brand Products, Inc.
AmGUARD Insurance Company Government Employees Financial Corp.PRECISION CASTPARTS CORP
Andrews Laser Works Corporation Government Employees Insurance Co.PRECISION FOUNDERS INC
Angelo Po America, Inc.GRD Holdings Corporation Precision Steel Warehouse, Inc.
ARCTURUS MANUFACTURING CORPORATION GREENVILLE METALS INC Press Forge Company
Artform International Inc.GUARDco, Inc.PRIMUS INTERNATIONAL HOLDING COMPANY
ATLANTIC PRECISION INC H. H. Brown Shoe Company, Inc.PRIMUS INTERNATIONAL INC
AVIBANK MANUFACTURING INC H.J. Justin & Sons, Inc.Princeton Insurance Company
AzGUARD Insurance Company HACKNEY LADISH INC Priority One Financial Services, Inc.
Bayport Systems, Inc.Halex/Scott Fetzer Company PRISM Holdings LLC
Ben Bridge Jeweler, Inc.HAMILTON AVIATION INC PRISM Plastics, Inc.
Benjamin Moore & Co.Hawthorn Life International, Ltd.Pro Installations, Inc.
Benson Industries, Inc.HeatPipe Technology, Inc.Procrane Holdings, Inc.
Benson, Ltd.HELICOMB INTERNATIONAL INC PROGRESSIVE INCORPORATED
Berkshire Hathaway Assurance Corporation Henley Holdings, LLC PROTECTIVE COATING INC
Berkshire Hathaway Automotive Inc.Hohmann & Barnard, Inc.QS Partners LLC
Berkshire Hathaway Credit Corporation Homefirst Agency, Inc.QS Security Services LLC
Berkshire Hathaway Direct Insurance Company Homemakers Plaza, Inc.R.C. Willey Home Furnishings
Berkshire Hathaway Finance Corporation HOWELL PENNCRAFT, INC.Radnor Specialty Insurance Company
Berkshire Hathaway Global Insurance Services, LLC HUNTINGTON ALLOYS CORPORATION Railserve, Inc.
Berkshire Hathaway Homestate Insurance Company IdeaLife Insurance Company Railsplitter Holdings Corporation
Berkshire Hathaway Inc.Ingersoll Cutting Tool Company Inc.RATHGIBSON HOLDING CO LLC
Berkshire Hathaway Life Insurance Company of Nebraska Innovative Building Products, Inc Redwood Fire and Casualty Insurance Company
Berkshire Hathaway Specialty Insurance Company Innovative Coatings Technology Corporation RENTCO Trailer Corporation
BH Columbia Inc.Interco Tobacco Retailers, Inc.Resolute Management Inc.
BH Credit LLC International Dairy Queen, Inc.Richline Group, Inc
BH Finance, Inc.International Insurance Underwriters, Inc.Ringwalt & Liesche Co.
BH Holding H Jewelry Inc.Intrepid JSB, Inc.Rio Grande, Inc.
BH Holding LLC Ironwood Plastics Inc Roxell USA, Inc.
BH Holding S Furniture Inc Iscar Metals Inc.Sager Electrical Supply Co. Inc
BH Media Group, Inc.ITTI Group USA Holdings Inc.Santa Fe Pacific Insurance Company
BH Shoe Holdings, Inc.ITTI Investment Holdings Inc.Santa Fe Pacific Pipeline Holdings, Inc.
BHA Minority Interest Holdco, Inc.J.L. Mining Company Santa Fe Pacific Pipelines, Inc.
BHG Life Insurance Company Johns Manville China, Ltd.Santa Fe Pacific Railroad Company
BHG Structured Settlements, Inc.Johns Manville Corporation Scott Fetzer Financial Group, Inc.
BHHC Special Risks Insurance Company Johns Manville, Inc.ScottCare Corporation
BHSF, Inc.Jordan's Furniture, Inc.See's Candies, Inc.
biBERK Insurance Services, Inc.Joyce Steel Erection LLC See's Candy Shops, Incorporated
Blue Chip Stamps, Inc.Justin Brands, Inc.Seventeenth Street Realty, Inc.
BN Leasing Corporation Kahn Ventures, Inc.SFEG Corp.
BNSF Communications, Inc.Karmelkorn Shoppes, Inc.Shaw Asia Pacific Holdings, LLC
BNSF Logistics Ocean Line, Inc.KEN'S SPRAY EQUIPMENT, INC.Shaw Contract Flooring Services, Inc.
BNSF Logistics, LLC Kinexo, Inc.Shaw Diversified Services, Inc.
BNSF Railway Company KITCO Fiber Optics, Inc.Shaw Floors, Inc.
BNSF Spectrum, Inc.KLUNE HOLDINGS INC Shaw Funding Company
Boat America Corporation KLUNE INDUSTRIES INC Shaw Industries Group, Inc.
Boat Owners Association of the United States L.A. Terminals, Inc.Shaw Industries, Inc.
Boat/U.S, Inc.LAKELAND MANUFACTURING, INC.Shaw International Services, Inc.
Borsheim Jewelry Company, Inc Larson-Juhl International LLC Shaw Retail Properties, Inc.
BR Agency, Inc.LeachGarner, Inc.Shaw Sports Turf California, Inc.
Brainy Toys, Inc.Lipotec USA, Inc.Shaw Transport, Inc.
Brilliant National Services, Inc.LiquidPower Specialty Products, Inc.Shultz Steel Company
BRITTAIN MACHINE INC LJ AERO HOLDINGS INC SHX Flooring, Inc.
Brooks Sports, Inc.LJ SYNCH HOLDINGS INC SidePlate Systems, Inc.
Burlington Northern Railroad Holdings, Inc.LMG Ventures, LLC Smilemakers Canada Inc.
Burlington Northern Santa Fe, LLC Loch Vale Logistics, Inc.Smilemakers, Inc.
Business Wire, Inc.Los Angeles Junction Railway Company SN Management, Inc.
CALEDONIAN ALLOYS INC LSPI Holdings Inc.Soco West, Inc.
Camp Manufacturing Company Lubrizol Advanced Materials Holding Corporation Sonnax Transmission Company
Cannon Equipment LLC Lubrizol Advanced Materials, Inc.Southern Energy Homes, Inc.
CANNON MUSKEGON CORPORATION Lubrizol Global Management, Inc.SOUTHWEST UNITED INDUSTRIES INC
Carefree/Scott Fetzer Company Lubrizol Inter-Americas Corporation SPECIAL METALS CORPORATION
CARLTON FORGE WORKS Lubrizol International Management Corporation Spectra Contract Flooring Puerto Rico, Inc.
Cavalier Homes, Inc.Lubrizol International, Inc.SPS INTERNATIONAL INVESTMENT COMPANY
Central States Indemnity Co. of Omaha Lubrizol Life Science, Inc.SPS TECHNOLOGIES LLC
Central States of Omaha Companies, Inc.Lubrizol Overseas Trading Corporation SPS Technologies Mexico LLC
Charter Brokerage Holdings Corp.M & C Products, Inc.SSP-SiMatrix Inc.
Chemtool Incorporated M&M Manufacturing, Inc.Stahl/Scott Fetzer Company
CJE II M2 Liability Solutions, Inc.Star Lake Railroad Company
Claims Services, Inc.Mapletree Transportation, Inc.Summit Distribution Services, Inc.
Clayton Commercial Buildings, Inc.Marathon Suspension Systems, Inc.SXP SCHULZ XTRUDED PRODUCTS LLC
Clayton Education Corp.Marmon Beverage Technologies, Inc.TBS USA, Inc.
Clayton Homes, Inc.Marmon Crane Services, Inc.Tenn-Tex Plastics, Inc.
Clayton Properties Group II, Inc.Marmon Distribution Services, Inc.TEXAS HONING INC
Clayton Properties Group, Inc.Marmon Energy Services Company The Ben Bridge Corporation
Clayton Supply, Inc.Marmon Engineered Components Company The BVD Licensing Corporation
Clayton, Inc.Marmon Foodservice Technologies LLC The Duracell Company
Clean Living Supplies, Inc.Marmon Foodservice Technologies, Inc.The Fechheimer Brothers Co.
CMH Capital, Inc.Marmon Holdings, Inc.The Indecor Group, Inc.
CMH Homes, Inc.Marmon Link Inc The Lubrizol Corporation
CMH Manufacturing West, Inc.Marmon Railroad Services LLC The Medical Protective Company
CMH Manufacturing, Inc.Marmon Renew, Inc.The Pampered Chef, Ltd.
CMH Services, Inc.Marmon Retail & Highway Technologies Company LLC The Scott Fetzer Company
CMH Transport, Inc.Marmon Retail Products, Inc.The Zia Company
Coil Master Corporation Marmon Retail Store Equipment LLC THI ACQUISITION INC
Columbia Insurance Company Marmon Retail Technologies Company TIMET REAL ESTATE CORPORATION
Complementary Coatings Corporation Marmon Tubing, Fittings & Wire Products, Inc.TITANIUM METALS CORPORATION
Composites Horizons LLC Marmon Water, Inc.TM City Leasing Inc.
Consumer Value Products, Inc.Marmon Wire & Cable, Inc.TMI Climate Solutions, Inc.
Continental Divide Insurance Company Marmon-Herrington Company Tool-Flo Manufacturing, Inc.
Cort Business Services Corporation Maryland Ventures, Inc..Top Five Club, Inc.
Criterion Insurance Agency McCarty-Hull Cigar Company, Inc.Total Quality Apparel Resources
Crown Holdco One, Inc.McLane Beverage Distribution, Inc.TPC European Holdings, LTD.
Crown Holdco Two, Inc.McLane Beverage Holding, Inc.TPC North America, Ltd.
Crown Parent, Inc.McLane Company, Inc.Transco Railcar Repair Inc
CSI Life Insurance Company McLane Eastern, Inc.Transco Railway Products Inc.
CTB Credit Corp McLane Express, Inc.Transco, Inc.
CTB Inc.McLane Foods, Inc.Transportation Technology Services, Inc.
CTB International Corp McLane Foodservice Distribution, Inc.TRH Holding Corp.
CTB IW INC McLane Foodservice, Inc.Triangle Suspension Systems, Inc.
CTB Midwest Inc McLane Mid-Atlantic, Inc.Tricycle, Inc.
CTB MN Investments McLane Midwest, Inc.TS City Leasing Inc
CTB Technology Holding Inc.McLane Minnesota, Inc.TSE Brakes, Inc.
CTMS North America, Inc.McLane Network Solutions, Inc.TTI JV 1
Cumberland Asset Management, Inc.McLane New Jersey, Inc.TTI JV 2
Cypress Insurance Company McLane Ohio, Inc.TTI, Inc.
D.I. Properties Inc.McLane Southern, Inc.Tucker Safety Products, Inc.
DCI Marketing Inc.McLane Suneast, Inc.TXFM, Inc.
Denver Brick Company McLane Tri-States, Inc.U.S. Investment Corporation
DESIGNED METAL CONNECTIONS, INC.McLane Western, Inc.U.S. Underwriters Insurance Co.
DICKSON TESTING CO INC MCWILLIAMS FORGE COMPANY UCFS Europe Company
Display Technologies LLC Medical Protective Finance Corporation UCFS International Holding Company
DL Trading Holdings I, Inc.MedPro Group, Inc Unified Supply Chain, Inc.
DQ Funding Corporation MedPro Risk Retention Services, Inc.Uni-Form Components Co.
DQF, Inc.Merit Distribution Services, Inc.Union Tank Car Company
DQGC, Inc.METALAC FASTENERS INC Union Underwear Co., Inc
Duracell Industrial Operations, Inc.Meyn LLC United Consumer Financial Services Company
Duracell U.S. Operations Inc MFS Fleet, Inc.United Direct Finance, Inc.
EastGUARD Insurance Company MH Site Construction, Inc.United States Aviation Underwriters, Incorporated
Eco Color Company Midwest Northwest Properties, Inc.United States Liability Insurance Company
Ecodyne Corporation Miller-Sage, Inc.UNIVERSITY SWAGING CORPORATION
Ellis & Watts Global Industries, Inc.Mindware Corporation UTLX Company
Elm Street Corporation MiTek Holdings, Inc.Van Enterprises, Inc.
Empire Distributors of Colorado, Inc.MiTek Inc.Vanderbilt ABS Corp.
Empire Distributors of North Carolina, Inc.MiTek Industries, Inc.Vanderbilt Mortgage and Finance, Inc.
Empire Distributors of Tennessee, Inc.MiTek Mezzanine Systems, Inc.Vanity Fair, Inc.
Empire Distributors, Inc.MLMIC Insurance Company Veritas Insurance Group, Inc.
ENVIRONMENT ONE CORPORATION MLMIC Services, Inc.VERO BEACH FLIGHT TRAINING ACADEMY, INC.
EXACTA AEROSPACE INC Morgantown-National Supply, Inc.Vesta Intermediate Funding, Inc.
Executive Jet Management, Inc.Mount Vernon Fire Insurance Company VFI-Mexico, Inc.
Exponential Technology Group, Inc.Mount Vernon Specialty Insurance Company Visilinx, Inc.
Exsif Worldwide, Inc.Mouser Electronics, Inc.Vision Retailing, Inc.
ExtruMed, Inc.Mouser JV 1, Inc VT Insurance Acquisition Sub Inc.
FATIGUE TECHNOLOGY INC Mouser JV 2 Wayne/Scott Fetzer Company
Financial Services Plus, Inc.MPP Co., Inc.WEAVER MANUFACTURING INC
Finial Holdings, Inc.MPP Pipeline Corporation Webb Wheel Products, Inc.
Finial Reinsurance Company MS Property Company Wellfleet Insurance Company
First Berkshire Hathaway Life Insurance Company MW Wholesale, Inc.Wellfleet New York Insurance Company
FlightSafety Capital Corp.National Fire & Marine Insurance Company Western Builders Supply, Inc.
FlightSafety Defense Corporation National Indemnity Company Western Fruit Express Company
FlightSafety Development Corp.National Indemnity Company of Mid-America Western/Scott Fetzer Company
FlightSafety International Inc.National Indemnity Company of the South WestGUARD Insurance Company
FlightSafety International Middle East Inc.National Liability & Fire Insurance Company Whittaker, Clark & Daniels, Inc.
FlightSafety New York, Inc.Nationwide Uniforms World Book Encyclopedia, Inc.
FlightSafety Properties, Inc.Nebraska Furniture Mart, Inc.World Book, Inc.
Floors, Inc.NetJets Aviation, Inc.World Book/Scott Fetzer Company
Focused Technology Solutions, Inc.NetJets Card Holdings, Inc.World Investments, Inc.
Fontaine Commercial Trailer, Inc.NetJets Card Partners, Inc.Worldwide Containers, Inc.
Fontaine Engineered Products, Inc.NetJets Europe Holdings, LLC WPLG, Inc.
Fontaine Fifth Wheel Company NetJets Inc.WYMAN GORDON COMPANY
Fontaine Modification Company NetJets International, Inc.WYMAN GORDON FORGINGS CLEVELAND INC
Fontaine Spray Suppression Company NetJets Sales, Inc.WYMAN GORDON FORGINGS INC
Fontaine Trailer Company LLC NetJets Services, Inc.WYMAN GORDON INVESTMENT CASTINGS INC
Forest River Holdings, Inc.NetJets U.S., Inc.WYMAN GORDON PENNSYLVANIA LLC
Forest River, Inc.New England Asset Management, Inc.X-L-Co., Inc.
Frasca International, Inc.NewCo D&W LLC XTRA Companies, Inc.
Freedom Warehouse Corp.NFM Custom Countertops, LLC XTRA Corporation
Fruit of the Loom Direct, Inc.NFM of Kansas, Inc.XTRA Finance Corporation
Fruit of the Loom Trading Company NFM SERVICES, LLC XTRA Intermodal, Inc.
Fruit of the Loom, Inc.
FERC FORM NO. 1 (ED. 12-96)Page 261
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 orother balance sheet accounts.9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT
BEGINNING OF YEAR
BALANCE AT END OF
YEAR DISTRIBUTION OF TAXES CHARGED
LineNo.(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 1,328,052 0 2,395,143 2,525,623 1,197,572 0 1,770,965 (m)624,178
7 Property Tax Property Tax California 0 0 2,827,733 2,827,733 0 0 2,683,798 (n)143,935
8 Property Tax Property Tax Colorado 2,700,000 0 2,259,639 2,719,639 2,240,000 0 2,258,396 (o)1,243
9 Property Tax Property Tax Idaho 3,467,572 0 6,008,833 5,928,697 3,547,708 0 5,816,070 (p)192,763
10 Property Tax Property Tax Montana 2,787,003 0 6,470,644 6,024,605 3,233,042 0 4,276,488 (q)2,194,156
11 Property Tax Property Tax New Mexico 0 0 19,927 19,927 0 0 19,927
12 Property Tax Property Tax Oregon 110,487 19,318,920 39,374,881 40,237,023 0 20,070,575 37,595,485 (r)1,779,396
13 Property Tax Property Tax Utah 322,949 0 79,878,330 79,331,627 869,652 0 79,345,204 (s)533,126
14 Property Tax Property Tax Washington 11,800,000 0 9,378,096 11,478,096 9,700,000 0 9,247,151 (t)130,945
15 Property Tax Property Tax Wyoming 10,868,831 0 20,764,505 21,251,084 10,382,252 0 19,331,047 (u)1,433,458
16 Goshute Possessory Interest Property Tax Idaho 0 0 33,432 33,432 0 0 33,432
17 Sho-Ban Possessory Interest Property Tax Utah 0 0 228,996 228,996 0 228,996
18 Navajo Possessory Interest Property Tax Utah 7,631 0 15,453 15,357 7,727 0 15,453
19 Ute Possessory Interest Property Tax Colorado 0 0 36,562 36,562 0 0 36,562
20 Crow Possessory Tax Property Tax Montana 0 0 79,000 79,000 0 79,000
21 Umatilla Possessory Interest Property Tax Oregon 0 0 113,836 113,836 0 0 113,836
22 Subtotal Property Tax 33,392,525 19,318,920 169,885,010 172,772,237 31,256,953 20,070,575 162,851,810 7,033,200
23 Subtotal Real Estate Tax 0 0 0 0
24 Federal Unemployment Tax Unemployment Tax 3,549 0 216,725 214,422 5,852 0 (v)216,725
25 Unemployment Tax Unemployment Tax California 973 0 16,885 17,389 469 0 (w)16,885
26 Unemployment Tax Unemployment Tax Idaho 550 0 14,926 14,729 747 0 (x)14,926
27 Unemployment Tax Unemployment Tax Missouri 0 0 174 174 0 0 (y)174
28 Unemployment Tax Unemployment Tax Montana 0 0 155 155 0 0 (z)155
29 Unemployment Tax Unemployment Tax Oregon 23,228 5,000 1,340,655 1,309,019 54,361 4,497 (aa)1,340,655
30 Unemployment Tax Unemployment Tax Texas 0 0 51 58 (7)0 (ab)51
31 Unemployment Tax Unemployment Tax South Carolina 0 0 69 69 0 0 (ac)69
32 Unemployment Tax Unemployment Tax Utah 1,593 0 145,905 142,812 4,686 0 (ad)145,905
Kind of Tax (See Instruction 5)Type of Tax State Tax Year
Taxes
Accrued
(Account236)
PrepaidTaxes(Include inAccount
165)
Taxes
ChargedDuring Year
Taxes PaidDuring Year Adjustments
Taxes
Accrued
(Account236)
PrepaidTaxes
(Included
inAccount165)
Electric(Account408.1, 409.1)
Extraordinary
Items
(Account409.3)
Adjustmentto Ret.Earnings(Account
439)
Other
33 Unemployment Tax Unemployment Tax Washington 18,738 0 87,153 91,823 14,068 0 (ae)87,153
34 Unemployment Tax Unemployment Tax Wyoming 578 0 330,331 327,235 3,674 0 (af)330,331
35 Subtotal Unemployment Tax 49,209 5,000 2,153,029 2,117,885 83,850 4,497 2,153,029
36 Use Tax Sales And Use Tax California 35,528 0 331,668 313,725 53,471 0 (ag)331,668
37 Use Tax Sales And Use Tax Idaho 37,593 0 106,969 139,835 4,727 0 (ah)106,969
38 Use Tax Sales And Use Tax Utah 511,162 0 4,983,635 5,261,889 232,908 0 (ai)4,983,635
39 Use Tax Sales And Use Tax Washington 47,454 0 490,285 504,233 33,506 0 (aj)490,285
40 Use Tax Sales And Use Tax Wyoming 77,231 0 1,092,498 1,123,513 46,216 0 (ak)1,092,498
41 Subtotal Sales And Use Tax 708,968 0 7,005,055 7,343,195 370,828 0 7,005,055
42 Federal Income Tax Income Tax 0 0 (160,666,772)(132,901,248)(a)27,765,524 0 0 (165,049,160)(al)4,382,388
43 Income Tax Income Tax Arizona 0 0 (9,565)(8,368)(b)1,197 0 0 (9,910)(am)345
44 Franchise - Income Tax Income Tax California 0 0 (270,543)(517,704)(c)(247,161)0 0 (325,750)(an)55,207
45 Income Tax Income Tax Colorado 0 0 211 (d)(211)0 0 223 (ao)(12)
46 Income Tax Income Tax Idaho 0 0 (595,027)(471,928)(e)123,099 0 0 (657,765)(ap)62,738
47 Corporate License - Income Tax Income Tax Montana 0 0 20,775 5,267 (f)(15,508)0 0 15,076 (aq)5,699
48 Income Tax Income Tax New Mexico 0 0 746 (33,925)(g)(34,671)0 0 (1,947)(ar)2,693
49 Excise - Income Tax Income Tax Oregon 0 0 (163,513)(880,063)(h)(716,550)0 0 (583,142)(as)419,629
50 City of Portland - Income Tax Income Tax Oregon 0 0 (23,232)(27,209)(i)(3,977)0 0 (25,697)(at)2,465
51 Corporate Activity Tax Income Tax Oregon 0 0 6,127,877 5,513,948 (j)(613,929)0 0 6,127,877
52 Metro Business Income Tax Income Tax Oregon 0 0 18,971 19,000 (k)29 0 0 18,971
53 Public Utility Tax Income Tax South Carolina 0 0 25 25 0 0 25
54 Income Tax Income Tax Utah 0 0 1,365,219 1,366,639 (l)1,420 0 0 921,494 (au)443,725
55 Subtotal Income Tax 0 0 (154,194,828)(127,935,566)26,259,262 0 0 (159,569,705)5,374,877
56 Natural Gas Use Tax Excise Tax Washington 234,279 0 3,164,983 2,916,340 482,922 0 (av)3,164,983
57 Forest Excise Tax Excise Tax Washington 0 0 31,615 31,615 0 0 (aw)31,615
58 Subtotal Excise Tax 234,279 0 3,196,598 2,947,955 482,922 0 3,196,598
59 Subtotal Fuel Tax 0 0 0 0
60 Subtotal Federal Insurance Tax 0 0 0 0
61 Local Franchise Tax Franchise Tax California 1,297,404 0 1,304,367 1,224,871 1,376,900 0 1,304,367
62 Local Franchise Tax Franchise Tax Oregon 5,322,619 0 29,131,152 29,478,412 4,975,359 0 29,131,152
63 Local Franchise Tax Franchise Tax Utah 0 0 7,615 7,615 0 0 7,615
64 Local Franchise Tax Franchise Tax Wyoming 296,500 0 1,848,674 1,857,474 287,700 0 1,848,674
65 Subtotal Franchise Tax 6,916,523 0 32,291,808 32,568,372 6,639,959 0 32,291,808
66 Subtotal Miscellaneous Other Tax 0 0 0 0
67 Subtotal Other Federal Tax 0 0 0 0
68 KWh Other State Tax Idaho 16,574 0 48,874 48,587 16,861 0 48,874
69 Wholesale Energy Other State Tax Montana 42,000 0 192,855 180,855 54,000 0 192,855
70 Energy License Other State Tax Montana 60,000 0 268,822 253,822 75,000 0 268,822
71 Commerce Tax Other State Tax Nevada 15,000 0 27,778 27,778 15,000 0 27,778
72 Department of Energy Other State Tax Oregon 0 749,600 1,609,682 1,720,165 0 860,083 1,609,682
73 Public Utility Tax Other State Tax Washington 945,000 0 13,887,414 13,392,414 1,440,000 0 13,887,414
74 Business and Occupation Tax Other State Tax Washington 3,700 0 26,198 25,898 4,000 0 26,198
75 Wind Generation Tax Other State Tax Wyoming 2,331,145 0 2,105,610 2,344,795 2,091,960 0 2,105,610
76 Annual Report Other State Tax Wyoming 0 0 95,880 95,880 0 0 95,880
77 Subtotal Other State Tax 3,413,419 749,600 18,263,113 18,090,194 3,696,821 860,083 18,263,113
78 Subtotal Other Property Tax 0 0 0 0
79 Subtotal Other Use Tax 0 0 0 0
80 Subtotal Other Advalorem Tax 0 0 0 0
81 Subtotal Other License And Fees Tax 0 0 0 0
82 Federal FICA Tax Payroll Tax 24,572,077 7,685 38,148,998 49,444,535 13,293,562 24,707 (ax)38,148,998
83 Tri-Met Transit Tax Payroll Tax Oregon 425,163 0 1,055,221 1,068,758 411,626 0 (ay)1,055,221
84 Lane Transit Tax Payroll Tax Oregon 0 0 654 654 0 0 (az)654
85 Family and Medical Leave Payroll Tax Washington 18,054 0 31,554 40,179 9,429 0 (ba)31,554
86 Subtotal Payroll Tax 25,015,294 7,685 39,236,427 50,554,126 13,714,617 24,707 39,236,427
87 Subtotal Advalorem Tax 0 0 0 0
88 Subtotal Other Allocated Tax 0 0 0 0
89 Subtotal Severance Tax 0 0 0 0
90 Subtotal Penalty Tax 0 0 0 0
91 Subtotal Other Taxes And Fees 0 0 0 0
40 TOTAL 69,730,217 20,081,205 117,836,212 158,458,398 26,259,262 56,245,950 20,959,862 53,837,026 63,999,186
FERC FORM NO. 1 (ED. 12-96)
Page 262-263
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents incometaxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parentcompany.
(b) Concept: TaxAdjustments
Account 143, Other accounts receivable, which represents a reclassification of thebalance.
(c) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents incometaxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parentcompany.
(d) Concept: TaxAdjustments
Account 143, Other accounts receivable, which represents a reclassification of thebalance.
(e) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents incometaxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parentcompany.
(f) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents incometaxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parentcompany.
(g) Concept: TaxAdjustments
Account 143, Other accounts receivable, which represents a reclassification of thebalance.
(h) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents incometaxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parentcompany.
(i) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents incometaxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parentcompany.
(j) Concept: TaxAdjustments
$ (28,502) Account 146, Accounts receivable from other associated companies 642,431 Account 182.3, Other Regulatory Assets$ 613,929
(k) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents incometaxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parentcompany.
(l) Concept: TaxAdjustments
Account 146, Accounts receivable from other associated companies, which represents incometaxes receivable from Berkshire Hathaway Energy Company, PacifiCorp’s indirect parentcompany.
(m) Concept: TaxesIncurredOther
Account 182.3, Other regulatory assets, which represents deferral of Oregon's share of Cholla Unit 4 Arizona property taxes.
(n) Concept: TaxesIncurredOther
Account 408.2, Taxes other than income taxes, other income and deductions
(o) Concept: TaxesIncurredOther
Account 408.2, Taxes other than income taxes, other income and deductions
(p) Concept: TaxesIncurredOther
$ 762 Account 408.2, Taxes other than income taxes, other income and deductions 192,001 Account 107, Construction work in progress$ 192,763
(q) Concept: TaxesIncurredOther
Account 107, Construction work in progress
(r) Concept: TaxesIncurredOther
$ 26,819 Account 408.2, Taxes other than income taxes, other income and deductions 173,268 Account 589, Rents 1,579,309 Account 107, Construction work in progress$
1,779,396
(s) Concept: TaxesIncurredOther
$ 46,662 Account 408.2, Taxes other than income taxes, other income and deductions 486,464 Account 107, Construction work in progress$ 533,126
(t) Concept: TaxesIncurredOther
$ 54,626 Account 408.2, Taxes other than income taxes, other income and deductions 76.319 Account 107, Construction work in progress$ 130,945
(u) Concept: TaxesIncurredOther
$ 2,416 Account 408.2, Taxes other than income taxes, other income and deductions 14,981 Account 589, Rents 1,416,061 Account 107, Construction work in progress$ 1,433,458
(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.
(af) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(ag) Concept: TaxesIncurredOther
Charged to same account as related goods.
(ah) Concept: TaxesIncurredOther
Charged to same account as related goods.
(ai) Concept: TaxesIncurredOther
Charged to same account as related goods.
(aj) Concept: TaxesIncurredOther
Charged to same account as related goods.
(ak) Concept: TaxesIncurredOther
Charged to same account as related goods.
(al) Concept: TaxesIncurredOther
Account 409.2, Income Taxes - Federal, which represents income tax applicable to other income and deductions.
(am) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(an) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(ao) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.
(ap) Concept: TaxesIncurredOther
Account 409.2, Income taxes - Other, which represents state 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 151, Fuel stock
(aw) Concept: TaxesIncurredOther
Account 408.2, Taxes other than income taxes, other income and deductions
(ax) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(ay) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(az) Concept: TaxesIncurredOther
Payroll taxes are generally charged to operations and maintenance expense and constructionwork in progress.
(ba) 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
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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
LineNo.Account Subdivisions(a)
Balance at
Beginning ofYear(b)
AccountNo.
(c)
Amount(d)
AccountNo.
(e)
Amount(f)Adjustments(g)
Balance
at End ofYear(h)
AveragePeriod ofAllocation
to Income
(i)
ADJUSTMENTEXPLANATION
(j)
1 Electric Utility
2 3%
3 4%
4 7%
5 10%3,847,843 (a)
411.4 1,332,693 2,515,150 39.3 years
6 30 2,293,570 420 336,191 (b)
420 151,194 (e)(6,328)2,472,239 24.0 years
7 Idaho (Pre-2013)25,976 (c)
411.4 6,485 19,491 39.3 years
8 Idaho 30,492 (d)
420 5,621 24,871 30.0 years
8 TOTAL Electric (Enter Totalof lines 2 thru 7)6,197,881 336,191 1,495,993 (6,328)5,031,751
9 Other (List separately andshow 3%, 4%, 7%, 10%and TOTAL)
10 `
11 Idaho (nonutility)6,128,355 190 2,112,695 420 1,278,232 (f)(48,913)6,913,905 30.0 years
47 OTHER TOTAL 6,128,355 2,112,695 1,278,232 (48,913)6,913,905
48 GRAND TOTAL 12,326,236 2,448,886 2,774,225 (55,241)11,945,656
FERC FORM NO. 1 (ED. 12-89)Page 266-267
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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.
(f) Concept: AccumulatedDeferredInvestmentTaxCreditsAdjustments
Represents an adjustment to the prior year balance that was made in the current year.FERC FORM NO. 1 (ED. 12-89)
Page 266-267
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
OTHER DEFERRED CREDITS (Account 253)
1. Report below the particulars (details) called for concerning other deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
DEBITS
Line
No.
Description and Other Deferred Credits
(a)
Balance at Beginning ofYear(b)
Contra
Account
(c)
Amount(d)
Credits
(e)
Balance at End of Year
(f)
1 Working Capital Deposits 4,817,524 936,999 5,754,523
2 Reclamation Costs - Trapper Mine 6,961,463 131 260,303 1,650,693 8,351,853
3 Western Coal Carriers Benefits Obligation 9,521,000 131, 557 1,833,083 714,083 8,402,000
4 Deferred Compensation Plans 8,222,304 131 1,157,176 1,616,074 8,681,202
5 Long-Term Incentive Plan 23,260,988 131 3,583,065 6,258,204 25,936,127
6 Regulated Environmental Liabilities 58,511,228 131, 182.3 10,025,740 26,835,710 75,321,198
7 Non-Regulated Environmental Liabilities 1,625,120 131, 426.5 101,775 76,790 1,600,135
8 (a)
Unearned Joint Use Pole Contact Revenue 2,992,452 454 6,880,361 7,256,672 3,368,763
9 Miscellaneous Security Deposits 109,978 131, 172 44,609 34,800 100,169
10 (b)
Lease Incentives 93,186 931 31,062 62,124
11 Cowlitz/Lewis River Operations andMaintenance (1)131,567 539 317,917 319,459 133,109
12 Employee Housing Security Deposits 21,000 131 3,700 3,900 21,200
13 Cogeneration Bonds - Sunnyside 413,417 413,417
14 Transmission Security Deposits 9,537,050 252 89,000 4,472,940 13,920,990
15 Transmission Service Deposits 672,567 131, 456 2,328,837 3,939,829 2,283,559
16 MCI F.O.G. Wire Lease (1)558,945 454 3,356,543 3,357,118 559,520
17 Unamortized Contract Values 36,447,683 242 18,133,410 18,314,273
18 Accrued Right-of-Way Obligations 2,266,777 107, 232, 566 875,210 461,684 1,853,251
19 (c)
Facility Use Fee 793,201 451, 456 161,379 109,976 741,798
20 Deer Creek Accrued Royalties 14,347,296 501,630 14,848,926
21 Deferred Revenue - Other 14,059 185 14,059 16,439 16,439
22 Coal Contract Costs - Naughton 2,238,687 131 2,238,687
23 Klamath Settlement Obligation 33,000,000 253, 545 30,622,061 2,377,939
24 Transmission Study Deposits for FinancialSecurity 44,379,660 44,379,660
25 Transmission Study Deposits for Site Control 260,000 260,000
47 TOTAL 216,557,492 82,057,977 103,202,660 237,702,175
FERC FORM NO. 1 (ED. 12-94)Page 269
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionOfOtherDeferredCredits
The weighted average remaining life is one year.
(b) Concept: DescriptionOfOtherDeferredCredits
The weighted average remaining life is two years.
(c) Concept: DescriptionOfOtherDeferredCredits
The weighted average remaining life is ten years.
FERC FORM NO. 1 (ED. 12-94)Page 269
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022
Year/Period of Report
End of: 2021/ Q4
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property.
2. For other (Specify),include deferrals relating to other income and deductions.
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line
No.
Account
(a)
Balance atBeginning of
Year
(b)
AmountsDebited to
Account 410.1
(c)
AmountsCredited to
Account 411.1
(d)
AmountsDebited to
Account 410.2
(e)
Amounts
Credited toAccount411.2(f)
AccountCredited(g)
Amount
(h)
AccountDebited(i)
Amount
(j)
Balance atEnd of Year(k)
1 AcceleratedAmortization (Account281)
2 Electric
3 Defense Facilities
4 Pollution ControlFacilities 152,581,995 1,462,673 10,460,812 143,583,856
5 Other
5.1 Other:
8 TOTAL Electric (Enter
Total of lines 3 thru 7)152,581,995 1,462,673 10,460,812 143,583,856
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) (Totalof 8, 15 and 16)152,581,995 1,462,673 10,460,812 143,583,856
18 Classification of TOTAL
19 Federal Income Tax 124,407,207 654,667 7,991,269 117,070,605
20 State Income Tax 28,174,788 808,006 2,469,543 26,513,251
21 Local Income Tax
FERC FORM NO. 1 (ED. 12-96)Page 272-273
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization.
2. For other (Specify),include deferrals relating to other income and deductions.
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line
No.
Account
(a)
Balance atBeginning of
Year
(b)
AmountsDebited to
Account 410.1
(c)
AmountsCredited to
Account 411.1
(d)
Amounts
Debited toAccount410.2(e)
Amounts
Credited toAccount411.2(f)
AccountCredited(g)
Amount
(h)
AccountDebited(i)
Amount
(j)
Balance atEnd of Year(k)
1 Account 282
2 Electric 2,908,481,325 582,494,156 439,499,143 182.3,
254 4,598,287 182.3,
254 7,265,989 3,054,144,040
3 Gas
4 Other (Specify)
5 Total (Total of lines 2
thru 4)2,908,481,325 582,494,156 439,499,143 4,598,287 7,265,989 3,054,144,040
6
7
8
9
TOTAL Account 282
(Total of Lines 5 thru
8)
2,908,481,325 582,494,156 439,499,143 4,598,287 7,265,989 3,054,144,040
10 Classification of
TOTAL
11 Federal Income Tax 2,392,566,817 434,686,173 321,384,580 3,052,202 5,473,319 2,508,289,527
12 State Income Tax 515,914,508 147,807,983 118,114,563 1,546,085 1,792,670 545,854,513
13 Local Income Tax
FERC FORM NO. 1 (ED. 12-96)
Page 274-275
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
3. Provide in the space below explanations for Page 276. Include amounts relating to insignificant items listed under Other.4. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line
No.
Account
(a)
Balance at
Beginning of
Year(b)
Amounts
Debited to
Account 410.1(c)
Amounts
Credited to
Account 411.1(d)
Amounts
Debited to
Account 410.2(e)
AmountsCredited toAccount411.2
(f)
AccountCredited(g)
Amount
(h)
AccountDebited(i)
Amount
(j)
Balance atEnd of Year(k)
1 Account 283
2 Electric
3 Regulatory Assets 342,606,717 105,758,102 77,649,867 2,605,834 8,156,962 182.3,
190, 283 34,600,862 182.3,
190, 283 1,438,125 332,001,087
4 Other 22,465,024 12,297,194 7,248,835 39,402,375 33,339,327 190, 283 536,974 190, 283 17,501,460 50,540,917
9 TOTAL Electric (Totalof lines 3 thru 8)365,071,741 118,055,296 84,898,702 42,008,209 41,496,289 35,137,836 18,939,585 382,542,004
10 Gas
11
12
13
14
15
16
17 TOTAL Gas (Total oflines 11 thru 16)
18 TOTAL Other
19
TOTAL (Acct 283)
(Enter Total of lines 9,
17 and 18)
365,071,741 118,055,296 84,898,702 42,008,209 41,496,289 35,137,836 18,939,585 382,542,004
20 Classification of
TOTAL
21 Federal Income Tax 297,886,223 95,825,586 68,791,471 37,964,544 33,914,789 28,821,339 11,979,036 312,127,790
22 State Income Tax 67,185,518 22,229,710 16,107,231 4,043,665 7,581,500 6,316,497 6,960,549 70,414,214
23 Local Income Tax
NOTES
FERC FORM NO. 1 (ED. 12-96)Page 276-277
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
OTHER REGULATORY LIABILITIES (Account 254)
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
DEBITS
Line
No.
Description and Purpose of OtherRegulatory Liabilities(a)
Balance at Beginning ofCurrent Quarter/Year(b)
Account
Credited
(c)
Amount(d)
Credits
(e)
Balance at End ofCurrent Quarter/Year(f)
1 DSM Balancing Account - CA 356,563 440,442,444 1,259,286 902,723
2 DSM Balancing Account - ID 180,721 180,721
3 DSM Balancing Account - WA 3,551,130 440,442,444 11,063,124 10,861,557 3,349,563
4 Oregon Energy Conservation Charge 3,729,429 440,442,444 36,238,860 36,388,699 3,879,268
5 Deferred Excess Net Power Costs - CA 842,039 1,494,997 2,337,036
6 (a)
Deferred Excess Net Power Costs - WA 24,552,560 555 21,964,824 178,172 2,765,908
7 Deferred Excess Net Power Costs - WY 586,639 182 586,639
8 (b)
Deferred Excess RECs in Rates - UT 1,658,278 456 1,155,346 822,473 1,325,405
9 Deferred Excess RECs in Rates - WA 39,819 39,819
10 (c)
Deferred Excess RECs in Rates - WY 190,298 456,431 212,362 463,270 441,206
11 Decoupling Mechanism - WA 2,008,356 182.3 1,676,605 331,751
12 Income Tax - Flow Through - WA 5,673,582 411 5,673,582
13 (d)
Investment Tax Credit 1,031,312 190.0 356,499 125 674,938
14 (e)
Deferred Income Tax Electric 1,456,252,383 190,282,411 163,799,904 13,666,377 1,306,118,856
15 (f)
Excess Income Tax Deferral 27,227,145 440,442,444 20,367,275 12,298,482 19,158,352
16 Tax on Bonus Depreciation - WY (1)322,667 440,442,444 333,020 354,837 344,484
17 (g)
Other Postretirement 10,827,899 (k)30,317 15,498,889 26,296,471
18 (h)
Postemployment Costs 3,902,859 (l)872,778 5,525,632 8,555,713
19 Revenues Subject to Refund - WA 2,847,187 2,847,187
20 Bridger Mine Depreciation and Reclamation -
OR 3,639,439 3,639,439
21 Bridger Mine Depreciation and Reclamation -
WA 2,549,408 2,549,408
22 Cholla Unit No. 4 Closure andDecommissioning Costs - ID 2,518,308 2,518,308
23 Cholla Plant Unit No. 4 Decommissioning -OR 9,183,623 232 825,729 8,357,894
24 Cholla Plant Unit No. 4 Decommissioning -UT 20,444,811 232 1,396,313 19,048,498
25 Deferral of Coal Plant Closure Costs - WA 1,355,736 1,355,736
26 Klamath Hydro Dam Removal - CA 261,298 261,298
27 (i)
Unrealized Gain on Derivative Contracts 244 42,701,332 95,743,511 53,042,179
28
(j)
Greenhouse Gas Allowance ComplianceCosts - CA 5,106,931 456 117,507 1,215,431 6,204,855
29 Emergency Service Resiliency Program - CA 619,099 908 4,918 614,181
30 Solar Incentive Program - UT 2,407,519 908 1,024,994 65,923 1,448,448
31 STEP Pilot Program - UT 17,283,104 440,442,444,107 17,937,816 11,517,203 10,862,491
32 Renewable Portfolio Standards Compliance -
OR (1)
126,351 555 527,302 688,481 287,530
33 Deferred Independent Evaluator Costs - UT 705,726 131 355,981 349,745
34 Alternative Rate For Energy (CARE) - CA 608,001 131,142 72,397 90,378 625,982
35 Utah Home Energy Lifeline 1,779,586 131,142 705,983 296,700 1,370,303
36 California Energy Savings AssistanceProgram 749,405 440,442,444 383,476 237,018 602,947
37 FERC Rate True-up - OR (3)14,512,339 456 6,845,758 273,769 7,940,350
38 BPA Balancing Account - WA 317,569 517,441 835,010
39 BPA Balancing Account - ID 1,348,963 440,442 1,321,051 27,912
40 Blue Sky - CA 241,583 440,442 110,125 2,868 134,326
41 Blue Sky - OR 2,346,214 440,442,456 6,911,562 6,803,426 2,238,078
42 Blue Sky - ID 122,470 440,442 27,095 149,565
43 Blue Sky - UT 7,126,250 440,442 1,603,980 132,415 5,654,685
44 Blue Sky - WA 588,203 440,442 88,057 500,146
45 Blue Sky - WY 767,981 440,442 109,902 658,079
46 Depreciation Study Deferral - ID (1)150,511 403 150,511
47 Depreciation Study Deferral - OR (3)7,935,376 440,442,444 2,660,452 82,440 5,357,364
48 Deferred Steam Accelerated Depreciation -
WA (3)52,254,334 440,442,444 17,418,112 34,836,222
49 Direct Access 5-Year Opt Out - OR (10)8,019,148 442 1,769,316 557,932 6,807,764
50 Transportation Electrification Program - CA 309,200 232,440,442,444 162,185 72,782 219,797
51 Oregon Clean Fuels Program 2,474,850 456 1,036,985 3,674,351 5,112,216
52 Wildfire Protection Plan - UT 997,769 997,769
41 TOTAL 1,700,242,286 371,832,165 234,845,082 1,563,255,203
FERC FORM NO. 1 (REV 02-04)Page 278
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average remaining life is approximately one year.
(b) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average remaining life is approximately one year.
(c) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average remaining life is approximately one year.
(d) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average remaining life is 39 years.
(e) 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.
(f) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average remaining life is approximately two years.
(g) 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.
(h) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average remaining life is four years.
(i) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Weighted average remaining life is one year.
(j) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
Includes California Solar on Multifamily Affordable Housing.
(k) Concept: DecreaseInOtherRegulatoryLiabilities
Other postretirement costs are associated with labor and generally charged to operations and maintenance expense and construction work in progress. Other postretirement settlements are charged to Account 926, Employee pensions and benefits.
(l) Concept: DecreaseInOtherRegulatoryLiabilities
Other postemployment costs are associated with labor and generally charged to operations and maintenance expense and work in progress.FERC FORM NO. 1 (REV 02-04)
Page 278
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 billingpurposes, 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 respondentif such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.)7. See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases.8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
9. Include unmetered sales. Provide details of such Sales in a footnote.
Line
No.
Title of Account
(a)
Operating Revenues
Year to Date
Quarterly/Annual(b)
Operating Revenues
Previous year (no
Quarterly)(c)
MEGAWATT HOURS
SOLD Year to Date
Quarterly/Annual(d)
MEGAWATT HOURSSOLD AmountPrevious year (noQuarterly)
(e)
AVG.NO.CUSTOMERS PER
MONTH Current
Year (noQuarterly)(f)
AVG.NO.
CUSTOMERSPER MONTHPreviousYear (no
Quarterly)
(g)
1
2 1,958,953,927 1,961,692,056 17,904,789 17,150,116 1,744,648 1,713,382
3
4 1,593,558,298 1,614,104,509 18,839,074 17,727,147 221,531 217,070
5 1,277,511,464 1,345,785,490 19,415,943 19,563,642 33,024 33,096
6 14,615,254 17,750,042 114,128 119,073 3,577 3,576
7
8
9
10 4,844,638,943 4,939,332,097 56,273,934 54,559,978 2,002,780 1,967,124
11 193,761,115 189,250,874 5,112,797 5,249,066
12 5,038,400,058 5,128,582,971 61,386,731 59,809,044 2,002,780 1,967,124
13 3,239,918
14 5,038,400,058 5,125,343,053 61,386,731 59,809,044 2,002,780 1,967,124
15
16 6,408,701 7,348,688
17 (a)8,632,229 6,952,421
18 9,345 7,350
19 18,185,617 18,294,555
20
21 (b)59,425,166 63,833,287
22 161,828,009 111,710,807
23
24
25
26 254,489,067 208,147,108
27 5,292,889,125 5,333,490,161
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 HighwayLighting
(445) Other Sales to PublicAuthorities
(446) Sales to Railroads andRailways
(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 ServiceRevenues
(453) Sales of Water and WaterPower
(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 OperatingRevenues
TOTAL Other Operating Revenues
TOTAL Electric Operating Revenues
Line12, column (b) includes $ 263,654,000 of unbilled revenues.
Line12, column (d) includes 3,273,707 MWH relating to unbilled revenues
FERC FORM NO. 1 (REV. 12-05)
Page 300-301
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: MiscellaneousServiceRevenues
Account 451, Miscellaneous service revenues, includes the following items that were $250,000 or greater during the years ended December 31:
2021 2020
Account service charges - application fees, disconnects, reconnects and returned check charges $6,887,413 $5,911,936
Customer contract flat rate billings and facility buyout charges $1,737,897 $1,135,646
(b) Concept: OtherElectricRevenue
Account 456, Other electric revenues, includes the following items that were $250,000 or greater during the years ended December 31:
2021 2020
Fly-ash and by-product sales $15,364,905 $6,851,586
Renewable energy credit sales, net of deferrals and amortization $13,757,319 $3,720,207
Wind-based ancillary services $10,429,829 $12,605,274
Amortization of Oregon retail customers' allocated share of the incremental Open Access Transmission Tariff revenues associated with FERC Docket No. ER11-3643, net ofdeferrals $6,845,756 $23,787,598
Amortization of California greenhouse gas allowance revenue $7,660,217 $12,764,541
Revenues from generation interconnection and transmission service request studies $1,580,721 $854,804
Amortization of Oregon clean fuels program credits $1,036,986 $551,170
Maintenance charges for work on joint-owned transmission facilities $593,004 $449,880
Steam sales $363,351 $440,116
Timber sales $762,608 (a)
Phase shifting equipment fee from Western Electricity Coordinating Council $588,884 (a)
Net gain/(loss) on sales of materials and supplies inventory (a)$1,056,572
Revenue from other requested customer studies (a)$270,719
(a) Amount is less than $250,000.
FERC FORM NO. 1 (REV. 12-05)
Page 300-301
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
1. The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved
tariff. All amounts separately billed must be detailed below.
Line
No.
Description of Service
(a)
Balance at End of Quarter 1
(b)
Balance at End of Quarter 2
(c)
Balance at End of Quarter 3
(d)
Balance at End of Year
(e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL
FERC FORM NO. 1 (NEW. 12-05)Page 302
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 rateschedule 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 waterheating 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 ofCustomers(d)
KWh of Sales PerCustomer(e)
Revenue Per KWhSold(f)
1 CALIFORNIA - 06BLSKY01R - BLUESKYENERGY (1)0.0000
2 CALIFORNIA - 06CHCK000R-CA RESCHECK M 1 0.0000
3 CALIFORNIA - 06LNX00311 - LINE EXT
80% GUARANTEE 3,857 0.0000
4 CALIFORNIA - 06NBDDL136-NET BL LOW
INC RES DEL NORTE 22 2,165 2 11,000 0.0984
5 CALIFORNIA - 06NBLDL136-NET BILLING
LOW INC-RES 76 8,481 8 9,500 0.1116
6 CALIFORNIA - 06NBLDN136-NET BLNGLOW INC-RES DELNORTE 117 11,901 12 9,750 0.1017
7 CALIFORNIA - 06NETBL136-CALIFORNIANET BILLING RES 288 28,994 29 9,931 0.1007
8 CALIFORNIA - 06NETMT135 - CA RESNET METERING 3,203 393,671 540 5,931 0.1229
9 CALIFORNIA - 06OALT015R-OUTD AR
LGT SR 248 61,759 264 939 0.2490
10 CALIFORNIA - 06RESD000D-RES SRVC 175,146 22,893,764 17,017 10,292 0.1307
11 CALIFORNIA - 06RESDDL06-CA LOWINCOME 128,901 16,789,615 11,826 10,900 0.1303
12 CALIFORNIA - 06RGNSV025-CA SMALLGENERAL SVC-RES 1,349 281,154 479 2,816 0.2084
13 CALIFORNIA - 06RNM25135 - CA NET
MTR, GEN SVC-RES 177 1 0.0000
14 CALIFORNIA - 06RESD0DM9 - MULTI
FAMILY 270 35,297 6 45,000 0.1307
15 CALIFORNIA - 06RESD0DS8-MULT FAMSBMET 1,782 170,184 20 89,100 0.0955
16 CALIFORNIA - INCOME TAX DEFERRALADJUSTMENTS 1,233,812 0.0000
17 CALIFORNIA - REVENUE_ACCOUNTINGADJUSTMENTS (702,747)0.0000
18 CALIFORNIA - 06RESD00DN - CA RESSRVC - DEL NORTE CTY 77,204 10,076,394 6,848 11,274 0.1305
19 CALIFORNIA - DSM REVENUE-
RESIDENTIAL 775,203 0.0000
20 CALIFORNIA - BLUE SKY REVENUE-
RESIDENTIAL 183,273 0.0000
21 CALIFORNIA - OTHER CUSTOMERRETAIL REVENUE 31,057 0.0000
22 IDAHO - 07LNX00010-MNTHLY 80%GUAR 1,087 0.0000
23 IDAHO - 07LNX00035-ADV 80%MO GUAR 2,172 0.0000
24 IDAHO - 07NBL36136-ID TOU RES NETBILLING 163 10,256 17 9,056 0.0629
25 IDAHO - 07NETBL136-ID RES NETBILLING 483 39,013 100 4,830 0.0808
26 7,713 728,640 1,110 6,949 0.0945
IDAHO - 07NETMT135 - ID RESIDENTIAL
NET METERING
27 IDAHO - 07NMT36135-IDAHO TIME-OF-DAY RES NET MTR 3,477 208,835 280 12,418 0.0601
28 IDAHO - 07OALCO007-CUST OWN LIGHT 11 4,114 1 11,000 0.3740
29 IDAHO - 07OALT07AR-SECURITY AR LG 88 36,139 111 793 0.4107
30 IDAHO - 07RESD0001-RES SRVC 568,763 65,088,781 57,556 9,882 0.1144
31 IDAHO - 07RESD0036-RES SRVC-OPTIO 176,670 17,386,289 10,470 16,874 0.0984
32 IDAHO - 07RGNSV06A-ID LRG GENERAL
SVC-RES 348 27,811 4 87,000 0.0799
33 IDAHO - 07RGNSV23A-ID SMALLGENERAL SVC-RES 10,149 1,137,520 1,164 8,719 0.1121
34 IDAHO - 07RN23A136-RES NET BILLINGSMALL GEN SVC (112)1 0.0000
35 IDAHO - 07RNM23135-RES USE NET MTRSMALL GEN SVC 262 20,702 9 29,000 0.0793
36 IDAHO - 07UPPL000R-BASE SCH FALL (5)2 (2,500)0.0000
37 IDAHO - INCOME TAX DEFERRALADJUSTMENTS 50,041 0.0000
38 IDAHO - REVENUE_ACCOUNTINGADJUSTMENTS (302,748)0.0000
39 IDAHO - DSM REVENUE-RESIDENTIAL 1,918,623 0.0000
40 IDAHO - BLUE SKY REVENUE-
RESIDENTIAL 38,919 0.0000
41 OREGON - 01CHCK000R-RES CHECK
MTR 1 0.0000
42 OREGON - 01COST0004 - 01RESD0004 5,269,225 276,660,004 0.0525
43 OREGON - 01COST0006 - 01RESD0006 437 19,426 0.0445
44 OREGON - 01COSTR023, OR RES GEN
SRV, COST BASED 97,766 5,026,980 0.0514
45 OREGON - 01COSTR028, OR RES GENSVC>30KW CST BSD 44,866 2,254,857 0.0503
46 OREGON - 01FXRENEWR - FixedRenewable Blue Sky (1)0.0000
47 OREGON - 01HABIT004 - 01RESD0004 65,059 3,369,980 0.0518
48 OREGON - 01HABTR023-RES GEN SVC
HABITAT BLND 220 11,420 0.0519
49 OREGON - 01LNX00102-LINE EXT 80% G 176 0.0000
50 OREGON - 01LNX00109-REF/NREF ADV+7,731 0.0000
51 OREGON - 01NETMT135-NET METERING 3,619,450 8,346 0.0000
52 OREGON - 01NMTOU135-TOU NETMETERING 28,939 53 0.0000
53 OREGON - 01OALTB15R-OR OUTD ARLGT RES 1,940 290,828 2,271 854 0.1499
54 OREGON - 01PTOU0004 - 01RESD0004 14,136 756,969 0.0535
55 OREGON - 01PTOU0005-01RESEV05T
TOU ENERGY SUP SVC 4 160 0.0401
56 OREGON - 01PTOURB23-RES GEN SVC;
TOU SUPPLY SVC 9 477 0.0530
57 OREGON - 01RENEW004 - 01RESD0004 479,011 24,583,599 0.0513
58 OREGON - 01RENWR023-RENEWUSAGE SPLY SVC-GEN SVC 569 29,872 0.0525
59 OREGON - 01RESD0004-RES SRVC 317,977,276 514,161 0.0000
60 OREGON - 01RESD0006-RES TIME-OF-DA 23,656 44 0.0000
61 OREGON - 01RESD004T - RES TimeOption 733,550 990 0.0000
62 OREGON - 01RESEV05T-RES ELECTRICVEHICLE TOU VIR 211 0.0000
63 OREGON - 01RGNSB023-SMALLGENERAL SVC-RES 7,826,169 17,045 0.0000
64 OREGON - 01RGNSB028 - GENERAL SVC
> 30 KW - RES 1,453,488 225 0.0000
65 OREGON - 01RGNSB23T-RES GEN SVC
TOU PORTFOLIO 704 2 0.0000
66 OREGON - 01RNETM023-NET METERRESIDENTIAL GEN SVC 84,232 201 0.0000
67 OREGON - 01RNETM028-NET METERRESIDENTIAL GEN SVC 68,304 5 0.0000
68 OREGON - 01UPPL000R-BASE SCH FALL 2 0.0000
69 OREGON - 01VIR04136-OR RES VOLUME
INCENTIVE 413,065 469 0.0000
70 OREGON - 01VIR06136-OR RES VOLUMEINCENTIVE 378 1 0.0000
71 OREGON - RESIDENTIAL CUSTOMERBILL CREDITS (165,055)0.0000
72 OREGON - OR GAIN ON SALE OF ASSET 17,563 0.0000
73 OREGON - INCOME TAX DEFERRAL
ADJUSTMENTS 2,461,678 0.0000
74 OREGON - REVENUE_ACCOUNTINGADJUSTMENTS (1,490,819)0.0000
75 OREGON - SOLAR FEED-IN REVENUE 2,243,883 0.0000
76 OREGON - COMMUNITY SOLARREVENUE 238,937 0.0000
77 OREGON - DSM REVENUE-RESIDENTIAL 21,451,304 0.0000
78 OREGON - BLUE SKY REVENUE-RESIDENTIAL 601,813 0.0000
79 UTAH - 08BLSKY01R-BLUESKY ENERGY (8)0.0000
80 UTAH - 08CFR00001-MTH FACILITY S 735 0.0000
81 UTAH - 08CGENR136-UT RESTRANSITION GENERATION 692 76,288 78 8,872 0.1102
82 UTAH - 08CGNSL136-UT RESTRANSITION GEN-SOLEIL 1,894 198,095 500 3,788 0.1046
83 UTAH - 08CGR01136-UTAH RESIDENTIALTRANS GEN 141,101 14,985,181 17,031 8,285 0.1062
84 UTAH - 08CGR01137-UT RES CUST
GENERATION 137 17,353 1,862,030 2,484 6,986 0.1073
85 UTAH - 08CGR02136-UT RES TOU
TRANSITION GEN 153 15,880 17 9,000 0.1038
86 UTAH - 08CGR02137-UT RES TOU CUSTGEN 137 31 3,204 4 7,750 0.1034
87 UTAH - 08CGR03136-UTAH LOW INC RESTRANS GEN 469 50,208 59 7,817 0.1071
88 UTAH - 08CGR03137-UT LOW INC RESCUST GEN 137 33 3,455 4 8,250 0.1047
89 UTAH - 08CGR06136-RES USE, GEN SVCRATE, MANUAL 234 22,964 2 117,000 0.0981
90 UTAH - 08CGR23136-RESIDENTIAL
SMALL GEN SVC 253 21,172 7 36,143 0.0837
91 UTAH - 08CGRA1137-UT RES CUST GEN
AGGEGATED 29 3,248 6 4,833 0.1120
92 UTAH - 08CGS23136-RES SMALL GENSVC MANUAL 321 36,208 37 8,676 0.1128
93 UTAH - 08CHCK000R-UT RES CHECK M 1 0.0000
94 UTAH - 08COOLKPRR - Utah Cool Keeper
Program (122)0.0000
95 UTAH - 08LNX00001-MTHLY 80% GUAR 14,058 0.0000
96 UTAH - 08LNX00005-MTHLY MIN GUAR 66 0.0000
97 UTAH - 08LNX00013-80% MNTHLY MIN 30,814 0.0000
98 UTAH - 08LNX00108-ANN COST MTHLY 1,188 0.0000
99 UTAH - 08MHTP0006-MOBILE HOME &TRAILER 12,165 896,942 9 1,351,667 0.0737
100 UTAH - 08MHTP0023-MOBILE HOME &TRAILER 127 9,654 1 127,000 0.0760
101 UTAH - 08NETAGFEE-> 6 NET METER
AGGREGATION FEE 675 2 0.0000
102 UTAH - 08NETMT135 - Net Metering 139,756 16,145,126 29,655 4,713 0.1155
103 UTAH - 08NMT03135-LOW INCOME RESNET METERING 1,181 127,591 188 6,282 0.1080
104 UTAH - 08OALT007R-SECURITY AR LG 2,130 357,126 2,175 979 0.1677
105 UTAH - 08PTLD000R-POST TOP LIGHT 1 105 2 500 0.1046
106 UTAH - 08RCG23136-RES NET METER,SMALL GEN SVC 110 12,308 13 8,462 0.1119
107 UTAH - 08RCG23137-RES SMALL GENSVC, CUST GEN 47 4,510 3 15,667 0.0960
108 UTAH - 08RESD0001-RES SRVC 7,215,138 769,858,951 796,442 9,059 0.1067
109 UTAH - 08RESD0002-RES SRVC-OPTIO 3,483 367,360 391 8,908 0.1055
110 UTAH - 08RESD0003-LIFELINE PRGRM 157,762 16,686,578 20,350 7,752 0.1058
111 UTAH - 08RESD002E-RES ELCTRC
VEHICLE TOU PILOT 7,473 628,071 468 15,968 0.0840
112 UTAH - 08RESD003E-UT RES LOW INC
ELEC V TOU PLT 4 402 1 4,000 0.1005
113 UTAH - 08RGNSV006-GEN SRVC-RES 125,934 9,281,577 310 406,239 0.0737
114 UTAH - 08RGNSV008-UT RESIDENTIALGENERAL SVC 783 54,372 1 783,000 0.0694
115 UTAH - 08RGNSV023-GEN SRVC-RES 104,085 10,924,584 14,439 7,209 0.1050
116 UTAH - 08RGNSV06A-UT SMALLGENERAL SVC-RES-TOU 8,422 654,901 30 280,733 0.0778
117 UTAH - 08RGNSV06B-UT SMALLGENERAL SVC-RES-TOU 61 0.0000
118 UTAH - 08RNM06135 - UT NET MTR, GENSVC-RES 3,604 292,209 11 327,636 0.0811
119 UTAH - 08RNM23135 - UT NET MTR, GEN
SVC-RES 1,143 152,944 433 2,640 0.1338
120 UTAH - 08RNM6A135-RES GEN SVC NET
METERING 7 3,220 3 2,333 0.4600
121 UTAH - 08RTCVLNGA-TCV LNX GAR 3,019 0.0000
122 UTAH - 08SSLR0001 - RESIDENTIALSUBSCRB SOLAR 29,254 3,427,695 0.1172
123 UTAH - 08SSLR0002-UT TOU RES -
SUBSCRIBER SOLAR 1 101 0.1009
124 UTAH - 08SSLR0003-RES LOW INC
SUBSCR SOLAR 240 28,927 22 10,909 0.1205
125 UTAH - 08SSLRRG23-RES SMALL GEN
SV SUBSCR SOLAR 55 8,203 17 3,235 0.1491
126 UTAH - 08UPPL000R-BASE SCH FALL 4 0.0000
127 UTAH - RESIDENTIAL CUSTOMER BILLCREDITS (344,147)0.0000
128 UTAH - INCOME TAX DEFERRAL
ADJUSTMENTS 0.0000
129 UTAH - REVENUE_ACCOUNTING
ADJUSTMENTS (766,585)0.0000
130 UTAH - REVENUE ADJUSTMENT -DEFERRED NPC 10,282,444 0.0000
131 UTAH - SOLAR FEED-IN REVENUE 1,241,225 0.0000
132 UTAH - DSM REVENUE-RESIDENTIAL 7,621,782 0.0000
133 UTAH - BLUE SKY REVENUE-RESIDENTIAL 3,543,226 0.0000
134 (2)0.0000
WASHINGTON - 02BLSKY01R-BLUESKY
ENERGY
135 WASHINGTON - 02LNX00102-LINE EXT80% G 44 0.0000
136 WASHINGTON - 02LNX00109-REF/NREFADV +1,005 0.0000
137 WASHINGTON - 02NETMT135 - WA RESNET METERING 14,390 1,453,985 1,576 9,131 0.1010
138 WASHINGTON - 02OALTB15R-WA OUTD
AR LGT RES 886 96,693 979 905 0.1091
139 WASHINGTON - 02RESD0016-WA RES
SRVC 1,487,391 141,251,360 103,337 14,394 0.0950
140 WASHINGTON - 02RESD0017-BILLASSISTANC 83,289 7,918,398 5,545 15,021 0.0951
141 WASHINGTON - 02RESD0018-WA 3PHASE RES 2,080 215,288 76 27,368 0.1035
142 WASHINGTON - 02RESD018X-WA 3PHASE RES 278 28,177 11 25,273 0.1014
143 WASHINGTON - 02RESD019T-WA
RESIDENTIAL TOU PILOT 18 1,632 2 9,000 0.0907
144 WASHINGTON - 02RGNSB024-WA SMALL
GENERAL SVC-RES 21,144 2,533,718 3,455 6,120 0.1198
145 WASHINGTON - 02RGNSB036-RES LRGGEN SVC < 1000 KW 1,888 150,255 3 629,333 0.0796
146 WASHINGTON - 02RNM24135-RES NETMETER SMALL GEN SVC 219 27,455 46 4,761 0.1254
147 WASHINGTON - RESIDENTIALCUSTOMER BILL CREDITS (108,660)0.0000
148 WASHINGTON - INCOME TAX DEFERRALADJUSTMENTS 899,027 0.0000
149 WASHINGTON - REVENUE ADJUSTMENT
- DEFERRED NPC 43,006 0.0000
150
WASHINGTON -
REVENUE_ACCOUNTING
ADJUSTMENTS
(1,316,630)0.0000
151 WASHINGTON - DSM REVENUE-
RESIDENTIAL 4,863,758 0.0000
152 WASHINGTON - BLUE SKY REVENUE-RESIDENTIAL 404,258 0.0000
153 WASHINGTON - ALT REVENUEPROGRAM ADJUSTMENTS (1,790,179)0.0000
154 WYOMING - 05BLSKY01R-BLUESKYENERGY (1)0.0000
155 WYOMING - 05LNX00102-LINE EXT 80%
G 727 0.0000
156 WYOMING - 05NETMT135 -
EXPERIMENTAL PARTIAL REQ - A 2,403 281,658 302 7,957 0.1172
157 WYOMING - 05OALT015R-OUTD AR LGTSR - A 794 100,479 944 841 0.1265
158 WYOMING - 05RESD0002-WY RES SRVC- A 910,017 96,528,919 103,046 8,831 0.1061
159 WYOMING - 05RESD0019-WY RES TOUPILOT 10 887 1 10,000 0.0887
160 WYOMING - 05RGNSV025-WY SMALLGENERAL SVC-RES - A 9,657 1,154,881 1,572 6,142 0.1196
161 WYOMING - 09OALT207R-SECURITY AR
LG - A 67 1 0.0000
162 WYOMING - 05RESD0002-WY RES SRVC
- B 113,441 12,187,306 12,746 8,900 0.1074
163 WYOMING - 05RGNSV025-WY SMALLGENERAL SVC-RES - B 527 82,127 152 3,467 0.1558
164 WYOMING - 09OALT207R-SECURITY ARLG - B 34 7,880 41 829 0.2318
165 WYOMING - 05LNX00109-REF/NREF ADV+6,918 0.0000
166 WYOMING - 05NETMT135 -EXPERIMENTAL PARTIAL REQ - B 584 66,621 81 7,210 0.1141
167 WYOMING - 05OALT015R-OUTD AR LGT
SR - A 33 4,406 42 786 0.1335
168 WYOMING - 09RES00002 1 0.0000
169 WYOMING - 09RESD0002 4 0.0000
170 WYOMING - INCOME TAX DEFERRAL
ADJUSTMENTS 131,377 0.0000
171 WYOMING - REVENUE ADJUSTMENT -
DEFERRED NPC (118,294)0.0000
172 WYOMING - REVENUE_ACCOUNTINGADJUSTMENTS (371,295)0.0000
173 WYOMING - DSM REVENUE-RESIDENTIAL - A 684,752 0.0000
174 WYOMING - DSM REVENUE-RESIDENTIAL GEN SVC - A 25,216 0.0000
175 WYOMING - BLUE SKY REVENUE-
RESIDENTIAL - A 300,603 0.0000
176 WYOMING - DSM REVENUE-
RESIDENTIAL - B 86,864 0.0000
177 WYOMING - DSM REVENUE-RESIDENTIAL GEN SVC - B 1,736 0.0000
178 WYOMING - BLUE SKY REVENUE-RESIDENTIAL - B 22,388 0.0000
179 LESS MULTIPLE BILLINGS (26,209)
41 TOTAL Billed Residential Sales 17,754,521 1,945,963,927 1,744,648 10,263 0.1087
42 TOTAL Unbilled Rev. (See Instr. 6)150,268 12,990,000 0.0007
43 TOTAL 17,904,789 1,958,953,927 1,744,648 10,263 0.1094
FERC FORM NO. 1 (ED. 12-95)Page 304
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 rateschedule 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 waterheating 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 ofCustomers(d)
KWh of Sales PerCustomer(e)
Revenue Per KWhSold(f)
1 CALIFORNIA - 06GNSV0025-CA GENSRVC 53,157 8,929,243 6,484 8,198 0.1680
2 CALIFORNIA - 06GNSV025F-GEN SRVC-<20 911 170,794 85 10,718 0.1875
3 CALIFORNIA - 06GNSV0A32-GEN SRVC-
20 KW 87,446 12,423,412 1,137 76,909 0.1421
4 CALIFORNIA - 06LGSV048T-LRG GEN
SERV 26,763 2,558,303 8 3,345,375 0.0956
5 CALIFORNIA - 06NMT48135-CA GEN SVC
NET MTR->500 KW 2,483 228,201 1 2,483,000 0.0919
6 CALIFORNIA - 06LGSV0A36-LRG GENSRVC-O 57,038 6,943,210 140 407,414 0.1217
7 CALIFORNIA - 06LNX00102-LINE EXT80% G 3,068 0 0.0000
8 CALIFORNIA - 06LNX00109-REF/NREFADV +108,600 0 0.0000
9 CALIFORNIA - 06LNX00110-REF/NREF
ADV +(2,194)0 0.0000
10 CALIFORNIA - 06LNX00311 - LINE EXT
80% GUARANTEE 26,636 0 0.0000
11 CALIFORNIA - 06LNX00312 - CA IRG LINEEXT 2,617 0 0.0000
12 CALIFORNIA - 06NBL25136-CA NET BILLGEN SVC < 20 KW 18 2,756 4 4,500 0.1531
13 CALIFORNIA - 06NBL32136-CA NET BILLGEN SVC >= 20 KW 225 29,833 1 225,000 0.1326
14 CALIFORNIA - 06NMT36135-CA GEN SVC
NET MTR->100 KW 3,144 408,109 7 449,143 0.1298
15 CALIFORNIA - 06OALT015N-OUTD AR
LGT SR 601 151,783 447 1,345 0.2526
16 CALIFORNIA - 06RCFL0042-AIRWAY &ATHLE 149 30,456 37 4,027 0.2044
17 CALIFORNIA - 06NMT25135-CA GEN SVCNET MTR<20KW 232 42,216 43 5,395 0.1820
18 CALIFORNIA - 06NMT32135-CA GEN SVCNET MTR>20KW 2,939 449,491 36 81,639 0.1529
19 CALIFORNIA - INCOME TAX DEFERRALADJUSTMENTS 762,559 0 0.0000
20 CALIFORNIA - REVENUE_ACCOUNTING
ADJUSTMENTS (412,014)0 0.0000
21 CALIFORNIA - DSM REVENUE-
COMMERCIAL 456,819 0 0.0000
22 CALIFORNIA - BLUE SKY REVENUE-COMMERCIAL 13,319 0 0.0000
23 CALIFORNIA - OTHER CUSTOMERRETAIL REVENUE 29,917 0 0.0000
24 IDAHO - 07CISH0019-COMM & IND SPA 4,681 402,615 80 58,513 0.0860
25 IDAHO - 07GNSV0006-GEN SRVC-LRG P 241,363 19,846,593 1,039 232,303 0.0822
26 IDAHO - 07GNSV0009-GEN SRVC-HI VO 58,649 3,645,503 3 19,549,667 0.0622
27 IDAHO - 07GNSV0023-GEN SRVC-SML P 175,876 17,392,038 7,759 22,667 0.0989
28 IDAHO - 07GNSV0035-GEN SRVCOPTION 309 24,829 3 103,000 0.0804
29 IDAHO - 07GNSV006A-GEN SRVC-LRG P 19,134 1,682,172 160 118,845 0.0879
30 IDAHO - 07GNSV023A-GEN SRVC-SML P 26,448 2,613,302 1,272 20,792 0.0988
31 IDAHO - 07GNSV023F-GEN SRVC SML P 6 1,691 4 1,500 0.2819
32 IDAHO - 07GNSV035A-GENSRVCOPTION 28 4,476 1 28,000 0.1598
33 IDAHO - 07LNX00010-MNTHLY 80%GUAR 29,877 0 0.0000
34 IDAHO - 07LNX00035-ADV 80%MO GUAR 223,099 0 0.0000
35 IDAHO - 07LNX00040-ADV+REFCHG+80%35,884 0 0.0000
36 IDAHO - 07OALT007N-SECURITY AR LG 221 85,798 166 1,331 0.3882
37 IDAHO - 07OALT07AN-SECURITY AR LG 10 4,148 11 909 0.4148
38 IDAHO - 07TCVLNXGN-TCV LNX - 80%GAR - NON RES 775 0 0.0000
39 IDAHO - 07LNX00312 - ID LINE EXT 5,438 0 0.0000
40 IDAHO - 07NBL23136-ID NET BILLING
SML GEN SVC 20 (103)3 6,667 (0.0051)
41 IDAHO - 07NBL6A136-ID NET BILLINGLRG GEN SVC 101 8,928 1 101,000 0.0884
42 IDAHO - 07NMT06135 - ID NET MTR -LARGE GEN SVC 2,947 258,196 8 368,375 0.0876
43 IDAHO - 07NMT23135 - ID NET MTR -SMALL GEN SVC 1,249 105,093 40 31,225 0.0841
44 IDAHO - 07NMT6A135-NET METERINGLARGE GEN SVC 98 6,983 1 98,000 0.0713
45 IDAHO - 07LNX00015-ANNUAL 80%GUAR 509 0 0.0000
46 IDAHO - 07LNX00311 - LINE EXT 80%GUARANTEE 35,200 0 0.0000
47 IDAHO - 07LNX00300 - 80% MONTHLYMIN GUAR + 80%1,461 0 0.0000
48 IDAHO - INCOME TAX DEFERRALADJUSTMENTS 33,265 0 0.0000
49 IDAHO - REVENUE_ACCOUNTING
ADJUSTMENTS (182,935)0 0.0000
50 IDAHO - DSM REVENUE-COMMERCIAL 1,037,447 0 0.0000
51 IDAHO - BLUE SKY REVENUE-COMMERCIAL 3,717 1 0.0000
52 OREGON - 01COST0023, OR GEN SRV,COST BASED 1,025,493 50,804,316 0 0.0495
53 OREGON - 01COST0048 - 01LGSV0048 1,543,085 65,493,865 0 0.0424
54 OREGON - 01COST023F - OR GEN SRV -COST-BASED 2,928 153,003 0 0.0523
55 OREGON - 01COSTB023 - OR GEN SRV,CST-BSD SPLY 24,020 1,205,654 0 0.0502
56 OREGON - 01COSTEV45-ELECTVEHICLE DC FAST CHG SVC 3,777 187,839 0 0.0497
57 OREGON - 01COSTL030 - OR LRG GENSRV, CST >200 kW 1,044,042 41,537,815 0 0.0398
58 OREGON - 01COSTS028, OR GEN SERV,
COST > 30kW 1,921,958 96,461,351 0 0.0502
59 OREGON - 01COSTS029-OR GEN SVC
TOU PILOT COS>30KW 4 178 0 0.0445
60 OREGON - 01GNCEL23F-OR SMALLCELL FLAT RATE 1,304 1 0.0000
61 OREGON - 01GNSB0023, OR GEN SRV,BPA, < 30 kW 1,692,072 2,755 0.0000
62 OREGON - 01GNSB0028, OR GEN SRV,BPA, > 30 kW 2,093,054 277 0.0000
63 OREGON - 01GNSB023T - OR GEN SRV -TOU - BPA 19,273 36 0.0000
64 OREGON - 01GNSB0723-OR GEN SVC
DIR ACCESS <= 30KW 23,550 40 0.0000
65 OREGON - 01GNSB0728 - OR GEN SVC
DIR ACCESS >30KW 14,461 1 0.0000
66 OREGON - 01GNSEV45T-ELECTVEHICLE DC FAST CHG<1MW 301,232 26 0.0000
67 OREGON - 01GNSV0023, OR GEN SRV, <30 KW 59,943,102 60,929 0.0000
68 OREGON - 01GNSV0028, OR GEN SRV >30 kW 64,444,349 8,950 0.0000
69 OREGON - 01GNSV0029-OR GEN SVC
TOU PILOT > 30 KW 531 0 0.0000
70 OREGON - 01GNSV023F - OR GEN SRV -
FLAT RATE 10,617 1,609,895 791 13,422 0.1516
71 OREGON - 01GNSV023M - OR GEN SRV,MANUAL BILL 91 8,463 2 45,500 0.0930
72 OREGON - 01GNSV023T, OR GEN SRV,TOU Option 151,798 176 0.0000
73 OREGON - 01GNSV0723-OR GEN SVCDIR ACCESS <= 30KW 576 0 0.0000
74 OREGON - 01HABT0023, OR HABITAT
BLENDED SPLY SRV 3,045 152,653 0 0.0501
75 OREGON - 01HABTB023 - OR HABITAT
BLENDED 10 542 0 0.0542
76 OREGON - 01LGSB0030, GEN DEL SRV,
> 200 kW(R)1,259,764 22 0.0000
77 OREGON - 01LGSV0030 - OR LRG GENSRV, > 1000 kW 34,864,181 601 0.0000
78 OREGON - 01LGSV0048-1000KW ANDOVR 23,423,077 92 0.0000
79 OREGON - 01LGSV048M-LRG GEN SRVC1 53,389 3,056,206 1 53,389,000 0.0572
80 OREGON - 01LNX00100-LINE EXT 60% G 7,788 0 0.0000
81 OREGON - 01LNX00102-LINE EXT 80% G 1,099,375 0 0.0000
82 OREGON - 01LNX00103-LINE EXT 80% G 5,371 0 0.0000
83 OREGON - 01LNX00105-CNTRCT $ MIN G 11,959 0 0.0000
84 OREGON - 01LNX00109-REF/NREF ADV+1,581,843 0 0.0000
85 OREGON - 01LNX00110-REF/NREF ADV+11,873 0 0.0000
86 OREGON - 01LNX00311 - LINE EXT 80%
G 221,648 0 0.0000
87 OREGON - 01LNX00312 - OR IRG LINE
EXT 647 0 0.0000
88 OREGON - 01LNX00314 - LINE EXT 60%
GUARANTEE 4,257 0 0.0000
89 OREGON - 01LNX00120 - Line Extension60% Gar 1,064 0 0.0000
90 OREGON - 01LNX00300 - LINE EXT 80%GUARANTEE 413,175 0 0.0000
91 OREGON - 01LNX00310-LINEEXTENSION CONTRACT 1,416 0 0.0000
92 OREGON - 01LPRS047M-PART REQ
SRVC 27,898 3,155,763 5 5,579,600 0.1131
93 OREGON - 01NM23T135-OR NET MTR
TOU GEN SVC<30 KW 1,864 1 0.0000
94 OREGON - 01NMB23135-OR NET MTRGEN SVC <= 30 KW 10,047 31 0.0000
95 OREGON - 01NMB28135-OR NET MTRGEN SVC > 30 KW 33,298 4 0.0000
96 OREGON - 01NMT23135 - OR NET MTR,
GEN, < 30 kW
485,520 500 0.0000
97 OREGON - 01NMT28135 - OR NET MTR,GEN, > 30 kW 2,269,977 280 0.0000
98 OREGON - 01NMT30135 - OR NET MTR,GEN, > 200 kW 2,176,360 38 0.0000
99 OREGON - 01NMT48135-NET METERINGGEN SVC => 1000 532,042 4 0.0000
100 OREGON - 01NMTEV45T-OR NET MTR,
EV DC FAST CHG ST 1,114 1 0.0000
101 OREGON - 01OALT015N-OUTD AR LGT
NR 4,946 525,849 2,652 1,865 0.1063
102 OREGON - 01OALTB15N-OR OUTD ARLGT NR 1,289 187,270 967 1,333 0.1453
103 OREGON - 01PTOU0023, OR GEN SRV,TOU ENG SPLY SRV 2,533 126,844 0 0.0501
104 OREGON - 01PTOUB023, OR GEN SRV,TOU SPLY SRV 256 13,628 0 0.0532
105 OREGON - 01RCFL0054-REC FIELD LGT 1,383 129,960 102 13,559 0.0940
106 OREGON - 01RENW0023, OR RENWUSAGE SPLY SRV 12,640 641,892 0 0.0508
107 OREGON - 01RENWB023 - ORRENEWABLE USAGE 121 6,062 0 0.0501
108 OREGON - 01STDAY023 - OR DAY STDOFR, SCH 23 3,608 244,951 0 0.0679
109 OREGON - 01STDAY028 - OR DAY STDOFF, SCH 28 12,833 874,552 0 0.0681
110 OREGON - 01STDAY030 - OR STD DAY
OFF, SCH 27 3,437 196,371 0 0.0571
111 OREGON - 01VIR23136-OR VOLUME
INCENTIVE <= 30 KW 213,630 131 0.0000
112 OREGON - 01VIR28136-OR VOLUMEINCENTIVE > 30 KW 654,014 84 0.0000
113 OREGON - 01VIR30136-OR VOLUMEINCENTIVE > 200 kW 167,280 3 0.0000
114 OREGON - 01VIR48136-OR VOLUMEINCENTIVE > 1000 KW 115,112 1 0.0000
115 OREGON - 01ZZMERGCR-MERGER
CREDITS (1)0 0.0000
116 OREGON - COMMERCIAL CUSTOMER
BILL CREDITS (20,212)0 0.0000
117 OREGON - CUSTOMER COUNT -REGULAR 0 0.0000
118 OREGON - 01LGSB0048 - LG GEN SVC >1000KW (R)698,062 1 0.0000
119 OREGON - 01LGSV028M - OR LGSV,<1000 kW, Manual 485 43,780 1 485,000 0.0903
120 OREGON - 01GNSV0728 - OR GEN SVC
DIR ACCESS >30KW 304,136 16 0.0000
121 OREGON - 01GNSV0730 -OR GEN SVC
DIR ACCESS >200KW 2,132,170 19 0.0000
122 OREGON - 01GNSV0748 LG GEN SVC
DIR ACCESS 1000KW+1,839,193 3 0.0000
123 OREGON - 01GNSV0848-LG GEN SVC >1000 DA DEL 1,558,832 1 0.0000
124 OREGON - OR GAIN ON SALE OF ASSET 16,155 0 0.0000
125 OREGON - INCOME TAX DEFERRAL
ADJUSTMENTS 2,291,748 0 0.0000
126 OREGON - REVENUE_ACCOUNTING
ADJUSTMENTS 3,205,650 0 0.0000
127 OREGON - SOLAR FEED-IN REVENUE 2,055,942 0 0.0000
128 OREGON - OTHER CUSTOMER RETAILREVENUE 33,058 0 0.0000
129 OREGON - COMMUNITY SOLAR
REVENUE
173,976 0 0.0000
130 OREGON - DSM REVENUE-COMMERCIAL 13,138,704 0 0.0000
131 OREGON - BLUE SKY REVENUE-COMMERCIAL 675,798 102 0.0000
132 UTAH - 08ABL-NRES - APPLICANT BUILTLINE 1,303 0 0.0000
133 UTAH - 08ABTCLXGN-LINE EXT 80%
CONTRACT MIN 8,215 0 0.0000
134 UTAH - 08BLSKY01N-BLUESKY ENERGY (1)0 0.0000
135 UTAH - 08CFR00051-MTH FAC SRVCHG 27,540 0 0.0000
136 UTAH - 08CFR00052-ANN FAC SVCCHG 2 0 0.0000
137 UTAH - 08CGA23137-UT NET MTR SMALLGEN SVC 6 788 1 6,000 0.1314
138 UTAH - 08CGM06136-UT NET METERINGGENERAL SVC 3,986 402,149 8 498,250 0.1009
139 UTAH - 08CGM23136-UTAH NET METERSM GEN SVC 758 77,323 44 17,227 0.1020
140 UTAH - 08CGM6A136-UTAH GEN SVC
TRANS GEN TOU 2,436 235,435 14 174,000 0.0966
141 UTAH - 08CGM6A137-UT GEN SVC
TRANS TOU MAN 137 25 1,686 0 0.0674
142 UTAH - 08CGN08136-UT NET MTR GEN
SVC > 1000 KW 6,913 511,650 1 6,913,000 0.0740
143 UTAH - 08CGN06136-UT GEN SVCTRANSITION GEN 39,451 3,531,750 83 475,313 0.0895
144 UTAH - 08CGN06137-UT GEN SVC CUSTGEN 137 1,307 133,394 7 186,714 0.1021
145 UTAH - 08CGN23136-UTAH NET METERSMALL GEN SVC 2,834 276,837 139 20,388 0.0977
146 UTAH - 08CGN23137-UT NET MTR SMALL
GEN SVC 323 29,870 11 29,364 0.0925
147 UTAH - 08CGN6A136-UT GEN SVC TRAN
- TOU ENERGY 608 45,776 0 0.0753
148 UTAH - 08COOLKPRN - A/C DIRECTLOAD CONTROL (5)0 0.0000
149 UTAH - 08GNSV0006-GEN SRVC-DISTR 5,113,558 413,024,190 11,338 451,011 0.0808
150 UTAH - 08GNSV0009-GEN SRVC-HI VO 871,050 47,915,087 44 19,796,591 0.0550
151 UTAH - 08GNSV0023-GEN SRVC-DISTR 1,285,387 122,283,863 78,335 16,409 0.0951
152 UTAH - 08GNSV006A-GEN SRVC-ENERG 248,750 28,800,529 1,968 126,397 0.1158
153 UTAH - 08GNSV006B-GEN SRVC-DEM&164 15,271 0 0.0931
154 UTAH - 08GNSV006M-MNL DIST VOLTG 1 0.0000
155 UTAH - 08GNSV009A-GEN SRVC HI VO 24,876 1,210,657 2 12,438,000 0.0487
156 UTAH - 08GNSV009M-MANL HIGH VOLT 221,221 12,142,761 1 221,221,000 0.0549
157 UTAH - 08GNSV023F-GEN SRVC FIXED 1,309 179,779 129 10,147 0.1373
158 UTAH - 08GNSV06AM-MNL ENERGY TOD 547 41,965 1 547,000 0.0767
159 UTAH - 08GNSV06MN-GNSV DIST VOLT 38,692 2,967,663 673 57,492 0.0767
160 UTAH - 08GNSVDWY6-UT GEN SVC WWYO DEDUCT MTR 45 5,493 0 0.1221
161 UTAH - 08LNX00002-MTHLY 80% GUAR 1,282,761 0 0.0000
162 UTAH - 08LNX00004-ANNUAL 80%GUAR 238,339 0 0.0000
163 UTAH - 08LNX00006-FIXD MTHLY MIN 2,882 0 0.0000
164 UTAH - 08LNX00014-80% MIN MNTHLY 2,193,474 0 0.0000
165 UTAH - 08LNX00017-ADV/REF&80%ANN 327,482 0 0.0000
166 UTAH - 08LNX00158-ANNUALCOST MTH 28,988 0 0.0000
167 227,406 0 0.0000
UTAH - 08LNX00300 - LINE EXT 80%
PLUS MONTHLY
168 UTAH - 08LNX00310 - IRR, 80% ANNUALMIN + 80% ?62,551 0 0.0000
169 UTAH - 08LNX00312 UT IRG LINE EXT 5,887 0 0.0000
170 UTAH - 08NMT06135-UT NET METERING
GEN SVC 116,609 9,852,171 267 436,738 0.0845
171 UTAH - 08NMT08135 - NET METERING
GEN SVC 53,090 3,918,059 11 4,826,364 0.0738
172 UTAH - 08NMT23135 - UT NET MTR, GEN,< 25 KW 9,790 1,003,857 817 11,983 0.1025
173 UTAH - 08NMT6A135-NET METERINGGEN SVC TOU 10,247 1,049,852 88 116,443 0.1025
174 UTAH - 08NMT8135M - NET METERINGGEN SVC MANUAL 6,404 639,683 1 6,404,000 0.0999
175 UTAH - 08OALT007N-SECURITY AR LG 6,902 871,975 3,721 1,855 0.1263
176 UTAH - 08POLE0075-POLES W/LIGHT 5 1 0.0000
177 UTAH - 08PRSV031M-BKUP MNT&SUPPL 201,791 11,423,925 4 50,447,750 0.0566
178 UTAH - 08PTLD000N-POST TOP LIGHT 6 455 2 3,000 0.0758
179 UTAH - 08REFP034M-RENEWABLE QUALCUST > 5000 KW 205,448 8,455,156 1 205,448,000 0.0412
180 UTAH - 08REFS032M-UT RENEWABLEFAC & SUPP PWR 191,742 13,476,753 3 63,914,000 0.0703
181 UTAH - 08SSLR0006-GENERAL SVCSUBSCR SOLAR 5,621 536,127 13 432,385 0.0954
182 UTAH - 08SSLR0023-SMALL GEN SVC
SUBSCR SOLAR 4,283 372,971 0 0.0871
183 UTAH - 08SSLR006A-GEN SVC TOU
SUBSCR SOLAR 13,559 278,868 3 4,519,667 0.0206
184 UTAH - 08SSLR06AM-GEN SVC TOUSOLAR SUBSCR MAN 1 4,082,975 337 3 4,082.9751
185 UTAH - 08TCVLNAGN-UTAH LNXANNUAL GAR NON RES 1,357 0 0.0000
186 UTAH - 08TCVLNXGN-TCV LNX - 80%GAR - NON RES 201,201 0 0.0000
187 UTAH - 08TCVLXACN-GAR ADDED
CAPACITY NON RES 16,647 0 0.0000
188 UTAH - 08TOSS015F-TRAFFIC SIG NM 171 14,830 20 8,550 0.0867
189 UTAH - COMMERCIAL CUSTOMER BILLCREDITS (13,575)0 0.0000
190 UTAH - 08TOSS0015-TRAF & OTHER S 3,184 320,869 1,107 2,876 0.1008
191 UTAH - 08MONL0015-MTR OUTDONIGHT 14,085 709,750 589 23,913 0.0504
192 UTAH - INCOME TAX DEFERRALADJUSTMENTS 0 0.0000
193 UTAH - REVENUE_ACCOUNTINGADJUSTMENTS (346,930)0 0.0000
194 UTAH - REVENUE ADJUSTMENT -DEFERRED NPC 11,987,862 0 0.0000
195 UTAH - SOLAR FEED-IN REVENUE 1,446,944 0 0.0000
196 UTAH - 08LNX00311 - LINE EXT 80%GUARANTEE 295,762 0 0.0000
197 UTAH - 08GNSV0008 - UT GEN SVC TOU> 1000KW 733,667 51,656,345 104 7,054,490 0.0704
198 UTAH - 08GNSV008M - UT GEN SVC TOU> 1000KW 6,864 439,877 2 3,432,000 0.0641
199 UTAH - DSM REVENUE-COMMERCIAL 8,885,005 0 0.0000
200 UTAH - BLUE SKY REVENUE-COMMERCIAL 874,490 0 0.0000
201 WASHINGTON - 02GN24EV45-WAELECTRIC VEHICLE FAST CHG 48 8,609 3 16,000 0.1794
202 27,922 2,769,933 1,507 18,528 0.0992
WASHINGTON - 02GNSB0024-WA GEN
SRVC DO
203 WASHINGTON - 02GNSB024F-GEN SRVCDOM/F 1 209 1 1,000 0.2090
204 WASHINGTON - 02GNSB24FP-WA GENSVC SEASONAL 196 73,750 66 2,970 0.3763
205 WASHINGTON - 02GNSV0024-WA GENSRVC 476,151 44,723,939 14,837 32,092 0.0939
206 WASHINGTON - 02GNSV024F-WA GEN
SRVC-FL 1,220 169,929 108 11,296 0.1393
207 WASHINGTON - 02LGSB0036-LRG GEN
SVC IRG 43,342 3,543,395 78 555,667 0.0818
208 WASHINGTON - 02LGSV0036-WA LRGGEN SRV 764,417 60,070,972 849 900,373 0.0786
209 WASHINGTON - 02LGSV048T-LRG GENSRVC 1 170,189 12,777,192 36 4,727,472 0.0751
210 WASHINGTON - 02LNX00102-LINE EXT80% G 94,188 0 0.0000
211 WASHINGTON - 02LNX00103-LINE EXT
80% G 6,553 0 0.0000
212 WASHINGTON - 02LNX00105-CNTRCT $
MIN G 2,573 0 0.0000
213 WASHINGTON - 02LNX00109-REF/NREFADV +256,394 0 0.0000
214 WASHINGTON - 02LNX00110-REF/NREFADV +34,263 0 0.0000
215 WASHINGTON - 02LNX00112-YRINCURRED CH 669 0 0.0000
216 WASHINGTON - 02LNX00300-LINE EXT80% G 49,199 0 0.0000
217 WASHINGTON - 02LNX00310 - IRG, 80%
ANNUAL MIN + 80%1,189 0 0.0000
218 WASHINGTON - 02LNX00311 - LINE EXT
80% GUARANTEE 45,822 0 0.0000
219 WASHINGTON - 02LNX00312 - WA IRGLINE EXT 6,386 0 0.0000
220 WASHINGTON - 02NMB24135-WA NETMETERING 129 17,276 24 5,375 0.1339
221 WASHINGTON - 02OALT015N-WA OUTDAR LGT 1,365 108,873 747 1,827 0.0798
222 WASHINGTON - 02OALTB15N-WA OUTD
AR LGT NR 482 51,730 453 1,064 0.1073
223 WASHINGTON - 02RCFL0054-WA REC
FIELD L 261 15,336 26 10,038 0.0588
224 WASHINGTON - 02NMT24135, Netmetering, WA 5,625 549,994 132 42,614 0.0978
225 WASHINGTON - 02NMT36135-WA NETMETER LRG SVC < 1000KW 12,866 1,081,191 17 756,824 0.0840
226 WASHINGTON - 02NMT48135-WA LGSVC NET METER=>1000 KW 10,324 740,910 2 5,162,000 0.0718
227 WASHINGTON - INCOME TAX DEFERRALADJUSTMENTS 830,189 0 0.0000
228 WASHINGTON - REVENUE ADJUSTMENT
- DEFERRED NPC 39,925 0 0.0000
229
WASHINGTON -
REVENUE_ACCOUNTING
ADJUSTMENTS
(428,306)0 0.0000
230 WASHINGTON - DSM REVENUE-
COMMERCIAL 3,915,890 0 0.0000
231 WASHINGTON - BLUE SKY REVENUE-COMMERCIAL 41,883 1 0.0000
232 WASHINGTON - ALT REVENUEPROGRAM ADJUSTMENTS 70,029 0 0.0000
233 WYOMING - 05CHCK000N-WY NRESCHECK 1 0.0000
234 WYOMING - 05GNSV0025-WY GEN SRVC- A 229,372 22,041,178 18,377 12,481 0.0961
235 WYOMING - 05GNSV0028-GEN SVC > 15
KW - A 822,351 67,663,513 3,058 268,918 0.0823
236 WYOMING - 05GNSV025F-GEN SRVC-FL
RA - A 989 155,625 171 5,784 0.1574
237 WYOMING - 05LGSV0046-WY LRG GENSRV 179,309 12,217,351 17 10,547,588 0.0681
238 WYOMING - 05LGSV048T-LRG GENSRVTIM 13,160 934,140 1 13,160,000 0.0710
239 WYOMING - 05LNX00100-LINE EXT 60%G 18,387 0 0.0000
240 WYOMING - 05LNX00102-LINE EXT 80%
G - A 936,585 0 0.0000
241 WYOMING - 05LNX00103-LINE EXT 80%
G - A 2,041 0 0.0000
242 WYOMING - 05LNX00105-CNTRCT $ MING 5,616 0 0.0000
243 WYOMING - 05LNX00109-REF/NREF ADV+ A 290,064 0 0.0000
244 WYOMING - 05LNX00110-REF/NREF ADV+ A 3,231 0 0.0000
245 WYOMING - 05LNX00114-TEMP SVC
12MO>233 0 0.0000
246 WYOMING - 05NMT25135 - WY NET MTR,
GEN, < 25 KW - A 1,125 92,183 41 27,439 0.0819
247 WYOMING - 05NMT28135-NET MTR
SMALL GEN SVC > 15 KW - A 9,119 810,128 26 350,731 0.0888
248 WYOMING - 05OALT015N-OUTD AR LGTSR - A 2,461 291,564 1,525 1,614 0.1185
249 WYOMING - 05RCFL0054-WY REC FIELDL - A 878 51,340 58 15,138 0.0585
250 WYOMING - 05LNX00300 - LINE EXT 80%GUARANTEE 149,671 0 0.0000
251 WYOMING - 05LNX00310-LINE
EXTENSION CONTRACT 9,295 0 0.0000
252 WYOMING - 05LNX00311 - LINE EXT 80%
GUARANTEE - A 41,067 0 0.0000
253 WYOMING - INCOME TAX DEFERRALADJUSTMENTS 172,223 0 0.0000
254 WYOMING - REVENUE ADJUSTMENT -DEFERRED NPC (154,637)0 0.0000
255 WYOMING - REVENUE_ACCOUNTINGADJUSTMENTS (569,725)0 0.0000
256 WYOMING - DSM REVENUE-SMALL
COMMERCIAL - A 1,521,880 0 0.0000
257 WYOMING - DSM REVENUE-LARGE
COMMERCIAL 87,094 0 0.0000
258 WYOMING - BLUE SKY REVENUE-
COMMERCIAL - A 23,552 1 0.0000
259 WYOMING - 05GNSV0025-WY GEN SRVC- B 30,841 2,977,789 2,516 12,258 0.0966
260 WYOMING - 05GNSV0028-GEN SVC > 15KW - B 89,751 7,333,724 364 246,569 0.0817
261 WYOMING - 05GNSV025F-GEN SRVC-FLRA 199 24,595 33 6,030 0.1236
262 WYOMING - 05LNX00102-LINE EXT 80%
G - B 118,089 0 0.0000
263 WYOMING - 05LNX00103-LINE EXT 80%
G - B 556 0 0.0000
264 WYOMING - 05LNX00109-REF/NREF ADV+ B 120,097 0 0.0000
265 WYOMING - 05LNX00110-REF/NREF ADV+ B 278 0 0.0000
266 WYOMING - 05NMT25135 - WY NET MTR,
GEN, < 25 KW - B
94 8,210 6 15,667 0.0873
267 WYOMING - 05NMT28135-NET MTRSMALL GEN SVC > 15 KW - B 394 32,777 2 197,000 0.0832
268 WYOMING - 05OALT015N-OUTD AR LGTSR - B 130 13,564 69 1,884 0.1043
269 WYOMING - 05RCFL0054-WY REC FIELDL - B 109 5,011 6 18,167 0.0460
270 WYOMING - 09OALT207N-SECURITY AR
LG 135 27,453 70 1,929 0.2034
271 WYOMING - 09MONL0213-WY MTR
OUTDOOR NIGHT LIGHT 135 7,106 6 22,500 0.0526
272 WYOMING - 05LNX00311 - LINE EXT 80%GUARANTEE 2,380 0 0.0000
273 WYOMING - DSM REVENUE-SMALLCOMMERCIAL - B 194,205 0 0.0000
274 WYOMING - BLUE SKY REVENUE-COMMERCIAL - B 731 0 0.0000
275 LESS MULTIPLE BILLINGS (22,224)
41 TOTAL Billed Small or Commercial 18,812,934 1,593,862,298 221,531 85,040 0.0846
42 TOTAL Unbilled Rev. Small or Commercial(See Instr. 6)26,140 (304,000)0.0000
43 TOTAL Small or Commercial 18,839,074 1,593,558,298 221,531 85,040 0.0846
FERC FORM NO. 1 (ED. 12-95)Page 304
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 rateschedule 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 waterheating 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 ofCustomers(d)
KWh of Sales PerCustomer(e)
Revenue Per KWhSold(f)
1 CALIFORNIA - 06GNSV0025-CA GENSRVC 516 91,398 82 6,293 0.1771
2 CALIFORNIA - 06GNSV0A32-GEN SRVC-20 KW 2,227 348,672 22 96,826 0.1566
3 CALIFORNIA - 06LGSV048T-LRG GEN
SERV 53,337 5,179,681 10 5,333,700 0.0971
4 CALIFORNIA - 06LGSV0A36-LRG GEN
SRVC-O 5,099 704,116 11 463,545 0.1381
5 CALIFORNIA - INCOME TAX DEFERRAL
ADJUSTMENTS 184,249 0.0000
6 CALIFORNIA - REVENUE_ACCOUNTINGADJUSTMENTS (79,632)0.0000
7 CALIFORNIA - DSM REVENUE-INDUSTRIAL 90,447 0.0000
8 CALIFORNIA - BLUE SKY REVENUE-INDUSTRIAL 368 0.0000
9 CALIFORNIA - OTHER CUSTOMER
RETAIL REVENUE 12,794 0.0000
10 IDAHO - 07CFR00001-MTH FACILITY S 2,216 0.0000
11 IDAHO - 07CISH0019-COMM & IND SPA 15 1,488 1 15,000 0.0992
12 IDAHO - 07GNSV0006-GEN SRVC-LRG P 86,477 6,145,044 102 847,814 0.0711
13 IDAHO - 07GNSV0009-GEN SRVC-HI VO 69,674 4,649,067 14 4,976,714 0.0667
14 IDAHO - 07GNSV0023-GEN SRVC-SML P 15,358 1,455,544 308 49,864 0.0948
15 IDAHO - 07GNSV006A-GEN SRVC-LRG P 2,224 197,975 21 105,905 0.0890
16 IDAHO - 07GNSV023A-GEN SRVC-SML P 1,912 198,627 134 14,269 0.1039
17 IDAHO - 07GNSV023S-IDAHO TRAFFIC
SIGNALS 5 601 1 5,000 0.1202
18 IDAHO - 07LNX00108-ANN COST MTHLY 1,996 0.0000
19 IDAHO - 07LNX00311 - LINE EXT 80%GUARANTEE 21 0.0000
20 IDAHO - 07NMT23135 - ID NET MTR -SMALL GEN SVC 25 2,432 1 25,000 0.0973
21 IDAHO - 07OALT007N-SECURITY AR LG 12 4,859 16 750 0.4049
22 IDAHO - 07OALT07AN-SECURITY AR LG 1 254 1 1,000 0.2543
23 IDAHO - 07SPCL0001 1,298,200 83,812,280 1 1,298,200,000 0.0646
24 IDAHO - 07SPCL0002 112,795 6,891,360 1 112,795,000 0.0611
25 IDAHO - INCOME TAX DEFERRALADJUSTMENTS 110,631 0.0000
26 IDAHO - REVENUE_ACCOUNTINGADJUSTMENTS (189,273)0.0000
27 IDAHO - DSM REVENUE-INDUSTRIAL 207,378 0.0000
28 IDAHO - BLUE SKY REVENUE-
INDUSTRIAL 14 0.0000
29 17,881 889,141 0.0497
OREGON - 01COST0023, OR GEN SRV,
COST BASED
30 OREGON - 01COST0048 - 01LGSV0048 1,225,780 53,179,176 0.0434
31 OREGON - 01COST023F - OR GEN SRV -COST-BASED 1 54 0.0538
32 OREGON - 01COSTB023 - OR GEN SRV,
CST-BSD SPLY 135 6,472 0.0479
33 OREGON - 01COSTL030 - OR LRG GEN
SRV, CST >200 kW 180,093 7,153,430 0.0397
34 OREGON - 01COSTS028, OR GEN SERV,COST > 30kW 78,162 3,920,660 0.0502
35 OREGON - 01GNSB0023, OR GEN SRV,BPA, < 30 kW 9,615 12 0.0000
36 OREGON - 01GNSB0028, OR GEN SRV,BPA, > 30 kW 7,188 1 0.0000
37 OREGON - 01GNSV0023, OR GEN SRV, <
30 KW 1,077,057 951 0.0000
38 OREGON - 01GNSV0028, OR GEN SRV >
30 kW 3,326,794 388 0.0000
39 OREGON - 01GNSV023F - OR GEN SRV -FLAT RATE 2 674 2 1,000 0.3372
40 OREGON - 01GNSV023M - OR GEN SRV,MANUAL BILL 307 1 0.0000
41 OREGON - 01GNSV023T, OR GEN SRV,TOU Option 2,322 3 0.0000
42 OREGON - 01GNSV0730 -OR GEN SVCDIR ACCESS >200KW 13,517 0.0000
43 OREGON - 01GNSV0748 LG GEN SVC
DIR ACCESS 1000KW+1,027,292 3 0.0000
44 OREGON - 01LGSV0030 - OR LRG GEN
SRV, > 1000 kW 8,395,636 126 0.0000
45 OREGON - 01LGSV0048-1000KW ANDOVR 24,106,853 76 0.0000
46 OREGON - 01LGSV048M-LRG GEN SRVC1 54,310 3,473,693 3 18,103,333 0.0640
47 OREGON - 01LNX00102-LINE EXT 80% G 95,068 0.0000
48 OREGON - 01LNX00109-REF/NREF ADV
+ A 301 0.0000
49 OREGON - 01LNX00300 - LINE EXT 80%GUARANTEE 16,170 0.0000
50 OREGON - 01LPRS047M-PART REQSRVC 2,184 878,461 1 2,184,000 0.4022
51 OREGON - 01NMT23135 - OR NET MTR,GEN, < 30 kW 3,160 5 0.0000
52 OREGON - 01NMT28135 - OR NET MTR,
GEN, > 30 kW 72,895 7 0.0000
53 OREGON - 01NMT30135 - OR NET MTR,
GEN, > 200 kW 76,079 2 0.0000
54 OREGON - 01OALT015N-OUTD AR LGT
NR 240 22,946 111 2,162 0.0956
55 OREGON - 01OALTB15N-OR OUTD ARLGT NR 3 371 3 1,000 0.1235
56 OREGON - 01PTOU0023, OR GEN SRV,TOU ENG SPLY SRV 33 1,739 0.0527
57 OREGON - 01RENW0023, OR RENWUSAGE SPLY SRV 95 4,784 0.0504
58 OREGON - CUSTOMER COUNT -
REGULAR 0.0000
59 OREGON - 01VIR23136-OR VOLUME
INCENTIVE <= 30 KW 1,009 1 0.0000
60 OREGON - 01VIR28136-OR VOLUMEINCENTIVE > 30 KW 15,316 2 0.0000
61 OREGON - 01VIR30136-OR VOLUMEINCENTIVE > 200 kW 88,087 1 0.0000
62 OREGON - INDUSTRIAL CUSTOMER BILLCREDITS (3,613)0.0000
63 OREGON - INCOME TAX DEFERRALADJUSTMENTS 1,211,840 0.0000
64 OREGON - OR GAIN ON SALE OF ASSET 4,697 0.0000
65 OREGON - REVENUE_ACCOUNTINGADJUSTMENTS 236,642 0.0000
66 OREGON - SOLAR FEED-IN REVENUE 536,962 0.0000
67 OREGON - COMMUNITY SOLAR
REVENUE 48,119 0.0000
68 OREGON - DSM REVENUE-INDUSTRIAL 947,059 0.0000
69 OREGON - BLUE SKY REVENUE-INDUSTRIAL 348,037 4 0.0000
70 UTAH - 08CFR00051-MTH FAC SRVCHG 14,901 0.0000
71 UTAH - 08CGM23136-UTAH NET METER
SM GEN SVC 11 1,531 1 11,000 0.1392
72 UTAH - 08CGN06136-UT GEN SVCTRANSITION GEN 1,557 120,155 1 1,557,000 0.0772
73 UTAH - 08CGN06137-UT GEN SVC CUSTGEN 137 16 3,284 1 16,000 0.2053
74 UTAH - 08CGN23136-UTAH NET METERSMALL GEN SVC 5 591 0.1182
75 UTAH - 08EFOP021M-ELEC FURNACE O 58 10,563 0.1821
76 UTAH - 08GNSV0006-GEN SRVC-DISTR 600,260 49,628,454 905 663,271 0.0827
77 UTAH - 08GNSV0009-GEN SRVC-HI VO 2,726,847 149,880,406 101 26,998,485 0.0550
78 UTAH - 08GNSV0023-GEN SRVC-DISTR 52,654 4,991,060 3,088 17,051 0.0948
79 UTAH - 08GNSV006A-GEN SRVC-ENERG 50,954 5,998,958 229 222,507 0.1177
80 UTAH - 08GNSV009A-GEN SRVC HI VO 16,669 1,392,788 6 2,778,167 0.0836
81 UTAH - 08GNSV009M-MANL HIGH VOLT 698,517 36,266,867 11 63,501,545 0.0519
82 UTAH - 08GNSV023F-GEN SRVC FIXED 3 2,336 1 3,000 0.7788
83 UTAH - 08GNSV06MN-GNSV DIST VOLT 731 69,698 19 38,474 0.0953
84 UTAH - 08LNX00002-MTHLY 80% GUAR 703,517 0.0000
85 UTAH - 08LNX00014-80% MIN MNTHLY 17,176 0.0000
86 UTAH - 08LNX00017-ADV/REF&80%ANN 639 0.0000
87 UTAH - 08LNX00300 - LINE EXT 80%PLUS MONTHLY 92,877 0.0000
88 UTAH - 08LNX00311 - LINE EXT 80%GUARANTEE 252 0.0000
89 UTAH - 08OALT007N-SECURITY AR LG 842 93,349 373 2,257 0.1109
90 UTAH - 08TOSS0015-TRAF & OTHER S 47 4,444 12 3,917 0.0945
91 UTAH - INDUSTRIAL CUSTOMER BILLCREDITS (28,718)0.0000
92 UTAH - 08MONL0015-MTR OUTDONIGHT 18 1,521 5 3,000 0.0845
93 UTAH - 08NMT06135-UT NET METERING
GEN SVC 2,348 213,289 6 391,333 0.0908
94 UTAH - 08NMT23135 - UT NET MTR, GEN,< 25 KW 98 13,097 17 5,765 0.1336
95 UTAH - 08NMT6A135-NET METERINGGEN SVC TOU 5,376 648,730 13 413,538 0.1207
96 UTAH - 08PRSV031M-BKUP MNT&SUPPL 63,083 4,476,267 3 21,027,667 0.0710
97 UTAH - 08SPCL0001 682,086 34,558,076 1 682,086,000 0.0507
98 UTAH - 08SPCL0002 615,848 29,040,276 1 615,848,000 0.0472
99 UTAH - 08SPCL0003 1,286,271 77,570,788 1 1,286,271,000 0.0603
100 UTAH - 08SSLR0006-GENERAL SVCSUBSCR SOLAR 1,417 111,189 3 472,333 0.0785
101 222 17,527 24 9,250 0.0790
UTAH - 08SSLR0023-SMALL GEN SVC
SUBSCR SOLAR
102 UTAH - 08SSLR006A-GEN SVC TOUSUBSCR SOLAR 1,378 70,647 2 689,000 0.0513
103 UTAH - 08SSLR06AM-GEN SVC TOUSOLAR SUBSCR MAN 1,113,391 29 0.0000
104 UTAH - 08TCVLNXGN-TCV LNX - 80%GAR - NON RES 20,445 0.0000
105 UTAH - INCOME TAX DEFERRAL
ADJUSTMENTS 0.0000
106 UTAH - REVENUE_ACCOUNTING
ADJUSTMENTS (463,116)0.0000
107 UTAH - REVENUE ADJUSTMENT -DEFERRED NPC 10,959,084 0.0000
108 UTAH - 08GNSV06AM-MNL ENERGY TOD 427 68,100 3 142,333 0.1595
109 UTAH - 08GNSV0008 - UT GEN SVC TOU
> 1000KW 981,305 70,222,193 93 10,551,667 0.0716
110 UTAH - 08GNSV008M - UT GEN SVC TOU
> 1000KW 27,191 2,074,876 4 6,797,750 0.0763
111 UTAH - SOLAR FEED-IN REVENUE 1,322,537 0.0000
112 UTAH - DSM REVENUE-INDUSTRIAL 8,121,080 0.0000
113 UTAH - BLUE SKY REVENUE-
INDUSTRIAL 178,871 7 0.0000
114 WASHINGTON - 02GNSB0024-WA GEN
SRVC DO 922 98,531 41 22,488 0.1069
115 WASHINGTON - 02GNSB24FP-WA GENSVC SEASONAL 4 1,748 1 4,000 0.4370
116 WASHINGTON - 02GNSV0024-WA GENSRVC 13,740 1,317,804 323 42,539 0.0959
117 WASHINGTON - 02GNSV024F-WA GENSRVC-FL 33 8,750 4 8,250 0.2651
118 WASHINGTON - 02LGSV0036-WA LRG
GEN SRV 86,368 7,189,802 88 981,455 0.0832
119 WASHINGTON - 02LGSV048M-WA LRG
GEN SRV 528,041 31,714,342 1 528,041,000 0.0601
120 WASHINGTON - 02LGSV048T-LRG GENSRVC 1 200,810 14,540,354 29 6,924,483 0.0724
121 WASHINGTON - 02LNX00103-LINE EXT80% G (73,038)0.0000
122 WASHINGTON - 02LNX00300-LINE EXT80% G 26,655 0.0000
123 WASHINGTON - 02NMT24135, Net
metering, WA 55 5,412 2 27,500 0.0984
124 WASHINGTON - 02NMT36135-WA NET
METER LRG SVC < 1000KW 95 8,452 0.0890
125 WASHINGTON - 02OALT015N-WA OUTDAR LGT 95 6,337 36 2,639 0.0667
126 WASHINGTON - 02OALTB15N-WA OUTDAR LGT NR 27 2,574 14 1,929 0.0953
127 WASHINGTON - 02PRSV47TM-LRG PARTREQMT 1,913 346,866 1 1,913,000 0.1813
128 WASHINGTON - INDUSTRIALCUSTOMER BILL CREDITS (3,860)0.0000
129 WASHINGTON - 02LGSB0036-LRG GEN
SVC IRG 918 135,910 8 114,750 0.1481
130 WASHINGTON - INCOME TAX DEFERRAL
ADJUSTMENTS 255,135 0.0000
131 WASHINGTON - REVENUE ADJUSTMENT- DEFERRED NPC 21,296 0.0000
132 WASHINGTON -REVENUE_ACCOUNTINGADJUSTMENTS 924,971 0.0000
133 WASHINGTON - BLUE SKY REVENUE-INDUSTRIAL 29 0.0000
134 WASHINGTON - DSM REVENUE-INDUSTRIAL 1,778,211 0.0000
135 WASHINGTON - ALT REVENUEPROGRAM ADJUSTMENTS (1,573,661)0.0000
136 WYOMING - 05GNSV0025-WY GEN SRVC
- A 18,390 1,673,159 1,100 16,718 0.0910
137 WYOMING - 05GNSV0028-GEN SVC > 15
KW - A 223,890 15,884,149 412 543,422 0.0709
138 WYOMING - 05GNSV025F-GEN SRVC-FLRA 26 4,186 8 3,250 0.1610
139 WYOMING - 05LGSV0046-WY LRG GENSRV - A 1,602,164 102,096,098 59 27,155,322 0.0637
140 WYOMING - 05LGSV046M-WY LRG GENSRV 10,308 733,448 1 10,308,000 0.0712
141 WYOMING - 05LGSV048M-TOU>1000KW
MAN - A 272,160 14,705,074 1 272,160,000 0.0540
142 WYOMING - 05LGSV048T-LRG GENSRV
TIM - A 1,829,096 98,412,206 11 166,281,455 0.0538
143 WYOMING - 05LNX00100-LINE EXT 60%G 70,077 0.0000
144 WYOMING - 05LNX00102-LINE EXT 80%G - A (3,086,041)0.0000
145 WYOMING - 05LNX00105-CNTRCT $ MING 32,100 0.0000
146 WYOMING - 05LNX00109-REF/NREF ADV+ A 112,572 0.0000
147 WYOMING - 05LNX00110-REF/NREF ADV
+209 0.0000
148 WYOMING - 05LNX00300 - LINE EXT 80%
GUARANTEE 126,726 0.0000
149 WYOMING - 05LNX00311 - LINE EXT 80%GUARANTEE 17,772 0.0000
150 WYOMING - 05OALT015N-OUTD AR LGTSR - A 67 6,831 38 1,763 0.1020
151 WYOMING - 05PRSV033M-PART SERVREQ - A 1,131,807 74,692,764 10 113,180,700 0.0660
152 WYOMING - INCOME TAX DEFERRAL
ADJUSTMENTS 794,986 0.0000
153 WYOMING - REVENUE ADJUSTMENT -
DEFERRED NPC (709,125)0.0000
154 WYOMING - REVENUE_ACCOUNTINGADJUSTMENTS 415,646 0.0000
155 WYOMING - DSM REVENUE-SMALLINDUSTRIAL-A 308,637 0.0000
156 WYOMING - DSM REVENUE-LARGEINDUSTRIAL-A 1,774,254 0.0000
157 WYOMING - BLUE SKY REVENUE-
INDUSTRIAL-A 285 0.0000
158 WYOMING - 05GNSV0025-WY GEN SRVC
- B 3,840 362,617 282 13,617 0.0944
159 WYOMING - 05GNSV0028-GEN SVC > 15
KW - B 58,197 4,079,474 65 895,338 0.0701
160 WYOMING - 05GNSV028M-GEN SVC > 15KW MANUAL BILL 3,344 199,659 3 1,114,667 0.0597
161 WYOMING - 05LGSV0046-WY LRG GENSRV - B 10,193 695,307 2 5,096,500 0.0682
162 WYOMING - 05LGSV048M-TOU>1000KWMAN - B 110,383 6,772,739 2 55,191,500 0.0614
163 WYOMING - 05LGSV048T-LRG GENSRV
TIM - B 776,278 47,739,248 14 55,448,429 0.0615
164 WYOMING - 05LNX00102-LINE EXT 80%
G - B 2,403,750 0.0000
165 WYOMING - 05LNX00109-REF/NREF ADV+ B 24,789 0.0000
166 WYOMING - 05NMT25135 - WY NET MTR,
GEN, < 25 KW
34 2,843 1 34,000 0.0836
167 WYOMING - 05OALT015N-OUTD AR LGTSR - B 3 257 2 1,500 0.0856
168 WYOMING - 05PRSV033M-PART SERVREQ - B 1,454 331,085 1 1,454,000 0.2277
169 WYOMING - 09OALT207N-SECURITY ARLG 3 550 2 1,500 0.1834
170 WYOMING - DSM REVENUE-SMALL
INDUSTRIAL-B 86,485 0.0000
171 WYOMING - DSM REVENUE-LARGE
INDUSTRIAL-B 524,337 0.0000
172 WYOMING - BLUE SKY REVENUE-INDUSTRIAL-B 86 0.0000
173 LESS MULTIPLE BILLINGS (813)
174 CALIFORNIA - 06APSV0020-AG PMP
SRVC 9,229 1,283,936 736 12,539 0.1391
175 CALIFORNIA - 06APSV0115-CA AGRI
PUMP TOU PILOT,GHG CR 15 4,861 3 5,000 0.3241
176 CALIFORNIA - 06APSV020L-AG PMPSRVC-NO GHG CREDIT 63,534 8,173,123 591 107,503 0.1286
177 CALIFORNIA - 06APSV115L-CA AGRIPUMP TOU, NO GHG CR 891 109,798 8 111,375 0.1232
178 CALIFORNIA - 06LGSV048T-LRG GENSERV IRR 7,571 1 0.0000
179 CALIFORNIA - 06LNX00103-LINE EXT80% G 1,026 0.0000
180 CALIFORNIA - 06LNX00110-REF/NREF
ADV +22,219 0.0000
181 CALIFORNIA - 06LNX00310 - IRG, 80%
ANNUAL MIN + 80%483 0.0000
182 CALIFORNIA - 06LNX00312 - CA IRG LINEEXT 15,022 0.0000
183 CALIFORNIA - 06NB20L136-CA IRG NETBILL NO GHG CR 22 2,277 0.1035
184 CALIFORNIA - 06NBL20136-CA IRG NETBILLING 15 1,167 0.0778
185 CALIFORNIA - 06NML20135-AGRI PUMP-
NET MTR NO GHG CR 1,479 326,486 32 46,219 0.2207
186 CALIFORNIA - 06NMT20135-
AGRICULTURAL PUMP-NET METER 93 24,441 18 5,167 0.2628
187 CALIFORNIA - 06USBR0020-KLAM IRGONPRJ 2,490 414,248 282 8,830 0.1664
188 CALIFORNIA - 06USBR0115-CA AGR PMPTOU PLT USBR GHG 7 1,963 5 1,400 0.2804
189 CALIFORNIA - 06USBR020L-KLAM IRGONPRJ-NO CHG CREDIT 29,649 3,955,024 326 90,948 0.1334
190 CALIFORNIA - 06USBR115L-CA AGR PMP
TOU PLT USBR NOGHG 381 51,415 4 95,250 0.1349
191 CALIFORNIA - DSM REVENUE-
IRRIGATION 203,360 0.0000
192 CALIFORNIA - BLUE SKY REVENUE-
IRRIGATION 154 0.0000
193 CALIFORNIA - OTHER CUSTOMERRETAIL REVENUE IRR 3,595 0.0000
194 CALIFORNIA - INCOME TAX DEFERRALADJUSTMENTS IRR 344,202 0.0000
195 CALIFORNIA - REVENUE_ACCOUNTINGADJUSTMENTS IRR (183,133)0.0000
196 IDAHO - 07APSA010L - IRG & Pump Large
Load 358,491 32,072,646 2,227 160,975 0.0895
197 IDAHO - 07APSA010S - IRG & Pump Small
Load 5,918 623,992 321 18,436 0.1054
198 272,998 24,726,258 1,989 137,254 0.0906
IDAHO - 07APSAL10X - IRG & PUMP -
Large load
199 IDAHO - 07APSAS10X - IRG & PUMP -Small load 9,165 986,806 585 15,667 0.1077
200 IDAHO - 07APSV006A-LRG POWEROPTIONAL SVC - IRG 564 43,999 1 564,000 0.0780
201 IDAHO - 07APSV023A-SMALL POWEROPTIONAL SVC-IRG 438 42,515 4 109,500 0.0971
202 IDAHO - 07APSVCNLL-LRG LOAD CANAL 13,646 1,118,873 36 379,056 0.0820
203 IDAHO - 07APSVCNLS-SML LOAD CANAL 41 5,605 11 3,727 0.1367
204 IDAHO - 07GNSV023A-GEN SRVC-SML PIRR 144 13,205 1 144,000 0.0917
205 IDAHO - 07LNX00015-ANNUAL 80%GUAR 60,849 0.0000
206 IDAHO - 07LNX00035-ADV 80%MO GUAR 1,283 0.0000
207 IDAHO - 07LNX00040-ADV+REFCHG+80%90,074 0.0000
208 IDAHO - 07LNX00310 80% ANNUAL
GUARANTEE 2,679 0.0000
209 IDAHO - 07LNX00312 - ID LINE EXT 24,656 0.0000
210 IDAHO - 07NBL10136-ID IRG LRG LOADNET BILLING 15 1,726 0.1151
211 IDAHO - 07NM10X135-ID NET METERING- IRG 19 1,551 1 19,000 0.0816
212 IDAHO - 07APSN010L - ID LG IRR &PUMP 9,310 821,828 37 251,622 0.0883
213 IDAHO - 07APSN010S - IRRIGATION,
SMALL, 3 PH 100 10,180 4 25,000 0.1018
214 IDAHO - 07APSNS10X - IRRIGATION,
SMALL, 3 PHASE 300 34,405 18 16,722 0.1143
215 IDAHO - INCOME TAX DEFERRALADJUSTMENTS IRR 43,483 0.0000
216 IDAHO - REVENUE_ACCOUNTINGADJUSTMENTS IRR (227,290)0.0000
217 IDAHO - DSM REVENUE-IRRIGATION 1,354,779 0.0000
218 IDAHO - BLUE SKY REVENUE-
IRRIGATION 70 0.0000
219 OREGON - 01APSB41TA-OR IRR TOUOPT A 63,490 27 0.0000
220 OREGON - 01APSB41TB-OR IRR TOUOPT B 8,322 16 0.0000
221 OREGON - 01APSV0041-AG PMP SRVCBP 1,284,409 2,269 0.0000
222 OREGON - 01APSV0215-OR IRRIGATION
TOU PILOT 19,288 7 0.0000
223 OREGON - 01APSV041L-OR Pumping
Serv >30KW 2,126,498 600 0.0000
224 OREGON - 01APSV041T - AGR PUMP
SRV-TOU OPTION 25,071 40 0.0000
225 OREGON - 01APSV041X-AG PMP SRVC 1,369,905 2,650 0.0000
226 OREGON - 01APSV41TA-OR IRGPUMPING TOU OPT-A 28,628 22 0.0000
227 OREGON - 01APSV41TB-OR IRG
PUMPING TOU OPT-B 2,862 10 0.0000
228 OREGON - 01APSV41XL-OR Pumping
Serv no BPA >30KW 2,279,568 506 0.0000
229 OREGON - 01COST0041 -01APSV0041-01APSV041X AG PMP 139,052 6,568,991 0.0472
230 OREGON - 01COST0048 - 01LGSV0048IRR 24,017 1,028,741 0.0428
231 OREGON - 01COST0215-OR TOU PILOTCOST BASED SPPLY 4,842 228,635 0.0472
232 2,245 97,187 0.0433
OREGON - 01COST041T- AG IRG TOU
ENERGY SUPPLY SVC
233 OREGON - 01CSTUSB41-USBRIRRIGATION CONTRACTS CSS 79,378 3,747,940 0.0472
234 OREGON - 01GNSV023T, OR GEN SRV,TOU Option IRR 499 1 0.0000
235 OREGON - 01HABIT041 - 01APSV0041AG PMP SRVC 4 178 0.0445
236 OREGON - 01LGSB0048 - LG GEN SVC >
1000KW (R)150,596 2 0.0000
237 OREGON - 01LGSV0048-1000KW AND
OVR IRR 541,579 2 0.0000
238 OREGON - 01LNX00103-LINE EXT 80% G 19,725 0.0000
239 OREGON - 01LNX00109-REF/NREF ADV+ B 150 0.0000
240 OREGON - 01LNX00110-REF/NREF ADV
+96,924 0.0000
241 OREGON - 01LNX00310-LINE
EXTENSION CONTRACT 15,242 0.0000
242 OREGON - 01PTOU0023, OR GEN SRV,TOU ENG SPLY SRV IRR 7 441 0.0630
243 OREGON - 01PTOU0041 - 01APSV0041AG PMP SRVC 436 20,623 0.0473
244 OREGON - 01RENEW041 - 01APSV0041AG PMP SRVC 140 6,607 0.0472
245 OREGON - 01STDAY041 - Daily StandardOffer Sch 25 167 12,654 0.0758
246 OREGON - 01USBR0215-OR IRG TOU
PILOT USBR CUST 169,446 55 0.0000
247 OREGON - 01USBRGV41-IRG TOU W/O
BPA (6,198)9 0.0000
248 OREGON - 01USBROF41-KLAMATHBASIN IRG OFF PRJ LND 1,589,896 472 0.0000
249 OREGON - 01USBRON41-KLAMATHBASIN IRG ON PJT LND 1,779,001 1,102 0.0000
250 OREGON - 01VIR41136-OR VOLUMEINCENTIVE-AGRI PUMP 68,638 26 0.0000
251 OREGON - 01VRU41136-OR VOL
INCENTIVE USB CONTRACT 402,312 104 0.0000
252 OREGON - 01VRU41215-OR VOL
INCENTIVE USB TOU PLT 41,270 6 0.0000
253 OREGON - SOLAR FEED-IN REVENUEIRR 100,691 0.0000
254 OREGON - COMMUNITY SOLARREVENUE IRR 7,514 0.0000
255 OREGON - INCOME TAX DEFERRALADJUSTMENTS IRR 263,729 0.0000
256 OREGON - OR GAIN ON SALE OF ASSET
IRR 110 0.0000
257 OREGON - DSM REVENUE-IRRIGATION 757,796 0.0000
258 OREGON - BLUE SKY REVENUE-IRRIGATION 308 0.0000
259 OREGON - 01LNX00312 - OR IRG LINEEXT 25,964 0.0000
260 OREGON - 01LNX00316-LINEEXTENTION 120 0.0000
261 OREGON - 01NM41A135-OR NET MTR
IRG TOU OPT A 2-6 61 0.0000
262 OREGON - 01NMB41135-OREGON NET
METER IRRIGATION 33,483 18 0.0000
263 OREGON - 01NMO41135-OR USBR IRGNT MTR OFF PJ LND 905 0.0000
264 OREGON - 01NMT41135 - NETMTR AGPMP SVC 18,251 28 0.0000
265 OREGON - 01NMU41135 - OR NET MTR -PROJECT LAND 35,372 11 0.0000
266 OREGON - 01NMU41215-IRG TOU PILOTUSBR NET MTR (52)0.0000
267 OREGON - REVENUE_ACCOUNTING
ADJUSTMENTS IRR (61,177)0.0000
268 UTAH - 08APSV0010-IRR & SOIL DRA 207,141 15,083,709 3,098 66,863 0.0728
269 UTAH - 08APSV10NS- Irg Soil Drain PumpNon Seas 60,445 3,920,645 316 191,278 0.0649
270 UTAH - 08CGM10136-UT IRG NET METERMANUAL 637 42,015 1 637,000 0.0660
271 UTAH - 08CGN10136-UT IRG AND SOIL
DRAIN NET MTR 10 1,029 2 5,000 0.1029
272 UTAH - 08LNX00002-MTHLY 80% GUAR
IRR 429 0.0000
273 UTAH - 08LNX00004-ANNUAL 80%GUAR 3,198 0.0000
274 UTAH - 08LNX00014-80% MIN MNTHLYIRR 3,611 0.0000
275 UTAH - 08LNX00017-ADV/REF&80%ANN
IRR 137,785 0.0000
276 UTAH - 08LNX00310 - IRR, 80% ANNUAL
MIN + 80% ?18,006 0.0000
277 UTAH - 08LNX00311 - LINE EXT 80%
GUARANTEE IRR 2,078 0.0000
278 UTAH - 08LNX00312 UT IRG LINE EXT 10,910 0.0000
279 UTAH - 08NMT010NS-IRR & SOIL DRAINNON SEASONAL 199 23,120 4 49,750 0.1162
280 UTAH - 08NMT10135-UT IRR_SOIL DRNG
NET MTR SVC 8,265 662,989 76 108,750 0.0802
281 UTAH - 08TCVLAACN-UTAH TCV LNX
ANNUAL GAR 1,979 0.0000
282 UTAH - 08TCVLNAGN-UTAH LNXANNUAL GAR NON RES 19,708 0.0000
283 UTAH - 08TCVLNXGN-TCV LNX - 80%GAR - NON RES IRR 118 0.0000
284 UTAH - INCOME TAX DEFERRALADJUSTMENTS IRR 0.0000
285 UTAH - REVENUE_ACCOUNTING
ADJUSTMENTS IRR (27,569)0.0000
286 UTAH - REVENUE ADJUSTMENT -
DEFERRED NPC IRR 369,787 0.0000
287 UTAH - SOLAR FEED-IN REVENUE IRR 44,721 0.0000
288 UTAH - DSM REVENUE-IRRIGATION 274,614 0.0000
289 UTAH - BLUE SKY REVENUE-
IRRIGATION 167 0.0000
290 WASHINGTON - 02APSV0040-WA AG
PMP SRVC 101,178 8,337,555 2,508 40,342 0.0824
291 WASHINGTON - 02APSV040X-WA AGPMP SRVC 82,094 6,865,483 2,618 31,358 0.0836
292 WASHINGTON - 02LNX00102-LINE EXT80% G 398 0.0000
293 WASHINGTON - 02LNX00103-LINE EXT80% G IRR 16,465 0.0000
294 WASHINGTON - 02LNX00105-CNTRCT $
MIN G 76 0.0000
295 WASHINGTON - 02LNX00109-REF/NREF
ADV +851 0.0000
296 WASHINGTON - 02LNX00110-REF/NREFADV +87,043 0.0000
297 WASHINGTON - 02LNX00310 - IRG, 80%ANNUAL MIN + 80%6,540 0.0000
298 WASHINGTON - 02LNX00312 - WA IRGLINE EXT 20,640 0.0000
299 WASHINGTON - 02NMT40135-WA NETMETERING-IRG 337 34,713 10 33,800 0.1027
300 WASHINGTON - 02NMX40135-WA NET
METERING-IRG 53 11,006 11 4,818 0.2077
301 WASHINGTON - REVENUE ADJUSTMENT
- DEFERRED NPC IRR 4,649 0.0000
302 WASHINGTON -REVENUE_ACCOUNTING
ADJUSTMENTS IRR
542,844 0.0000
303 WASHINGTON - INCOME TAX DEFERRALADJUSTMENTS IRR 45,007 0.0000
304 WASHINGTON - DSM REVENUE-IRRIGATION 495,369 0.0000
305 WASHINGTON - BLUE SKY REVENUE-IRRIGATION 2,284 0.0000
306 WASHINGTON - ALT REVENUE
PROGRAM ADJUSTMENTS IRR (118,844)0.0000
307 WYOMING - 05APS00040-AG PUMPING
SVC-A 24,949 2,001,987 739 33,760 0.0802
308 WYOMING - 05APS0040T-WY IRG TOUPILOT 140 1 0.0000
309 WYOMING - 05APSNS040-AG PUMPINGSVC - NON SEASON 2,080 172,441 35 59,429 0.0829
310 WYOMING - 05LNX00103-LINE EXT 80%G 1,216 0.0000
311 WYOMING - 05LNX00110-REF/NREF ADV+ A 30,447 0.0000
312 WYOMING - 05LNX00312 - WY IRG LINE
EXT-A 1,546 0.0000
313 WYOMING - 09APSNS210-IRR & SOIL
DRA - NON SEASON-A 8 1,328 1 8,000 0.1659
314 WYOMING - INCOME TAX DEFERRALADJUSTMENTS IRR 4,113 0.0000
315 WYOMING - REVENUE_ACCOUNTINGADJUSTMENTS IRR (11,232)0.0000
316 WYOMING - REVENUE ADJUSTMENT -DEFERRED NPC IRR (3,743)0.0000
317 WYOMING - DSM REVENUE-
IRRIGATION-A 27,614 0.0000
318 WYOMING - BLUE SKY REVENUE-
IRRIGATION 34 0.0000
319 WYOMING - 05APS00040-AG PUMPINGSVC-B 370 29,339 8 46,250 0.0793
320 WYOMING - 05LNX00110-REF/NREF ADV+ B 7,064 0.0000
321 WYOMING - 05LNX00312 - WY IRG LINEEXT-B 240 0.0000
322 WYOMING - 09APSNS210-IRR & SOIL
DRA - NON SEASON-B 569 51,298 5 113,800 0.0902
323 WYOMING - 09APSV0210-IRR & SOIL
DRA 7,167 544,474 100 71,670 0.0760
324 WYOMING - DSM REVENUE-
IRRIGATION-B 10,955 0.0000
325 LESS MULTIPLE BILLINGS IRRIGATION (871)
41 TOTAL Billed Large (or Ind.) Sales 19,432,437 1,280,250,464 33,024 2,022,873 0.1551
42 TOTAL Unbilled Rev. Large (or Ind.) (See
Instr. 6)(16,494)(2,739,000)0.0000
43 TOTAL Large (or Ind.)19,415,943 1,277,511,464 33,024 2,022,873 0.1551
FERC FORM NO. 1 (ED. 12-95)Page 304
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 rateschedule 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 waterheating 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 ofCustomers(d)
KWh of Sales PerCustomer(e)
Revenue Per KWhSold(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed Commercial and Industrial
Sales
42 TOTAL Unbilled Rev. (See Instr. 6)
43 TOTAL
FERC FORM NO. 1 (ED. 12-95)Page 304
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 rateschedule 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 waterheating 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 ofCustomers(d)
KWh of Sales PerCustomer(e)
Revenue Per KWhSold(f)
1 CALIFORNIA - 06CUSL053E-SPECIALCUST O 1,060 158,915 107 9,907 0.1499
2 CALIFORNIA - 06CUSL058F-CUST OWNDSTR 52 9,390 20 2,600 0.1806
3 CALIFORNIA - 06SLCO0051-COMPANY
OWNED STREET LIGHTING 676 199,255 78 8,667 0.2948
4 CALIFORNIA - 06OALT015N-OUTD AR
LGT SR 208 1 0.0000
5 CALIFORNIA - DSM REVENUE-PSHL 4,868 0.0000
6 CALIFORNIA - OTHER CUSTOMERRETAIL REVENUE 167 0.0000
7 CALIFORNIA - INCOME TAX DEFERRALADJUSTMENTS 6,074 0.0000
8 CALIFORNIA - REVENUE_ACCOUNTING
ADJUSTMENTS (4,502)0.0000
9 IDAHO - 07GNSV023S-IDAHO TRAFFIC
SIGNALS 141 17,092 22 6,130 0.1212
10 IDAHO - 07SLCO0011-STR LGT CO-OWN 182 87,961 59 3,085 0.4833
11 IDAHO - 07SLCU012E-ENGY STR LGT-CUST OWN 472 51,864 59 8,000 0.1099
12 IDAHO - 07SLCU012F-FULL MNT STR
LGT-CUST OWN 1,755 349,512 184 9,538 0.1992
13 IDAHO - 07SLCU012P-PART MNT STR
LGT CUST OWN 194 28,220 16 12,125 0.1455
14 IDAHO - INCOME TAX DEFERRALADJUSTMENTS 190 0.0000
15 IDAHO - REVENUE_ACCOUNTINGADJUSTMENTS (2,650)0.0000
16 IDAHO - DSM REVENUE-PSHL 12,015 0.0000
17 OREGON - 01COSL0052-STR LGT SRVC
C 4 475 0.1189
18 OREGON - 01COST023F - OR GEN SRV -
COST-BASED 597 31,144 0.0522
19 OREGON - 01CUSL0053-CUS-OWNEDMTRD 462 34,878 71 6,507 0.0755
20 OREGON - 01GNSV023F - OR GEN SRV -FLAT RATE 107,027 14 0.0000
21 OREGON - 01CUSL053E-STR LGT SVC 8,437 637,783 227 37,000 0.0756
22 OREGON - 01CUSL053F-STR LGT SRVC
C 80 6,788 7 11,429 0.0849
23 OREGON - 01CUSL53E2-STR LGT SVC 219 16,635 4 54,750 0.0760
24 OREGON - 01HPSV0051-HI PRESSURESO 16,772 2,805,769 733 22,881 0.1673
25 OREGON - 01OALT015N-OUTD AR LGT
NR 42 5,807 24 1,750 0.1383
26 OREGON - 01OALTB15N-OR OUTD AR
LGT NR 13 2,214 13 1,000 0.1703
27 OREGON - 01SLCO0051-OR COMPANY
OWNED STREET LIGHT
8,102 1,325,606 378 21,434 0.1636
28 OREGON - COMMUNITY SOLARREVENUE 405 0.0000
29 OREGON - DSM REVENUE-PSHL 83,391 0.0000
30 OREGON - INCOME TAX DEFERRAL
ADJUSTMENTS 6,959 0.0000
31 OREGON - OR GAIN ON SALE OF ASSET 810 0.0000
32 OREGON - REVENUE_ACCOUNTINGADJUSTMENTS 4,901 0.0000
33 OREGON - SOLAR FEED-IN REVENUE 3,203 0.0000
34 UTAH - 08CFR00012-STR LGTS (CONV 54 0.0000
35 UTAH - 08CFR00051-MTH FAC SRVCHG 4,529 0.0000
36 UTAH - 08CFR00062-STREET LIGHTS 79 0.0000
37 UTAH - 08OALT007N-SECURITY AR LG 448 66,277 252 1,778 0.1479
38 UTAH - 08TOSS015F-TRAFFIC SIG NM 1,150 98,102 121 9,504 0.0853
39 UTAH - PSHL CUSTOMER BILL CREDITS (163)0.0000
40 UTAH - 08SLCO0011-STR LGT CO-OWN 13,236 3,633,811 727 18,206 0.2745
41 UTAH - 08TOSS0015-TRAF & OTHER S 3,331 353,844 1,431 2,328 0.1062
42 UTAH - 08MONL0015-MTR OUTDONIGHT 918 51,044 108 8,500 0.0556
43 UTAH - 08SLCU012P-STR LGT CUST-O 1,323 102,690 148 8,879 0.0776
44 UTAH - 08SLCU012F-STR LGT CUST-O 710 70,564 60 11,817 0.0995
45 UTAH - 08SLCU012E-DECOR CUST-OWN 37,581 1,734,481 1,065 35,287 0.0462
46 UTAH - DSM REVENUE-PSHL 62,412 0.0000
47 UTAH - REVENUE_ACCOUNTING
ADJUSTMENTS (6,381)0.0000
48 UTAH - REVENUE ADJUSTMENT -DEFERRED NPC 85,595 0.0000
49 UTAH - SOLAR FEED-IN REVENUE 10,164 0.0000
50 WASHINGTON - 02CFR00012-STR LGTS
(CONV 91 0.0000
51 WASHINGTON - 02CUSL053F-WA STR
LGT SRV 1,396 60,944 119 11,731 0.0437
52 WASHINGTON - 02CUSL053M-WA STRLGT SRV 719 32,342 112 6,363 0.0450
53 WASHINGTON - 02SLCO0051-WACOMPANY STREET LIGHTING 1,958 446,627 225 8,702 0.2281
54 WASHINGTON - PSHL CUSTOMER BILLCREDITS (27,013)0.0000
55 WASHINGTON - INCOME TAX DEFERRAL
ADJUSTMENTS 5,569 0.0000
56 WASHINGTON - DSM REVENUE-PSHL 9,895 0.0000
57 WASHINGTON -REVENUE_ACCOUNTING
ADJUSTMENTS
2,059 0.0000
58 WYOMING - 05COSL0057-CO-OWND STRLG 91 12,757 7 13,000 0.1402
59 WYOMING - 05CUSL0058-CUST OWNDSTR 47 2,337 9 5,222 0.0497
60 WYOMING - 05CUSL0E58-WY CUSTOWNED STREET LIGHT 1,138 55,331 34 33,471 0.0486
61 WYOMING - 05CUSL0M58-CUST OWNED
STREET LT W/MAIT-A 44 2,667 3 14,667 0.0606
62 WYOMING - 05MVS00053-MERCURY
VAPOR 2,010 225,644 124 16,210 0.1123
63 WYOMING - 05OALT015N-OUTD AR LGTSR 40 3,592 5 8,000 0.0898
64 7,714 1,295,006 303 25,459 0.1679
WYOMING - 05SLCO0051-WY STREET
LIGHT COMPANY OWNED-A
65 WYOMING - DSM REVENUE-PSHL-A 28,143 0.0000
66 WYOMING - INCOME TAX DEFERRALADJUSTMENTS 1,462 0.0000
67 WYOMING - REVENUE_ACCOUNTING
ADJUSTMENTS (4,627)0.0000
68 WYOMING - REVENUE ADJUSTMENT -
DEFERRED NPC (1,305)0.0000
69 WYOMING - 05CUSL0M58-CUST OWNEDSTREET LT W/MAIT-B 16 2,161 2 5,333 0.1351
70 WYOMING - 05RCFL0054-WY REC FIELDL 44 2,579 9 4,889 0.0586
71 WYOMING - 05SLCO0051-WY STREETLIGHT COMPANY OWNED-B 784 122,764 27 29,037 0.1566
72 WYOMING - 09MONL0213-WY MTR
OUTDOOR NIGHT LIGHT 11 590 1 11,000 0.0536
73 WYOMING - 09SLCO0211-STR LGT CO-
OWN 767 165,997 26 29,500 0.2164
74 WYOMING - 09SLCUP212-CUST OWNEDSTREET LT PART MNT 17 2,425 3 5,667 0.1427
75 WYOMING - 09TOSS0213-WY TRAFFIC &OTHER SIGNAL SYS 28 1,372 8 3,500 0.0490
76 WYOMING - DSM REVENUE-PSHL-B 5,369 0.0000
77 LESS MULTIPLE BILLINGS (3,369)
41 TOTAL Billed Public Street and HighwayLighting 114,781 14,714,254 3,577 31,911 0.1290
42 TOTAL Unbilled Rev. (See Instr. 6)(653)(99,000)(0.0009)
43 TOTAL 114,128 14,615,254 3,577 31,911 0.1281
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 rateschedule 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 waterheating 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 ofCustomers(d)
KWh of Sales PerCustomer(e)
Revenue Per KWhSold(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed Provision For Rate Refunds
42 TOTAL Unbilled Rev. (See Instr. 6)
43 TOTAL
FERC FORM NO. 1 (ED. 12-95)Page 304
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 rateschedule 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 waterheating 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 ofCustomers(d)
KWh of Sales PerCustomer(e)
Revenue Per KWhSold(f)
41 TOTAL Billed - All Accounts 56,114,673 4,834,790,943 2,002,780
42 TOTAL Unbilled Rev. (See Instr. 6) - All
Accounts 159,261 9,848,000
43 TOTAL - All Accounts 56,273,934 4,844,638,943 2,002,780 28,098 0.0907
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 haswith 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 itssystem 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 thateither 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, mustmatch 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 thecontract 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 eachadjustment.
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), theaverage 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 amegawatt 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-RequirementsSales 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 orPublic Authority
(Footnote
Affiliations)(a)
Statistical
Classification
(b)
FERC RateSchedule
or Tariff
Number(c)
Average
MonthlyBillingDemand(MW)
(d)
AverageMonthly
NCP
Demand(e)
AverageMonthly CPDemand(f)
MegawattHoursSold(g)
DemandCharges($)(h)
Energy
Charges ($)
(i)
Other
Charges ($)
(j)
Total ($)
(h+i+j)
(k)
1 Requirement Sales:
2 Helper City RQ T-6 1 1 1 6,364 130,724 112,475 243,199
3 Helper City Annex RQ T-6 1 1 1 3,574 71,412 63,179 134,591
4 Navajo Tribal UtilityAuthority RQ T-12 31 31 29 258,726 5,785,847 7,482,649 (k)(621,244)12,647,252
5 Navajo Tribal UtilityAuthority (MexicanHat)RQ T-6 0 0 0 871 17,824 15,192 33,016
6 Navajo Tribal UtilityAuthority (Red Mesa)RQ T-6 2 2 1 9,848 160,155 174,004 334,159
7 Accrual RQ (550)(l)(148,152)(148,152)
8 Non-Requirement
Sales:
9 Arizona Electric PowerCooperative, Inc.SF T-12 53,887 1,967,097 1,967,097
10 Arizona Public ServiceCompany SF T-12 6,637 464,978 464,978
11 Avangrid Renewables,LLC
(c)
AD T-12 10 (m)343 343
12 Avangrid Renewables,
LLC SF T-12 95,756 4,329,190 4,329,190
13 SF T-13 74 (n)1,634 1,634
Avangrid Renewables,
LLC
14 Avista Corporation SF T-12 19,310 898,755 898,755
15 Avista Corporation SF T-13 68 (o)3,072 3,072
16 Basin Electric Power
Cooperative SF T-12 24,140 1,390,639 1,390,639
17 Black Hills Power, Inc.(d)
LF 441 50 50 48 342,281 1,042,864 7,940,889 8,983,753
18 Black Hills Power, Inc.SF T-12 140,402 5,487,726 5,487,726
19 Bonneville Power
Administration SF T-12 94,968 3,819,686 3,819,686
20 Bonneville Power
Administration SF T-13 116 (p)3,248 3,248
21 Bonneville PowerAdministration SF WSPP-Q 5,740 196,726 196,726
22 BP Energy Company SF T-12 88,962 3,295,335 3,295,335
23
British Columbia
Hydro and PowerAuthority SF T-13 283 (q)21,706 21,706
24
Brookfield Renewable
Trading and MarketingLP SF T-12 31,902 1,299,897 1,299,897
25
California Independent
System OperatorCorporation SF T-12 564 13,152 13,152
26 Calpine EnergyServices, L.P.SF T-12 3,455 107,463 107,463
27 Citigroup Energy Inc.(e)
AD T-12 6 (r)200 200
28 Citigroup Energy Inc.SF T-12 806,783 23,105,055 23,105,055
29 City of Burbank SF T-12 24,732 902,280 902,280
30 City of Burbank SF WSPP-Q 480 17,280 17,280
31 City of Glendale SF T-12 599 22,073 22,073
32 City of Hurricane IF 560 270 15,813 15,813
33 City of Idaho Falls SF WSPP-Q 4,405 103,500 103,500
34 City of Redding SF T-12 2,195 115,630 115,630
35 City of Roseville SF T-12 9,819 441,270 441,270
36 City of St. George,Utah SF T-12 700 32,365 32,365
37 Clatskanie People'sUtility District SF T-12 1,380 58,907 58,907
38 ConocoPhillipsCompany SF T-12 43,197 1,865,121 1,865,121
39 CP Energy Marketing
(US) Inc.SF T-12 450 17,100 17,100
40 DTE Energy Trading,
Inc.SF T-12 189,161 6,308,852 6,308,852
41 Dynasty Power Inc.SF T-12 1,726 127,748 127,748
42 EDF Trading NorthAmerica, LLC SF T-12 22,439 1,292,529 1,292,529
43 El Paso ElectricCompany SF T-12 4,416 347,120 347,120
44 Energy Keepers, Inc.SF T-12 9,268 301,067 301,067
45 Eugene Water &Electric Board SF T-12 6,577 278,001 278,001
46 Exelon GenerationCompany, LLC SF T-12 549,718 24,232,649 24,232,649
47 Exelon GenerationCompany, LLC SF WSPP-Q 25 1,875 1,875
48 Gridforce Energy
Management, LLC SF T-13 337 (s)13,988 13,988
49 Guzman Energy, LLC SF T-12 2,322 139,428 139,428
50 Idaho Power Company SF T-12 400 20,000 20,000
51 Idaho Power Company SF T-13 79 (t)4,106 4,106
52 Idaho Power Company SF WSPP-Q 25,157 803,930 803,930
53 Los AngelesDepartment of Waterand Power SF T-12 7,000 257,870 257,870
54 Macquarie EnergyLLC SF T-12 102,848 5,950,424 5,950,424
55 Macquarie EnergyLLC SF WSPP-Q 9,858 300,319 300,319
56
Metropolitan Water
District Of SouthernCalifornia SF T-12 1,000 37,600 37,600
57 Modesto Irrigation
District SF T-12 50,716 1,998,046 1,998,046
58 Morgan Stanley
Capital Group Inc.
(f)
AD T-12 2 (u)48 48
59 Morgan StanleyCapital Group Inc.SF T-12 591,049 19,098,805 19,098,805
60 Morgan StanleyCapital Group Inc.SF WSPP-Q 275 15,574 15,574
61 NaturEner PowerWatch, LLC SF T-13 204 (v)5,170 5,170
62
(a)
Nevada PowerCompany SF WSPP-Q 2,413 134,166 134,166
63 NextEra EnergyMarketing, LLC SF T-12 20,733 678,211 678,211
64 Northern California
Power Agency SF T-12 400 42,400 42,400
65 NorthWestern Energy SF T-13 155 (w)4,249 4,249
66 NorthWestern Energy SF WSPP-Q 4,042 153,448 153,448
67 Portland General
Electric Company SF T-12 55,203 2,798,201 2,798,201
68 Portland General
Electric Company SF T-13 96 (x)3,887 3,887
69 Powerex Corporation SF T-12 60,741 2,184,261 2,184,261
70 Powerex Corporation SF WSPP-Q 2,389 52,558 52,558
71 Public Service
Company of Colorado SF T-12 223,784 7,131,199 7,131,199
72 Public ServiceCompany of Colorado SF T-13 158 (y)8,074 8,074
73 Public ServiceCompany of NewMexico SF T-12 35,461 2,127,228 2,127,228
74 Public Utility DistrictNo. 1 of Chelan
County
SF T-13 13 (z)333 333
75 Public Utility DistrictNo. 1 of Snohomish
County
SF T-12 4,809 246,200 246,200
76 Public Utility DistrictNo. 2 of Grant County SF T-13 3 (aa)69 69
77 Puget Sound Energy,Inc.SF T-12 26,485 931,397 931,397
78 Puget Sound Energy,Inc.SF T-13 14 (ab)701 701
79 Rainbow Energy
Marketing Corporation SF T-12 51,372 1,914,968 1,914,968
80 Sacramento Municipal
Utility District SF T-12 18,776 791,456 791,456
81 Sacramento MunicipalUtility District SF T-13 16 (ac)503 503
82 Salt River Project SF T-12 5,068 138,349 138,349
83 Seattle City Light SF T-12 12,775 409,175 409,175
84 Seattle City Light SF T-13 131 (ad)13,742 13,742
85 Shell Energy NorthAmerica (US), L.P.SF T-12 1,068,778 36,779,430 36,779,430
86 Shell Energy NorthAmerica (US), L.P.SF WSPP-Q 173,324 5,755,686 5,755,686
87
(b)
Sierra Pacific PowerCompany SF T-13 53 (ae)4,351 4,351
88 Tacoma Power SF T-12 6,280 208,562 208,562
89 Tenaska PowerServices Co.SF T-12 220,213 9,630,370 9,630,370
90 Tenaska PowerServices Co.SF WSPP-Q 75,701 2,689,706 2,689,706
91 The Energy Authority,Inc.SF T-12 34,109 1,265,186 1,265,186
92 TransAlta Energy
Marketing (U.S.) Inc.SF T-12 103,642 4,692,274 4,692,274
93 TransAlta Energy
Marketing (U.S.) Inc.SF WSPP-Q 25 800 800
94 Tri-State Generationand Transmission
Association, Inc.
SF T-12 43,601 2,025,810 2,025,810
95 Tucson Electric Power
Company SF T-12 119,121 5,091,558 5,091,558
96 Turlock IrrigationDistrict SF T-12 70,504 2,622,457 2,622,457
97 Turlock IrrigationDistrict SF T-13 5 (af)339 339
98 Uniper GlobalCommodities NorthAmerica LLC SF T-12 6,758 404,671 404,671
99 UNS Electric, Inc.SF T-12 39,334 1,519,440 1,519,440
100
Utah Associated
Municipal Power
Systems
SF WSPP-Q 56,357 1,587,338 1,587,338
101 Utah Municipal Power
Agency SF WSPP-Q 73,725 3,020,181 3,020,181
102 Vitol Inc.SF T-12 3,398 115,020 115,020
103 Western Area PowerAdministration-Colorado Missouri SF T-12 169,884 7,332,930 7,332,930
104 Western Area PowerAdministration-Colorado Missouri SF T-13 861 (ag)52,950 52,950
105 Western Area PowerAdministration-LowerColorado SF T-12 400 9,840 9,840
106 Western Area PowerAdministration-SierraNevada SF T-12 34,508 946,367 946,367
107 Western Area PowerAdministration-UpperColorado SF T-12 212,763 8,602,961 8,602,961
108 Test Generation (g)
AD 8,692 (ah)159,757 159,757
109 Test Generation (h)
OS (76,753)(ai)(1,432,278)(1,432,278)
110 Transmission Loss
Sales Revenue
(i)
AD T-11 6 (aj)1,241 1,241
111 Transmission Loss
Sales Revenue
(j)
OS T-11 266,743 (ak)10,567,702 10,567,702
112 Netting-Bookouts (1,776,035)(al)(61,513,064)(61,513,064)
113 Netting-Trading (am)(1,049,308)(1,049,308)
114 Accrual (5,218)(an)(856,145)(856,145)
15 Subtotal - RQ 278,833 6,165,962 7,847,499 (769,396)13,244,065
16 Subtotal-Non-RQ 4,833,964 1,042,864 233,453,568 (53,979,382)180,517,050
17 Total 5,112,797 7,208,826 241,301,067 (54,748,778)193,761,115
FERC FORM NO. 1 (ED. 12-90)
Page 310-311
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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
Black Hills Power, Inc. - contract termination date: December 31, 2023.
(e) Concept: StatisticalClassificationCode
Settlement adjustment.
(f) Concept: StatisticalClassificationCode
Settlement adjustment.
(g) Concept: StatisticalClassificationCode
Settlement adjustment.
(h) Concept: StatisticalClassificationCode
The negative revenue reported on this line reflects test energy generated that was transferred to Account 107, Construction work in progress for the following wind-powered generating
facilities: Foote Creek I, Pryor Mountain, and TB Flats.Energy generated during testing was delivered to PacifiCorp's electric system for sale as accounted for under the guidance in 18
C.F.R., Part 101, Electric Plant Instructions Electric Plant Instructions 3, 18(a). Test energy is a component of construction work in progress and is reported at the fair value of the energy
delivered.
(i) Concept: StatisticalClassificationCode
Settlement adjustment.
(j) Concept: StatisticalClassificationCode
Transmission loss sales revenues collected from PacifiCorp's third-party transmission service customers.
(k) Concept: OtherChargesRevenueSalesForResale
Load retention $(723,827)
Customer service charges related to:102,583
- 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
$(621,244)
(l) 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.
(m) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(n) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(o) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(p) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(q) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(r) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(s) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(t) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(u) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(v) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(w) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(x) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(y) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(z) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(aa) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ab) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ac) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ad) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ae) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(af) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ag) Concept: OtherChargesRevenueSalesForResale
Reserve share.
(ah) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(ai) Concept: OtherChargesRevenueSalesForResale
The negative revenue reported on this line reflects test energy generated that was transferred to Account 107, Construction work in progress for the following wind-powered generating facilities: Foote Creek I, Pryor Mountain, and TB Flats.Energy generated during testing was delivered to PacifiCorp's electric system for sale as accounted for under the guidance in 18 C.F.R., Part 101, Electric Plant Instructions Electric Plant Instructions 3, 18(a). Test energy is a component of construction work in progress and is reported at the fair value of the energy delivered.
(aj) Concept: OtherChargesRevenueSalesForResale
Settlement adjustment.
(ak) Concept: OtherChargesRevenueSalesForResale
Transmission loss sales revenues collected from PacifiCorp's third-party transmission service customers.
(al) Concept: OtherChargesRevenueSalesForResale
Reflects transactions that did not physically settle.
(am) Concept: OtherChargesRevenueSalesForResale
Reflects transactions that were categorized as trading activities.
(an) 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.
FERC FORM NO. 1 (ED. 12-90)Page 310-311
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 13,702,637 16,129,284
5 681,733,834 681,801,669
6 74,176,098 76,240,280
7 5,403,741 6,509,105
8
9 916,105 1,537,510
10 30,859,783 60,013,889
11 462,521 471,449
12
13 807,254,719 842,703,186
14
15 5,275,696 8,206,527
16 19,593,314 31,374,467
17 66,310,145 70,714,383
18 31,198,027 26,678,095
19 11,830,404 9,600,799
20 134,207,586 146,574,271
21 941,462,305 989,277,457
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
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
39
40
41
42
43
44 10,210,632 9,728,617
45 236,861 155,554
46 4,546,533 4,805,592
47
48 17,346,302 16,386,285
49 1,890,597 1,781,762
50 34,230,925 32,857,810
51
52
53 384 394
54 961,454 696,412
55 909,945 1,417,042
56 1,821,792 1,680,183
57 (a)(21,144,614)37,153,349
58 (17,451,039)40,947,380
59 16,779,886 73,805,190
60
61
62 315,815 350,785
63 333,859,748 252,620,782
64 17,000,142 19,594,249
64.1
65 8,840,800 8,625,877
66 10,234,559 5,102,234
67 370,251,064 286,293,927
68
69
70 3,041,462 4,362,235
71 21,376,958 16,030,141
71.1
72 3,197,336 2,900,157
73 27,615,756 23,292,533
74 397,866,820 309,586,460
75
76 682,349,483 707,124,705
76.1 0
77 474,524 677,650
78 39,466,614 41,143,081
79 722,290,621 748,945,436
80 2,078,399,632 2,121,614,543
81
(532) Maintenance of Miscellaneous Nuclear Plant
TOTAL Maintenance (Enter Total of lines 35 thru 39)
TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 &
40)
C. Hydraulic Power Generation
Operation
(535) Operation Supervision and Engineering
(536) Water for Power
(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)
82
83 10,250,114 8,359,068
85
86 6,922,647 7,719,651
87
88 998,544 1,198,333
89 2,388,711 2,375,511
90 61,696 139,663
91 1,551,212 829,798
92 5,672,396 4,780,276
93 3,332,703 3,412,615
93.1
94 1,246,724 1,038,503
95
96 159,058,497 141,188,225
97 2,330,927 3,041,748
98 2,688,993 2,217,342
99 196,503,164 176,300,733
100
101 851,471 939,674
102 84,542 90,224
103
104 936,999 838,778
105 4,951,310 4,700,965
106
107 11,669,287 11,205,549
107.1
108 17,140,571 16,393,049
109 70,738 229,967
110 93,758 192,730
111 35,798,676 34,590,936
112 232,301,840 210,891,669
113
114
115
116
117
118
119
120
121
122
123
124
125
2. TRANSMISSION EXPENSES
Operation
(560) Operation Supervision and Engineering
(561.1) Load Dispatch-Reliability
(561.2) Load Dispatch-Monitor and Operate Transmission System
(561.3) Load Dispatch-Transmission Service and Scheduling
(561.4) Scheduling, System Control and Dispatch Services
(561.5) Reliability, Planning and Standards Development
(561.6) Transmission Service Studies
(561.7) Generation Interconnection Studies
(561.8) Reliability, Planning and Standards Development Services
(562) Station Expenses
(562.1) Operation of Energy Storage Equipment
(563) Overhead Lines Expenses
(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
126
127
128
129
130
131
132
133
134 9,002,354 9,310,152
135 13,698,661 12,577,822
136 4,524,018 4,767,498
137 9,627,966 9,423,680
138 417
138.1
139 310,424 276,304
140 2,840,279 2,835,348
141 17,375,269 16,782,395
142 546,692 510,308
143 3,341,252 3,335,443
144 61,266,915 59,819,367
145
146 6,141,981 5,561,808
147 1,955,273 1,806,802
148 9,046,758 9,853,811
148.1
149 116,547,834 98,989,449
150 31,879,531 27,804,232
151 1,195,363 1,002,821
152 1,947,397 2,100,061
153 552,196 696,559
154 6,796,973 7,655,412
155 176,063,306 155,470,955
156 237,330,221 215,290,322
157
158
159 2,250,883 2,273,700
160 13,919,083 12,950,694
161 41,365,509 42,975,871
162 12,679,848 18,138,836
163 2,669 30,955
164 70,217,992 76,370,056
165
166
167 (535)670
168 110,137,782 104,747,958
(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 ofLines 123 and 130)
4. DISTRIBUTION EXPENSES
Operation
(580) Operation Supervision and Engineering
(581) Load Dispatching
(582) Station Expenses
(583) Overhead Line Expenses
(584) Underground Line Expenses
(584.1) Operation of Energy Storage Equipment
(585) Street Lighting and Signal System Expenses
(586) Meter Expenses
(587) Customer Installations Expenses
(588) Miscellaneous Expenses
(589) Rents
TOTAL Operation (Enter Total of Lines 134 thru 143)
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
169 3,873,160 5,453,497
170 1,265 1,747
171 114,011,672 110,203,872
172
173
174
175
176 293
177
178 293
179
180
181 76,127,716 79,083,452
182 9,793,857 11,377,137
183 38,091,540 37,851,096
184 27,252,619 20,941,909
185 (b)16,033,171 16,363,750
186 27,218,326 149,445,957
187 (c)124,791,272 118,191,960
188
189 26,427,417 25,986,830
190 (d)125,437,524 122,425,535
191 8,074 14,951
192 2,520,116 2,242,565
193 944,893 3,449,336
194 147,588,397 266,821,216
195
196 (e)26,057,380 25,099,866
197 (f)173,645,777 291,921,082
198 2,905,907,427 3,026,291,544
FERC FORM NO. 1 (ED. 12-93)Page 320-323
(909) Informational and Instructional Expenses
(910) Miscellaneous Customer Service and Informational Expenses
TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)
7. SALES EXPENSES
Operation
(911) Supervision
(912) Demonstrating and Selling Expenses
(913) Advertising Expenses
(916) Miscellaneous Sales Expenses
TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)
8. ADMINISTRATIVE AND GENERAL EXPENSES
Operation
(920) Administrative and General Salaries
(921) Office Supplies and Expenses
(Less) (922) Administrative Expenses Transferred-Credit
(923) Outside Services Employed
(924) Property Insurance
(925) Injuries and Damages
(926) Employee Pensions and Benefits
(927) Franchise Requirements
(928) Regulatory Commission Expenses
(929) (Less) Duplicate Charges-Cr.
(930.1) General Advertising Expenses
(930.2) Miscellaneous General Expenses
(931) Rents
TOTAL Operation (Enter Total of Lines 181 thru 193)
Maintenance
(935) Maintenance of General Plant
TOTAL Administrative & General Expenses (Total of Lines 194 and 196)
TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112,
131, 156, 164, 171, 178, and 197)
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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: 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 191(b)$16,033,171
Less: Situs property loss reserves, net of reimbursements 11,825,571
Revised (924) Property Insurance $4,207,600
To adjust PacifiCorp's formula rate, per FERC Docket No. FA16-4-000 for situs property loss reserves, net of reimbursements.
(c) Concept: EmployeePensionsAndBenefits
As required by Commission regulations, the cost of pensions, postretirement other than pensions and other employee benefits are reported in Account 926, Employee pensions and benefits. Pensions and benefits expense is associated with labor and generally charged to operations and maintenance expense and construction work in progress, therefore, pursuant to FERC Docket No. FA16-4-000, these pensions and benefits are offset in Account 929, Duplicate charges-credit.In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No. ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations should be excluded from the calculation of the wholesale transmission revenue requirement and charges under the wholesale formula rates, unless approved by the Commission. During the year ended December 31, 2021, pension and postretirement regulatory asset amortization and deferrals were $(8,986,759).
(d) Concept: DuplicateChargesCredit
Includes the offset of pensions and benefits in Account 926, Employee pensions and benefits, pursuant to FERC Docket No. FA16-4-000.
(e) Concept: 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)$26,057,380
Less: Write-off of assets under construction 137,294
Revised (935) Maintenance of General Plant $25,920,086
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.
(f) 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)$173,645,777
Less: Situs property loss reserves, net of reimbursements 11,825,571
Less: Pension and postretirement regulatory asset deferrals, net of amortization (8,986,759)
Less: Write-off of assets under construction 137,294
Revised TOTAL Administrative & General Expenses $170,669,671
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)
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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). MonthlyNCP 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 forthe net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote.8. The data in columns (g) through (n) must be totaled on the last line of the schedule. The total amount in columns (g) and (h) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13.9. Footnote entries as required and provide explanations following all required data.
Actual Demand (MW)POWER EXCHANGES COST/SETTLEMENT OF POWER
LineNo.(a)(b)(c)(d)(e)(f)
(g)(h)(i)(j)(k)(l)(m)(n)
1 3Degrees Group, Inc.AD
2 Adams Solar Center, LLC (d)
AD (bh)15,536 15,536
3 Adams Solar Center, LLC LU 21,889 1,490,867 (bi)16,519 1,507,386
4 Airport Solar, LLC (e)
OS (bj)376,250 376,250
5 Airport Solar, LLC (f)
AD (bk)(213,651)(213,651)
6 Amor IX LLC LU 130,602 7,307,568 7,307,568
7 Apple, Inc.LU 2,677 224,833 224,833
8 Arizona Electric Power Cooperative, Inc.SF 7,700 1,154,754 1,154,754
9 Arizona Public Service Company SF 34,099 2,813,626 2,813,626
10 Arizona Public Service Company (g)
AD (439)(bl)38,490 38,490
11 Avangrid Renewables, LLC SF 1,034,002 69,857,438 (bm)921 69,858,359
12 Avangrid Renewables, LLC (h)
AD 12 (bn)315 315
13 Avista Corporation SF 113,151 5,590,888 (bo)2,619 5,593,507
14 Basin Electric Power Cooperative, Inc.SF 13,311 963,614 963,614
15 BC Solar, LLC LU 17,875 1,218,976 1,218,976
16 Bear Creek Solar Center, LLC (i)
AD (bp)16,568 16,568
17 Bear Creek Solar Center, LLC LU 23,903 1,632,794 (bq)18,109 1,650,903
18 Beaver City Corporation (j)
LF 27 2,889 2,889
19 Bell Mountain Hydro, LLC LU 403 37,757 37,757
20 Beryl Solar, LLC LU 3 3 1 6,376 446,137 348,766 794,903
21 Big Top, LLC LU 3,968 314,792 314,792
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
(Excluding for
Energy Storage)
MegaWatt
HoursPurchasedfor EnergyStorage
MegaWattHoursReceived
MegaWattHoursDelivered
DemandCharges($)
Energy
Charges ($)
Other Charges
($)
Total (k+l+m)of
Settlement
($)
22 Biomass One, L.P.LU 193,564 15,834,907 (br)2,069,797 17,904,704
23 Birch Power Company, Inc.LU 12,336 781,953 781,953
24 (a)
Black Cap Solar, LLC LU 668 43,864 43,864
25 Black Hills Power, Inc.SF 4,734 374,565 374,565
26 Bly Solar Center, LLC (k)
AD (bs)14,578 14,578
27 Bly Solar Center, LLC LU 20,443 1,394,645 (bt)16,072 1,410,717
28 Bonneville Power Administration (l)
LF (bu)138,281 138,281
29 Bonneville Power Administration (m)
SF 454,090 28,770,205 (bv)16,062 28,786,267
30 Bourdet, Peter M LU 307 18,925 18,925
31 Box Canyon Limited Partnership LU 5,124 139,429 139,429
32 BP Energy Company SF 372,760 23,210,891 23,210,891
33 Brigham Young University - Idaho IU 38,057 2,149,919 2,149,919
34 Brookfield Renewable Trading and Marketing LP SF 28,599 2,689,492 2,689,492
35 Buckhorn Solar, LLC LU 3 3 1 5,965 446,881 326,297 773,178
36 Butter Creek Power, LLC LU 12,806 1,015,044 1,015,044
37 California Independent System Operator Corporation SF 22,206 4,180,698 4,180,698
38 Calpine Energy Services, L.P.SF 18,117 990,248 990,248
39 Cedar Springs III, LLC LU 528,019 9,345,935 9,345,935
40 Cedar Springs Wind, LLC LU 762,075 11,812,145 11,812,145
41 Cedar Valley Solar, LLC LU 3 3 1 6,086 444,076 332,929 777,005
42 Central Oregon Irrigation District LU 25,962 2,384,908 2,384,908
43 Central Rivers Power, LLC LU 6,097 245,390 245,390
44 Chiloquin Solar LLC LU 19,447 936,525 936,525
45 Chopin Wind, LLC LU 31,670 1,881,961 1,881,961
46 Citigroup Energy Inc.SF 211,569 8,960,422 8,960,422
47 Citigroup Energy Inc.(n)
AD (26)(bw)(747)(747)
48 City of Albany LU 626 50,512 50,512
49 City of Anaheim SF 307 1,952 1,952
50 City of Burbank SF 8,504 747,080 747,080
51 City of Glendale SF 1,695 254,280 254,280
52 City of Hurricane (o)
LF 2,833 194,933 194,933
53 City of Idaho Falls, Idaho LU 52,833 (bx)1,800,708 1,800,708
54 City of Idaho Falls, Idaho (p)
AD (by)(49,449)(49,449)
55 City of Idaho Falls, Idaho SF 240 6,880 6,880
56 City of Portland, Portland Water Bureau LU 172 14,449 14,449
57 City of Preston Idaho LU 2,161 143,581 143,581
58 Clatskanie People's Utility District SF 466 42,653 42,653
59 Commercial Energy Magement Inc.LU 1,302 55,060 55,060
60 Confederate Tribes of Warm Springs LU 193 11,919 11,919
61 ConocoPhillips Company SF 180,208 11,732,151 11,732,151
62 Consolidated Irrigation Company LU 871 51,418 51,418
63 Cottonwood Hydro, LLC IU 3,352 161,294 161,294
64 Cove Mountain Solar 2, LLC LU 331,360 9,457,021 9,457,021
65 Cove Mountain Solar, LLC LU 159,142 3,843,279 (bz)905,518 4,748,797
66 Cove Mountain Solar, LLC (ca)279,163 279,163
(q)
AD
67 CP Energy Marketing (US) Inc.SF 1,130 159,300 159,300
68 Crook County Solar 1, LLC LU 1,112 70,132 70,132
69 Deschutes Valley Water District LU 20,028 506,329 506,329
70 Deschutes Valley Water District (r)
AD 49 (cb)7,079 7,079
71 Deseret Generation & Transmission Cooperative (s)
LF 100 100 88 467,255 19,212,455 11,406,014 (cc)4,918,341 35,536,810
72 Dorena Hydro, LLC LU 5,473 461,637 461,637
73 Douglas Co., Inc. dba Douglas Co. Forest Products LU 848 40,059 40,059
74 Douglas County LU 2,517 34,393 426,957 461,350
75 Draper Irrigation Company IU 28 3,732 3,732
76 Dry Creek LLC LU 3,335 172,334 172,334
77 Dry Creek LLC (t)
AD 50 (cd)3,157 3,157
78 DTE Energy Trading, Inc.SF 3,515 487,925 487,925
79 Dynasty Power Inc.SF 40,209 6,636,374 6,636,374
80 EDF Trading North America, LLC SF 89,385 6,482,252 6,482,252
81 El Paso Electric Company SF 26,488 1,117,872 1,117,872
82 Elbe Solar Center, LLC (u)
AD (ce)15,873 15,873
83 Elbe Solar Center, LLC LU 22,281 1,515,685 (cf)17,692 1,533,377
84 Energy Keepers, Inc.SF 14,160 1,252,863 1,252,863
85 Enterprise Solar, LLC (v)
AD (cg)216,121 216,121
86 Enterprise Solar, LLC LU 222,436 12,083,947 (ch)222,418 12,306,365
87 Escalante Solar I, LLC LU 207,267 11,047,216 11,047,216
88 Escalante Solar II, LLC LU 209,333 10,603,396 10,603,396
89 Escalante Solar III, LLC LU 195,324 9,559,221 9,559,221
90 Eugene Water & Electric Board SF 4,984 288,607 (ci)20,000 308,607
91 Eurus Combine Hills I, LLC LU 104,909 5,245,440 5,245,440
92 Exelon Generation Company, LLC SF 97,989 5,268,482 5,268,482
93 ExxonMobil Production Company LU 51 827 827
94 Fall River Rural Electric Cooperative, Inc.LU 22,777 1,301,632 1,301,632
95 Farm Power Misty Meadow, LLC LU 3,220 271,903 271,903
96 Farmers Irrigation District LU 21,535 1,800,418 1,800,418
97 Fillmore City Corporation (w)
LF 31 2,134 2,134
98 Finley BioEnergy, LLC LU 37,965 3,057,705 3,057,705
99 Flathead Electric Cooperative, Inc.(x)
LF 359 17,357 17,357
100 Four Corners Windfarm, LLC LU 18,171 1,444,801 1,444,801
101 Four Mile Canyon Windfarm, LLC LU 22,096 1,749,931 1,749,931
102 Georgetown Irrigation Company LU 1,684 68,162 68,162
103 Grand Valley Power (y)
LF 49 8,318 8,318
104 Granite Mountain Solar East, LLC LU 208,003 10,723,432 10,723,432
105 Granite Mountain Solar West, LLC LU 125,008 6,780,427 6,780,427
106 Granite Peak Solar, LLC LU 3 3 6,290 285,278 293,732 579,010
107 Greenville Solar, LLC LU 2 2 4,159 336,908 227,500 564,408
108 Gridforce Energy Magement, LLC SF 17 (cj)826 826
109 Guzman Energy, LLC SF 4,113 577,620 577,620
110 Hammerich 1 & 2 LU 1,142 72,386 72,386
111 Hayward Paul Luckey and Joanne Luckey Revocable Trust of 2005 LU 15 672 672
112 Hunter Solar LLC LU 249,980 6,796,195 (ck)904,924 7,701,119
113 Hunter Solar LLC (z)
AD 751 (cl)16,570 16,570
114 Idaho Power Company SF 150,594 5,116,971 (cm)9,010 5,125,981
115 Idaho Power Company (aa)
AD 1,609 (cn)48,780 48,780
116 Iron Springs Solar, LLC LU 207,983 11,104,044 11,104,044
117 J Bar 9 Ranch, Inc.LU 67 454 454
118 Jake Amy LU 1,154 68,504 68,504
119 Joseph Community Solar, LLC LU 691 43,890 43,890
120 Keeton 1 & 2 LU 381 24,190 24,190
121 Kettle Butte Digester LLC LU 7 146 146
122 Klamath Falls Solar 1, LLC LU 1,402 95,520 95,520
123 Klamath Falls Solar 2, LLC IU 6,474 311,744 311,744
124 Lacomb Irrigation District LU 4,151 152,418 (co)46,320 198,738
125 Laho Solar, LLC LU 3 3 5,917 274,868 276,326 551,194
126 Latigo Wind Park, LLC LU 161,054 9,732,379 9,732,379
127 Los Angeles Department of Water and Power SF 100,596 11,483,786 11,483,786
128 Loyd Fery LU 237 6,591 6,591
129 Loyd Fery (ab)
AD (cp)5 5
130 Macquarie Energy LLC SF 212,626 18,797,243 18,797,243
131 Marsh Valley Hydro Electric Company LU 3,981 253,003 253,003
132 Meadow Creek Project Company LLC LU 305,297 26,199,461 26,199,461
133 Meadow Creek Project Company LLC (ac)
AD 37 (cq)3,856 3,856
134 Middle Fork Irrigation District LU 21,258 1,653,583 1,653,583
135 Milford Flat Solar, LLC LU 3 3 1 6,310 285,266 294,680 579,946
136 Milford Solar I, LLC LU 268,900 7,010,236 (cr)1,056,777 8,067,013
137 Milford Solar I, LLC (ad)
AD (cs)227,567 227,567
138 Millican Solar Energy LLC LU 118,751 2,312,345 (ct)1,511,688 3,824,033
139 Mink Creek Hydro LLC LU 5,629 339,824 339,824
140 Monroe Hydro, LLC LU 704 59,370 59,370
141 Monsanto Company IU (cu)20,100,019 20,100,019
142 Monsanto Company (ae)
AD (cv)(6,000)(6,000)
143 Morgan City Corporation (af)
LF 8 677 677
144 Morgan Stanley Capital Group Inc.SF 180,740 28,375,097 28,375,097
145 Mountain Wind Power II, LLC LU 204,398 13,134,508 13,134,508
146 Mountain Wind Power, LLC LU 158,073 8,848,446 8,848,446
147 Myron Jones, Nola Jones, Larry Oja and Christie Oja LU 327 17,144 17,144
148 (b)
Nevada Power Company SF 29,593 1,522,370 1,522,370
149 NextEra Energy Marketing, LLC SF 10,680 453,195 453,195
150 Nichols Gap Limited Partnership LU 1 2,343 30,497 375,128 405,625
151 NorthWestern Corporation dba NorthWestern Energy SF 86 50,022 (cw)2,093 52,115
152 NorthWestern Corporation dba NorthWestern Energy (ag)
AD (150)(cx)(2,473)(2,473)
153 NorWest Energy 2, LLC IU 22,249 1,520,903 1,520,903
154 NorWest Energy 4, LLC IU 9,908 685,970 685,970
155 NorWest Energy 7, LLC IU 15,538 1,060,745 1,060,745
156 NorWest Energy 9, LLC IU 11,923 574,036 574,036
157 Nucor Corporation (ah)
IU (cy)7,313,400 7,313,400
158 Oak Lea Digester LLC LU 807 68,135 68,135
159 Obsidian Fince Group, LLC LU 897 59,204 59,204
160 Old Mill Solar, LLC LU 10,498 787,326 787,326
161 OR Solar 2, LLC LU 19,729 950,719 950,719
162 OR Solar 2, LLC (ai)
AD 842 (cz)39,230 39,230
163 OR Solar 3, LLC LU 24,721 1,189,940 1,189,940
164 OR Solar 5, LLC LU 19,481 937,643 937,643
165 OR Solar 6, LLC LU 24,905 1,199,183 1,199,183
166 OR Solar 8, LLC LU 26,220 1,262,319 1,262,319
167 Orchard Windfarm 1, LLC LU 15,325 516,071 516,071
168 Orchard Windfarm 2, LLC LU 14,919 502,411 502,411
169 Orchard Windfarm 3, LLC LU 14,574 490,721 490,721
170 Orchard Windfarm 4, LLC LU 15,095 507,935 507,935
171 Oregon Environmental Industries, LLC LU 20,724 1,617,210 1,617,210
172 Oregon Solar Incentive LU 9,963 643,174 643,174
173 Oregon State University LU 211 7,184 7,184
174 Oregon Trail Windfarm, LLC LU 26,209 2,074,729 2,074,729
175 OSLH, LLC IU 23,721 1,142,323 1,142,323
176 Pacific Canyon Windfarm, LLC LU 19,285 1,530,558 1,530,558
177 Pavant Solar II LLC LU 118,178 4,029,820 4,029,820
178 Pavant Solar III LLC LU 48,263 2,548,308 2,548,308
179 Pavant Solar LLC LU 108,767 5,032,570 (da)163,149 5,195,719
180 Pioneer Wind Park I, LLC LU 243,192 10,155,959 10,155,959
181 Pioneer Wind Park I, LLC (aj)
AD 3,861 (db)157,556 157,556
182 Platte River Power Authority SF 2,968 141,582 141,582
183 Portland General Electric Company (ak)
LF 12,037 (dc)148,524 148,524
184 Portland General Electric Company (al)
AD (dd)(58,276)(58,276)
185 Portland General Electric Company SF 126,555 6,566,569 (de)4,408 6,570,977
186 Power County Wind Park North, LLC LU 66,127 5,407,101 5,407,101
187 Power County Wind Park South, LLC LU 60,838 5,056,675 5,056,675
188 Powerex Corporation SF 396,595 39,497,392 39,497,392
189 Prineville Solar Energy LLC LU 96,822 1,770,871 (df)1,232,557 3,003,428
190 Prineville Solar Energy LLC (am)
AD 1,069 23,857 (dg)13,608 37,465
191 Provo City Corporation (an)
LF 6 6,867 6,867
192 Provo City Corporation (ao)
AD (93)(dh)(4,166)(4,166)
193 Public Service Company of Colorado SF 34,426 1,707,365 (di)24,975 1,732,340
194 Public Service Company of New Mexico SF 16,036 964,806 964,806
195 Public Utility District No. 1 of Chelan County SF 119,216 6,277,862 (dj)727 6,278,589
196 Public Utility District No. 1 of Douglas County SF 3 (dk)166 166
197 Public Utility District No. 1 of Snohomish County SF 34,800 2,299,875 2,299,875
198 Public Utility District No. 2 of Grant County LU 75,206 (dl)24,855 24,855
199 Public Utility District No. 2 of Grant County (ap)
AD (dm)8,036 8,036
200 Public Utility District No. 2 of Grant County SF 677,504 (dn)28,756,206 28,756,206
201 Public Utility District No. 2 of Grant County SF 26 (do)1,206 1,206
202 Puget Sound Energy, Inc.SF 262,469 14,596,474 (dp)4,851 14,601,325
203 Quichapa 1, LLC LU 3 3 1 7,913 286,712 369,539 656,251
204 Quichapa 2, LLC LU 3 3 1 7,785 284,484 363,534 648,018
205 Quichapa 3, LLC LU 3 3 1 7,751 285,505 361,968 647,473
206 Rainbow Energy Marketing Corporation SF 2,200 121,692 121,692
207 Rock River I, LLC LU 108,381 3,845,352 3,845,352
208 Roseburg Forest Products Company LU 74,187 3,240,791 3,240,791
209 Roseburg LFG Energy, LLC LU 9,483 796,041 796,041
210 Sacramento Municipal Utility District SF 3,200 203,200 203,200
211 Sage Solar I LLC LU 40,662 1,878,458 1,878,458
212 Sage Solar II LLC LU 40,325 1,856,970 1,856,970
213 Sage Solar III LLC LU 39,909 1,828,130 1,828,130
214 Salt River Project SF 37,129 2,283,767 2,283,767
215 Salt River Project (aq)
AD (dq)2 2
216 Sand Ranch Windfarm, LLC LU 24,845 1,969,981 1,969,981
217 Seattle City Light SF 35,830 1,889,679 (dr)1,698 1,891,377
218 Shell Energy North America (US), L.P.SF 333,964 23,458,298 23,458,298
219 Shiloh Warm Springs Ranch, LLC LU 408 25,949 25,949
220 (c)
Sierra Pacific Power Company SF 452 3,107 (ds)20,519 23,626
221 Sigurd Solar LLC LU 178,716 4,813,163 (dt)761,339 5,574,502
222 Simplot Phosphates LLC LU 49 882 882
223 Solwatt, LLC LU 847 54,047 54,047
224 Southern California Edison Company SF 2,400 81,200 81,200
225 Spanish Fork Wind Park 2, LLC LU 45,396 2,751,149 2,751,149
226 Sprague Hydro LLC LU 822 22,505 128,962 151,467
227 St. Anthony Hydro, LLC LU 5,492 386,850 386,850
228 St. Anthony Hydro, LLC (ar)
AD 413 (du)25,616 25,616
229 Stahlbush Island Farms, Inc.IU 1,540 55,268 55,268
230 SunE DB18, LLC LU 2 2 1 5,469 347,748 299,175 646,923
231 SunE DB24, LLC LU 3 3 1 7,058 253,435 329,613 583,048
232 SunE Solar XVII Project1, LLC LU 2 7 3 6,217 360,732 340,092 700,824
233 SunE Solar XVII Project2, LLC LU 3 7 3 6,028 384,661 329,733 714,394
234 SunE Solar XVII Project3, LLC LU 3 7 3 7,103 258,581 331,690 590,271
235 Sunny Bar Ranch LLLP LU 1,543 88,311 88,311
236 Sunnyside Cogeneration Associates LU 55 53 51 400,956 11,574,588 20,087,636 31,662,224
237 Surprise Valley Electrification Corp (as)
AD (dv)(28,892)(28,892)
238 Swalley Irrigation District LU 2,133 171,867 171,867
239 Sweetwater Solar LLC LU 179,694 7,686,198 7,686,198
240 Tacoma Power SF 75,150 5,335,471 (dw)45,000 5,380,471
241 Tacoma Power SF 15 (dx)734 734
242 Tata Chemicals (Soda Ash) Partners LU 1,487 20,772 20,772
243 Tenaska Power Services Co.SF 33,057 2,396,563 2,396,563
244 Tesoro Refining & Marketing Company, LLC LU 1,598 24,978 24,978
245 Thayn Hydro LLC LU 4,229 222,983 222,983
246 The Energy Authority, Inc.SF 101,829 6,796,753 6,796,753
247 Three Buttes Windpower, LLC LU 301,476 19,230,724 19,230,724
248 Three Peaks Power, LLC LU 225,081 9,531,646 9,531,646
249 Three Sisters Irrigation District LU 1,862 100,438 100,438
250 Threemile Canyon Wind I, LLC LU 22,869 1,845,660 1,845,660
251 TMF Biofuels, LLC LU 36,313 2,896,205 2,896,205
252 Tooele Army Depot LU 2,482 68,577 68,577
253 Top of the World Wind Energy LLC LU 392,340 25,894,240 (dy)12,350,384 38,244,624
254 Top of the World Wind Energy LLC (at)
AD (dz)94,101 94,101
255 TransAlta Energy Marketing (U.S.) Inc.SF 239,715 19,702,189 19,702,189
256 TransCada Energy Sales Ltd.SF 5,900 609,200 609,200
257 Tri-State Generation and Transmission Association, Inc.SF 5,238 258,313 258,313
258 Tucson Electric Power Company SF 49,143 2,733,483 2,733,483
259 Tumbleweed Solar LLC LU 19,175 923,215 923,215
260 Turlock Irrigation District SF 300 22,500 22,500
261 U.S. Department of the Interior - Bureau of Land Magement LU 26 1,867 1,867
262 Uniper Global Commodities SF 1,500 171,000 171,000
263 United States Air Force at Hill Air Force Base LU 14,469 861,626 861,626
264 UNS Electric, Inc.SF 4,006 303,540 303,540
265 US Magnesium LLC LU (ea)3,699,014 3,699,014
266 Utah Associated Municipal Power Systems (au)
LF 60,816 3,097,449 3,097,449
267 Utah Associated Municipal Power Systems SF 400 16,000 16,000
268 Utah Municipal Power Agency SF 74,192 13,001,506 13,001,506
269 Utah Red Hills Renewable Park, LLC LU 209,050 12,183,125 12,183,125
270 Utah Retail Solar customers LU 100,452 8,845,435 8,845,435
271 Utah Retail Solar customers (av)
AD 139 (eb)12,630 12,630
272 Vitol Inc.SF 500 11,000 11,000
273 Wagon Trail, LLC LU 7,640 606,613 606,613
274 Ward Butte Windfarm, LLC LU 17,059 1,350,386 1,350,386
275 Weber County LU (48)(3,116)(3,116)
276 Wolverine Creek Energy, LLC LU 168,800 10,470,678 10,470,678
277 Woodline Solar, LLC IU 17,063 821,604 821,604
278 Yakima-Tieton Irrigation District LU 6,131 370,977 370,977
279 Western Area Power Administration SF 37,832 1,528,027 (ec)11,350 1,539,377
280 Western Area Power Administration (aw)
LF 10,827 251,859 251,859
281 Liquidated Damages OS (ed)(437,037)(437,037)
282 CA Greenhouse Gas Allowances Purchases (ee)7,009,270 7,009,270
283 Net Power Cost Deferrals (bg)(97,064,618)(97,064,618)
284 Netting - Bookouts (1,776,035)(ef)(61,513,064)(61,513,064)
285 Netting - Trading (eg)(1,049,308)(1,049,308)
286 System Deviation (bf)(5,565)
287 Accrual (eh)12,054,289 12,054,289
288 Power Exchanges:
289 Arizona Public Service Company EX 307 211,766 (ei)6,667,280 6,667,280
290 Avista Corporation EX 382 988
291 Bonneville Power Administration EX T- BPA 270,999 4,430 (ej)206,414 206,414
292 Bonneville Power Administration EX 237 1,469,905 1,456,908 (ek)32,745 32,745
293 California Independent System Operator Corporation EX T-12 2,543,813 6,367,060 (el)(164,973,661)(164,973,661)
294 California Independent System Operator Corporation (ax)
AD T-12 0 (em)168 168
295 California Independent System Operator Corporation EX T-11 (en)(26,191,224)(26,191,224)
296 California Independent System Operator Corporation (ay)
AD T-11 (eo)(334,126)(334,126)
297 Emerald People's Utility District EX T-6 870 (ep)(21,752)(21,752)
298 Idaho Power Company EX T-6 2,104 2,096
299 Idaho Power Company EX 708 116,053 111,632
300 Los Angeles Department of Water and Power EX OV-1 2,459 (eq)245,401 245,401
301 Los Angeles Department of Water and Power (az)
AD OV-1 346 (er)19,736 19,736
302 Milford Wind Corridor Phase I, LLC EX OV-1 1,639 (es)(162,891)(162,891)
303 Milford Wind Corridor Phase I, LLC (ba)
AD OV-1 206 (et)(13,609)(13,609)
304 Milford Wind Corridor Phase II, LLC EX OV-1 820 (eu)(82,510)(82,510)
305 Milford Wind Corridor Phase II, LLC (bb)
AD OV-1 140 (ev)(6,127)(6,127)
306 NorthWestern Corporation EX 160 11,403
307 Portland General Electric Company EX T-8 3,480
308 Public Service Company of Colorado EX 334 1,311,985 1,312,543 (ew)5,397,660 5,397,660
309 Public Service Company of Colorado (bc)
AD 334 39 (ex)2,340 2,340
310 Public Utility District No. 1 of Cowlitz County EX 442 199,060 213,182
311 Seattle City Light EX 554 377,372 360,103 (ey)890,723 890,723
312 Western Area Power Administration EX LAS-4 181,570 107,878 (ez)676,444 676,444
313 Western Area Power Administration (bd)
AD LAS-4 210 3,943 (fa)(188,617)(188,617)
314 Imbalance Energy Accrual EX T-11 153,513 (551)(fb)7,716,507 7,716,507
315 Imbalance Energy Accrual (be)
AD T-11 3,583 (fc)1,944,819 1,944,819
15 TOTAL 14,523,353 6,856,077 9,947,470 35,855,710 768,977,094 (122,483,321)682,349,483
FERC FORM NO. 1 (ED. 12-90)Page 326-327
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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
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
Under Electric Service Agreement subject to termination upon timely notification.
(k) Concept: StatisticalClassificationCode
Settlement adjustment.
(l) Concept: StatisticalClassificationCode
Bonneville Power Administration - contract termination date: Upon 30 days written notice.
(m) Concept: StatisticalClassificationCode
Bonneville Power Administration - contract termination date: Upon 30 days written notice.
(n) Concept: StatisticalClassificationCode
Settlement adjustment.
(o) Concept: StatisticalClassificationCode
City of Hurricane - contract termination date: August 31, 2022.
(p) Concept: StatisticalClassificationCode
Settlement adjustment.
(q) Concept: StatisticalClassificationCode
Settlement adjustment.
(r) Concept: StatisticalClassificationCode
Settlement adjustment.
(s) Concept: StatisticalClassificationCode
Deseret Generation & Transmission Cooperative - contract termination date: September 30, 2024.
(t) Concept: StatisticalClassificationCode
Settlement adjustment.
(u) Concept: StatisticalClassificationCode
Settlement adjustment.
(v) Concept: StatisticalClassificationCode
Settlement adjustment.
(w) Concept: StatisticalClassificationCode
Under Electric Service Agreement subject to termination upon timely notification.
(x) Concept: StatisticalClassificationCode
Flathead Electric Cooperative, Inc. - contract termination date: September 30, 2021.
(y) Concept: StatisticalClassificationCode
Under Electric Service Agreement subject to termination upon timely notification.
(z) Concept: StatisticalClassificationCode
Settlement adjustment.
(aa) Concept: StatisticalClassificationCode
Settlement adjustment.
(ab) Concept: StatisticalClassificationCode
Settlement adjustment.
(ac) Concept: StatisticalClassificationCode
Settlement adjustment.
(ad) Concept: StatisticalClassificationCode
Settlement adjustment.
(ae) Concept: StatisticalClassificationCode
Settlement adjustment.
(af) Concept: StatisticalClassificationCode
Under Electric Service Agreement subject to termination upon timely notification.
(ag) Concept: StatisticalClassificationCode
Settlement adjustment.
(ah) Concept: StatisticalClassificationCode
Nucor Corporation - contract termination date: December 31, 2031
(ai) Concept: StatisticalClassificationCode
Settlement adjustment.
(aj) Concept: StatisticalClassificationCode
Settlement adjustment.
(ak) Concept: StatisticalClassificationCode
Portland General Electric Company - contract termination date: When the Round Butte project no longer operates for power production purposes.
(al) Concept: StatisticalClassificationCode
Settlement adjustment.
(am) Concept: StatisticalClassificationCode
Settlement adjustment.
(an) Concept: StatisticalClassificationCode
Under Electric Service Agreement subject to termination upon timely notification.
(ao) Concept: StatisticalClassificationCode
Settlement adjustment.
(ap) Concept: StatisticalClassificationCode
Settlement adjustment.
(aq) Concept: StatisticalClassificationCode
Settlement adjustment.
(ar) Concept: StatisticalClassificationCode
Settlement adjustment.
(as) Concept: StatisticalClassificationCode
Settlement adjustment.
(at) Concept: StatisticalClassificationCode
Settlement adjustment.
(au) Concept: StatisticalClassificationCode
Utah Associated Municipal Power System - contract termination date: March 31, 2022.
(av) Concept: StatisticalClassificationCode
Settlement adjustment.
(aw) Concept: StatisticalClassificationCode
Western Area Power Administration - contract termination date: May 31, 2022.
(ax) Concept: StatisticalClassificationCode
Settlement adjustment.
(ay) Concept: StatisticalClassificationCode
Settlement adjustment.
(az) Concept: StatisticalClassificationCode
Settlement adjustment.
(ba) Concept: StatisticalClassificationCode
Settlement adjustment.
(bb) Concept: StatisticalClassificationCode
Settlement adjustment.
(bc) Concept: StatisticalClassificationCode
Settlement adjustment.
(bd) Concept: StatisticalClassificationCode
Settlement adjustment.
(be) Concept: StatisticalClassificationCode
Settlement adjustment.
(bf) Concept: MegawattHoursPurchasedOtherThanStorage
Adjustment for inadvertent interchange.
(bg) Concept: EnergyChargesOfPurchasedPower
Regulatory net power cost and renewable energy credit deferrals.
(bh) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bi) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(bj) Concept: OtherChargesOfPurchasedPower
Reactive supply and voltage control, per FERC Docket ER20-2528, effective September 28, 2020.
(bk) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bl) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bm) Concept: OtherChargesOfPurchasedPower
Reserve share.
(bn) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bo) Concept: OtherChargesOfPurchasedPower
Reserve share.
(bp) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bq) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(br) Concept: OtherChargesOfPurchasedPower
Non-generation agreement.
(bs) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bt) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(bu) Concept: OtherChargesOfPurchasedPower
Ancillary services.
(bv) Concept: OtherChargesOfPurchasedPower
Reserve share.
(bw) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bx) Concept: OtherChargesOfPurchasedPower
Labor, equipment and administration fees associated with a hydro project in Idaho Falls, Idaho.
(by) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(bz) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(ca) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cb) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cc) Concept: OtherChargesOfPurchasedPower
Reimbursement to counterparty for operations and maintenance costs at a coal-fired generating facility located in Vernal, Utah.
(cd) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ce) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cf) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(cg) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ch) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(ci) Concept: OtherChargesOfPurchasedPower
Cash out fees to obtain the counterparties share of Meaningful Priority.
(cj) Concept: OtherChargesOfPurchasedPower
Reserve share.
(ck) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(cl) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cm) Concept: OtherChargesOfPurchasedPower
Reserve share.
(cn) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(co) Concept: OtherChargesOfPurchasedPower
Fixed annual payment.
(cp) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cq) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cr) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(cs) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ct) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(cu) Concept: OtherChargesOfPurchasedPower
Compensation for interruptible service and operating reserves.
(cv) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cw) Concept: OtherChargesOfPurchasedPower
Reserve share.
(cx) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(cy) Concept: OtherChargesOfPurchasedPower
Ancillary services.
(cz) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(da) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(db) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dc) Concept: OtherChargesOfPurchasedPower
Operations expense plus amortization of unrecovered costs of Cove Project.
(dd) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(de) Concept: OtherChargesOfPurchasedPower
Reserve share.
(df) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(dg) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dh) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(di) Concept: OtherChargesOfPurchasedPower
Reserve share.
(dj) Concept: OtherChargesOfPurchasedPower
Reserve share.
(dk) Concept: OtherChargesOfPurchasedPower
Reserve share.
(dl) Concept: OtherChargesOfPurchasedPower
Operations expense, bond interest, amortization and taxes.
(dm) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dn) Concept: OtherChargesOfPurchasedPower
2021 Meaningful Priority award to PacifiCorp of generation output from the Priest Rapids Project from Grant County, consisting of 0.92% generation output from Eugene Water & Electric Board, 1.82% generation output from Tacoma Power and 7.44% from Priest Rapids and 4.22% from Priest/Wapum Development.
(do) Concept: OtherChargesOfPurchasedPower
Reserve share.
(dp) Concept: OtherChargesOfPurchasedPower
Reserve share.
(dq) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dr) Concept: OtherChargesOfPurchasedPower
Reserve share.
(ds) Concept: OtherChargesOfPurchasedPower
Reserve share.
(dt) Concept: OtherChargesOfPurchasedPower
Purchase of renewable energy credit certificates for renewable portfolio standardrequirements.
(du) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dv) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(dw) Concept: OtherChargesOfPurchasedPower
Cash out fees to obtain the counterparties share of Meaningful Priority.
(dx) Concept: OtherChargesOfPurchasedPower
Reserve share.
(dy) Concept: OtherChargesOfPurchasedPower
Non-generation agreement.
(dz) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ea) Concept: OtherChargesOfPurchasedPower
Ancillary services.
(eb) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ec) Concept: OtherChargesOfPurchasedPower
Reserve share.
(ed) Concept: OtherChargesOfPurchasedPower
Liquidated damages.
(ee) Concept: OtherChargesOfPurchasedPower
Purchases of greenhouse gas allowances for compliance with the California Air Resources Board greenhouse gas cap-and-trade program.
(ef) Concept: OtherChargesOfPurchasedPower
Reflects transactions that did not physically settle.
(eg) Concept: OtherChargesOfPurchasedPower
Reflects transactions that were categorized as trading activities.
(eh) 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.
(ei) Concept: OtherChargesOfPurchasedPower
Exchange energy credit.
(ej) Concept: OtherChargesOfPurchasedPower
Storage and exchange energy charges.
(ek) Concept: OtherChargesOfPurchasedPower
Storage and exchange energy charges.
(el) Concept: OtherChargesOfPurchasedPower
Energy Imbalance Market (EIM) participating resource settlements in EIM.
(em) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(en) Concept: OtherChargesOfPurchasedPower
EIM entity settlements in EIM.
(eo) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ep) Concept: OtherChargesOfPurchasedPower
Exchange energy credit.
(eq) Concept: OtherChargesOfPurchasedPower
Station service for a third-party wind project.
(er) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(es) Concept: OtherChargesOfPurchasedPower
Reimbursement for providing station service to a third-party wind project.
(et) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(eu) Concept: OtherChargesOfPurchasedPower
Reimbursement for providing station service to a third-party wind project.
(ev) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ew) Concept: OtherChargesOfPurchasedPower
Exchange energy credit.
(ex) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(ey) Concept: OtherChargesOfPurchasedPower
Exchange energy credit.
(ez) Concept: OtherChargesOfPurchasedPower
Imbalance energy settlements between PacifiCorp merchant function and third-party transmission providers.
(fa) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
(fb) Concept: OtherChargesOfPurchasedPower
Imbalance energy settlements between PacifiCorp, the transmission provider and third-party transmission customers.
(fc) Concept: OtherChargesOfPurchasedPower
Settlement adjustment.
FERC FORM NO. 1 (ED. 12-90)Page 326-327
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 anyownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c).4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation,NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract.7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.8. Report in column (i) and (j) the total megawatthours received and delivered.9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (0) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively.11. Footnote entries and provide explanations following all required data.
TRANSFER OFENERGY REVENUE FROM TRANSMISSION OF ELECTRICITYFOR OTHERS
LineNo.(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 (p)
AD SA 876
Bonneville
Power
Administration
various 1 129 129 (ep)91 91
2 Airport Solar LLC Airport Solar LLC Portland General Electric Company (q)
LFP SA 965 Trona
Substation
Red Butte/Mona
Sub 52 106,103 106,103 1,674,365 (eq)391,263 2,065,628
3 Airport Solar LLC Airport Solar LLC Portland General Electric Company (r)
AD SA 965 TronaSubstation Red Butte/MonaSub 52 4,723 4,723 (er)19,336 19,336
4 Arizona Electric Power Cooperative, Inc.various signatories various signatories SFP SA 1010 various various 1,160 1,160 131,788 (es)8,461 140,249
5 Avangrid Renewables, LLC various signatories various signatories NF SA 121 various various 181,844 181,844 1,932,011 (et)131,993 2,064,004
6 Avangrid Renewables, LLC various signatories various signatories (s)
AD SA 121 various various 18,634 18,634 (eu)155,470 155,470
7 Avangrid Renewables, LLC various signatories various signatories SFP SA 122 various various 56,182 56,182 773,798 (ev)52,696 826,494
8 Avangrid Renewables, LLC various signatories various signatories (t)
AD SA 122 various various 3,572 3,572 (ew)44,266 44,266
9 Avangrid Renewables, LLC Avangrid Renewables, LLC (e)
See footnote
(u)
OS SA 476
Long Hollow,
WY switching
station
Long Hollow,
WY switching
station
(ex)216,646 216,646
10 Avangrid Renewables, LLC Avangrid Renewables, LLC (f)
See footnote
(v)
AD SA 476
Long Hollow,
WY switching
station
Long Hollow,
WY switching
station
(ey)20,191 20,191
11 Avangrid Renewables, LLC Exxon Mobil (g)
Nevada Power Company
(w)
LFP SA 895 Trona
Substation
Red Butte/Mona
Sub 31 63,784 63,784 1,004,618 (ez)68,713 1,073,331
12 Avangrid Renewables, LLC Exxon Mobil Nevada Power Company (x)
AD SA 895 TronaSubstation Red Butte/MonaSub 7,222 7,222 (fa)28,866 28,866
13 Avangrid Renewables, LLC Bonneville Power Administration Oregon Direct Access FNO SA 742 PonderosaSubstation various 35 273,987 273,987 1,112,539 (fb)540,135 1,652,674
14 Avangrid Renewables, LLC Avangrid Renewables, LLC various signatories (y)
AD SA 742 PonderosaSubstation various 34 25,354 25,354 (fc)76,656 76,656
15 Avista Corporation various signatories various signatories NF SA 886 various various 4 (fd)0 4
16 Basin Electric Power Cooperative, Inc.Western Area Power Administration Powder River Energy Corporation FNO SA 505 Yellowtail Sub Sheridan
Substation 10 70,327 70,327 320,335 (fe)45,730 366,065
17 Basin Electric Power Cooperative, Inc.Western Area Power Administration Powder River Energy Corporation (z)
AD SA 505 Yellowtail Sub SheridanSubstation 11 6,447 6,447 (ff)15,225 15,225
18 Basin Electric Power Cooperative, Inc.Western Area Power Administration Powder River Energy Corporation NF SA 607 various various 33,997 33,997 313,136 (fg)21,715 334,851
19 Basin Electric Power Cooperative, Inc.Western Area Power Administration Powder River Energy Corporation (aa)
AD SA 607 various various 2,297 2,297 (fh)13,800 13,800
20 Basin Electric Power Cooperative, Inc.Western Area Power Administration Powder River Energy Corporation SFP SA 606 various various 883 883 5,536 (fi)378 5,914
21 Basin Electric Power Cooperative, Inc.Western Area Power Administration Powder River Energy Corporation (ab)
AD SA 606 various various 1,507 1,507 (fj)14,586 14,586
22 Black Hills/Colorado Electric Utility Company, L.P.various signatories various signatories NF SA 563 various various 1,186 1,186 9,947 (fk)651 10,598
23 Black Hills Corporation PacifiCorp Montana-Dakota Utilities FNO SA 347 various 45 274,591 274,591 1,455,958 (fl)99,261 1,555,219
Payment By (Company of Public Authority) (FootnoteAffiliation)Energy Received From (Company of Public Authority)(Footnote Affiliation)Energy Delivered To (Company of Public Authority)(Footnote Affiliation)Statistical Classification Ferc Rate Schedule ofTariff Number
Point of
Receipt
(Substationor OtherDesignation)
Point of
Delivery
(Substation orOtherDesignation)
Billing
Demand(MW)
Megawatt
HoursReceived
Megawatt
HoursDelivered
Demand
Charges($)
Energy
Charges($)
OtherCharges ($)
Total
Revenues($) (k+l+m)
Sheridan
Substation
24 Black Hills Corporation PacifiCorp Montana-Dakota Utilities (ac)
AD SA 347 various SheridanSubstation 46 27,663 27,663 (fm)37,371 37,371
25 Black Hills Corporation PacifiCorp Black Hills Corporation (ad)
LFP SA 67 various WyodakSubstation 52 77,629 77,629 1,674,365 (fn)114,523 1,788,888
26 Black Hills Corporation PacifiCorp Black Hills Corporation (ae)
AD SA 67 various WyodakSubstation 52 5,202 5,202 (fo)48,111 48,111
27 Black Hills Corporation various signatories various signatories NF SA 768 various various 5,131 5,131 41,638 (fp)2,673 44,311
28 Black Hills Corporation various signatories various signatories (af)
AD SA 768 various various (fq)2,636 2,636
29 Black Hills Corporation various signatories various signatories SFP SA 767 various various 16,826 16,826 3,763 (fr)240 4,003
30 Black Hills Power Marketing various signatories various signatories NF SA 43 various various 1,045 1,045 6,766 (fs)500 7,266
31 Black Hills Power Marketing various signatories various signatories (ag)
AD SA 112 various various 629 (ft)1,875 2,504
32 Black Hills Power Marketing various signatories various signatories SFP SA 714 various various 50 50 304 (fu)23 327
33 Bonneville Power Administration (b)
See footnote
(h)
See footnote
(ah)
OS RS 369 Midpoint
Substation
Summer Lake
Sub
34 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (ai)
OS RS 237 various various 356 1,127,066 1,127,066 4,235,339 (fv)4,341 4,239,680
35 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (aj)
AD RS 237 various various 360 101,492 101,492 (fw)130,968 130,968
36 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (ak)
LFP SA 656 Lost CreekHydro Plt AlveySubstation 58 186,322 186,322 1,875,288 (fx)52,507 1,927,795
37 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (al)
AD SA 656 Lost CreekHydro Plt AlveySubstation 58 13,919 13,919 (fy)49,145 49,145
38 Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative FNO SA 229
Bonneville
PowerAdministration
GazleySubstation 3 22,582 22,582 107,852 (fz)187,956 295,808
39 Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative (am)
AD SA 229
Bonneville
PowerAdministration
GazleySubstation 3 2,093 2,093 (ga)15,325 15,325
40 Bonneville Power Administration Bonneville Power Administration Benton Rural Electric Association FNO SA 539
Bonneville
PowerAdministration
TietonSubstation 1 5,568 5,568 17,072 (gb)2,693 19,765
41 Bonneville Power Administration Bonneville Power Administration Benton Rural Electric Association (an)
AD SA 539
Bonneville
PowerAdministration
TietonSubstation 1 28 28 (gc)1,674 1,674
42 Bonneville Power Administration Bonneville Power Administration Umatilla Electric Cooperative Association and Columbia Basin
Electric Cooperative, Inc FNO SA 538 McNary
Substation
Hinkle
Substation 1 1,236 1,236 9,589 (gd)1,023 10,612
43 Bonneville Power Administration Bonneville Power Administration Umatilla Electric Cooperative Association and Columbia Basin
Electric Cooperative, Inc
(ao)
AD SA 538 McNary
Substation
Hinkle
Substation 1 173 173 (ge)1,452 1,452
44 Bonneville Power Administration United States Department of Interior, Bureau of Reclamation Bonneville Power Administration (ap)
LFP SA 179 USBR GreenSprings
BonnevillePower
Administration
19 10,014 10,014 202,474 (gf)7,789 210,263
45 Bonneville Power Administration United States Department of Interior, Bureau of Reclamation Bonneville Power Administration (aq)
AD SA 179 USBR GreenSprings
BonnevillePower
Administration
19 119 119 (gg)16,077 16,077
46 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (ar)
OS RS 368 MalinSubstation MalinSubstation 554,442 554,442 (gh)232,452 232,452
47 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (as)
AD RS 368 MalinSubstation MalinSubstation 50,428 50,428 (gi)21,132 21,132
48 Bonneville Power Administration Bonneville Power Administration Yakama Power FNO SA 328 BonnevillePowerAdministration
WhiteSwan/ToppenishSubstations 6 37,817 37,817 183,554 (gj)113,557 297,111
49 Bonneville Power Administration Bonneville Power Administration Yakama Power (at)
AD SA 328 BonnevillePowerAdministration
WhiteSwan/ToppenishSubstations 4 3,554 3,554 (gk)6,246 6,246
50 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO SA 827 BonnevillePowerAdministration Neff Substation 3 673 673 1,082 (gl)304 1,386
51 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (au)
AD SA 827 BonnevillePowerAdministration Neff Substation 1 87 87 (gm)952 952
52 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO SA 746 GoshenSubstation various 206 1,365,660 1,365,660 6,676,795 (gn)1,747,785 8,424,580
53 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (av)
AD SA 746 GoshenSubstation various 327 182,830 182,830 (go)767,537 767,537
54 Bonneville Power Administration various signatories various signatories NF SA 44 various various 633,559 (gp)43,970 677,529
55 Bonneville Power Administration various signatories various signatories FNO SA 747 GoshenSubstation various 76 637,986 637,986 2,962,324 (gq)593,295 3,555,619
56 Bonneville Power Administration various signatories various signatories (aw)
AD SA 747 GoshenSubstation various 102 69,465 69,465 (gr)151,220 151,220
57 Bonneville Power Administration Bonneville Power Administration Public Utility District No. 1 of Clark County FNO SA 735 Cardwell-Merwin Chelatchie/View115kV 23 119,863 119,863 745,299 (gs)88,110 833,409
58 Bonneville Power Administration Bonneville Power Administration Public Utility District No. 1 of Clark County (ax)
AD SA 735 Cardwell-
Merwin
Chelatchie/View
115kV 28 15,248 15,248 (gt)31,980 31,980
59 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO SA 865 Goshen
Substation various 1 483 483 1,699 (gu)274 1,973
60 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (ay)
AD SA 865 GoshenSubstation various 1 55 55 (gv)504 504
61 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO SA 975 BonnevillePowerAdministration various 1 4,171 4,171 22,760 (gw)2,761 25,521
62 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration (az)
AD SA 975 BonnevillePowerAdministration various 1 (gx)(50)(50)
63 Brookfield Renewable Trading and Marketing LP various signatories various signatories NF SA 941 various various 21,943 21,943 122,002 (gy)8,898 130,900
64 Brookfield Renewable Trading and Marketing LP various signatories various signatories (ba)
AD SA 941 various various 3,696 3,696 (gz)20,007 20,007
65 Brookfield Renewable Trading and Marketing LP various signatories various signatories SFP SA 940 various various 12,138 12,138 87,499 (ha)5,769 93,268
66 Calpine Energy Solutions, LLC Bonneville Power Administration Oregon Direct Access FNO SA 299 BonnevillePowerAdministration various 19 115,541 115,541 538,521 (hb)96,446 634,967
67 Calpine Energy Solutions, LLC Bonneville Power Administration Oregon Direct Access (bb)
AD SA 299 BonnevillePowerAdministration various 17 8,167 8,167 (hc)9,851 9,851
68 City of Roseville City of Roseville City of Roseville (bc)
LFP SA 881 Malin 500Substation Round MountainSub 50 1,609,305 (hd)36,575 1,645,880
69 City of Roseville City of Roseville City of Roseville (bd)
AD SA 881 Malin 500Substation Round MountainSub 50 (he)43,770 43,770
70 Clatskanie People's Utility District Clatskanie People's Utility District Clatskanie People's Utility District (be)
LFP SA 899 Troutdale
Substation various 14 75,233 75,233 435,351 (hf)29,776 465,127
71 Clatskanie People's Utility District Clatskanie People's Utility District Clatskanie People's Utility District (bf)
AD SA 899 Troutdale
Substation various 6,976 6,976 (hg)8,525 8,525
72 Clatskanie People's Utility District Clatskanie People's Utility District Clatskanie People's Utility District (bg)
LFP SA 901 TroutdaleSubstation various 2 66,976 (hh)4,580 71,556
73 Clatskanie People's Utility District Clatskanie People's Utility District Clatskanie People's Utility District (bh)
AD SA 901 TroutdaleSubstation various (hi)5,858 5,858
74 ConocoPhillps Company various signatories various signatories NF SA 280 various various 588 (hj)38 626
75 CP Energy Marketing (US) Inc.various signatories various signatories NF SA 968 various various 40 40 421 (hk)31 452
76 Deseret Generation and Transmission Co-operative Deseret Generation and Transmission Co-operative Deseret Gen and Transmission Co-operative (bi)
OS RS 280 various various 142 1,114,653 1,114,653 4,577,194 (hl)1,902,943 6,480,137
77 Deseret Generation and Transmission Co-operative Deseret Generation and Transmission Co-operative Deseret Gen and Transmission Co-operative (bj)
AD RS 280 various various 122 94,571 94,571 (hm)243,263 243,263
78 Deseret Generation and Transmission Co-operative various signatories various signatories NF SA 156 various various 5,636 5,636 54,260 (hn)3,672 57,932
79 Deseret Generation and Transmission Co-operative various signatories various signatories SFP SA 159 various various 543 543 5,939 (ho)379 6,318
80 Dynasty Power Inc.various signatories various signatories NF SA 1014 various various 39,714 39,714 690,915 (hp)44,257 735,172
81 Dynasty Power Inc.various signatories various signatories SFP SA 1013 various various 19,382 19,382 453,558 (hq)29,041 482,599
82 Eagle Energy Partners I LP various signatories various signatories NF SA 569 various various 18,157 18,157 2,689,455 (hr)175,633 2,865,088
83 Eagle Energy Partners I LP various signatories various signatories (bk)
AD SA 569 various various 668 668 (hs)4,921 4,921
84 Eagle Energy Partners I LP various signatories various signatories SFP SA 570 various various 6,404 (ht)411 6,815
85 Enel Trading North America, LLC various signatories various signatories NF SA 962 various various 716 716 6,444 (hu)414 6,858
86 Energy Keepers, Inc.various signatories various signatories NF SA 814 various various 7,375 7,375 63,875 (hv)4,416 68,291
87 Energy Keepers, Inc.various signatories various signatories SFP SA 815 various various 2,022 2,022 22,046 (hw)1,451 23,497
88 Eugene Water & Electric Board NextEra Energy Resources, LLC Public Utility District No. 2 of Grant County (bl)
AD SA 780 various various (hx)(47)(47)
89 Evergreen Biopower LLC NextEra Energy Resources, LLC various signatories SA 874 various various 10 50,926 50,926 334,873 (hy)68,502 403,375
(bm)
LFP
90 Evergreen Biopower LLC NextEra Energy Resources, LLC Public Utility District No. 2 of Grant County (bn)
AD SA 874 various various 10 4,338 4,338 (hz)12,400 12,400
91 Exelon Generation Company, LLC Bonneville Power Administration Oregon Direct Access FNO SA 943 BonnevillePowerAdministration various 2 9,567 9,567 46,479 (ia)8,177 54,656
92 Exelon Generation Company, LLC Bonneville Power Administration Oregon Direct Access (bo)
AD SA 943 BonnevillePowerAdministration various 1 608 608 (ib)487 487
93 Exelon Generation Company, LLC various signatories various signatories NF SA 759 various various 827 827 126,971 (ic)1,610,140 1,737,111
94 Exelon Generation Company, LLC various signatories various signatories (bp)
AD SA 759 various various 154 154 (id)172,417 172,417
95 Exelon Generation Company, LLC various signatories various signatories SFP SA 760 various various 112 (ie)7 119
96 Fall River Rural Electric Cooperative, Inc.Marysville Hydro Partners Idaho Power Company (bq)
OS RS 322 TargheeSubstation GoshenSubstation (if)138,699 138,699
97 Fall River Rural Electric Cooperative, Inc.Marysville Hydro Partners Idaho Power Company (br)
AD RS 322 TargheeSubstation GoshenSubstation (ig)12,609 12,609
98 Falls Creek H.P. Limited Partnership Lakeview Airport 10 Portland General Electric Company (bs)
LFP SA 868
Falls Creek
H.P. LimitedPartnership
BonnevillePower Adm 5 12,252 12,252 135,075 (ih)23,813 158,888
99 Falls Creek H.P. Limited Partnership Lakeview Airport 10 Portland General Electric Company (bt)
AD SA 868
Falls Creek
H.P. LimitedPartnership
BonnevillePower Adm 3 2,300 2,300 (ii)7,819 7,819
100 Garrett Solar LLC Garrett Solar LLC Portland General Electric Company (bu)
LFP SA 966 Wallula
Substation Wala-MIDC path 10 25,483 25,483 334,873 (ij)81,956 416,829
101 Garrett Solar LLC Garrett Solar LLC Portland General Electric Company (bv)
AD SA 966 Wallula
Substation Wala-MIDC path 10 1,137 1,137 (ik)15,627 15,627
102 Guzman Energy LLC various signatories various signatories NF SA 786 various various 101,906 101,906 1,483,036 (il)97,495 1,580,531
103 Guzman Energy LLC various signatories various signatories (bw)
AD SA 786 various various 2,121 2,121 (im)16,493 16,493
104 Guzman Energy LLC various signatories various signatories SFP SA 785 various various 24,144 24,144 861,558 (in)56,803 918,361
105 Idaho Power Company Exxon Mobil Nevada Power Company (bx)
LFP SA 212 TronaSubstation Red Butte/MonaSub 52 35,785 35,785 809,440 (io)51,975 861,415
106 Idaho Power Company Exxon Mobil Nevada Power Company (by)
AD SA 212 TronaSubstation Red Butte/MonaSub (ip)(37,104)(37,104)
107 Idaho Power Company various signatories various signatories SFP SA 726 various various 585 585 3,829 (iq)245 4,074
108 Idaho Power Company various signatories various signatories NF SA 725 various various 141,090 141,090 1,779,857 (ir)114,478 1,894,335
109 Imperial Irrigation District various signatories various signatories NF SA 1006 various various 7,546 7,546 785,892 (is)51,865 837,757
110 Macquarie Energy LLC various signatories various signatories NF SA 755 various various 60,049 60,049 876,221 (it)58,009 934,230
111 Macquarie Energy LLC various signatories various signatories (bz)
AD SA 755 various various 112 112 (iu)926 926
112 Macquarie Energy LLC various signatories various signatories SFP SA 754 various various 11,460 11,460 179,986 (iv)11,607 191,593
113 MAG Energy Solutions, Inc.various signatories various signatories NF SA 903 various various 19 19 57,836 (iw)3,793 61,629
114 MAG Energy Solutions, Inc.various signatories various signatories SFP SA 902 various various 105 105 4,275 (ix)317 4,592
115 Mercuria Energy America LLC various signatories various signatories NF SA 998 various various 164,142 164,142 2,581,549 (iy)167,829 2,749,378
116 Mercuria Energy America LLC various signatories various signatories SFP SA 997 various various 134,065 134,065 967,603 (iz)62,057 1,029,660
117 Moon Lake Electric Association Inc.Moon Lake Electric Association Moon Lake Electric Association (ca)
OS RS 302 Duchesne Duchesne 17,833 17,833 (ja)18,722 18,722
118 Moon Lake Electric Association Inc.Moon Lake Electric Association Moon Lake Electric Association (cb)
AD RS 302 Duchesne Duchesne 1,498 1,498 (jb)1,702 1,702
119 Morgan Stanley Capital Group, Inc.various signatories various signatories NF SA 157 various various 429,674 429,674 10,924,747 (jc)733,624 11,658,371
120 Morgan Stanley Capital Group, Inc.various signatories various signatories (cc)
AD SA 157 various various 557 557 (jd)3,695 3,695
121 Morgan Stanley Capital Group, Inc.various signatories various signatories SFP SA 160 various various 18,701 18,701 148,414 (je)9,655 158,069
122 Navajo Tribal Utility Authority Navajo Tribal Utility Authority Navajo Tribal Utility Authority FNO SA 894 Four Corners Pinto-FourCorners 2 13,829 13,829 67,512 (jf)11,948 79,460
123 Navajo Tribal Utility Authority Navajo Tribal Utility Authority Navajo Tribal Utility Authority (cd)
AD SA 894 Four Corners Pinto-Four
Corners 1 1,717 1,717 (jg)4,146 4,146
124 Nevada Power Company various signatories various signatories NF SA 455 various various 3,532 3,532 25,544 (jh)1,639 27,183
125 Nevada Power Company various signatories various signatories SFP SA 454 various various 13,918 13,918 244,660 (ji)15,711 260,371
126 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 94 402,870 402,870 3,007,663 (jj)893,906 3,901,569
127 NextEra Energy Resources, LLC NextEra Energy Resources, LLC Public Utility District No. 2 of Grant County (cf)
AD SA 733 WallulaSubstation Wala-MIDC path 103 22,265 22,265 (jk)171,223 171,223
128 NextEra Energy Resources, LLC various signatories various signatories NF SA 236 various various 5,187 (jl)10,588 15,775
129 Obsidian Renewables Lakeview Airport 10 Portland General Electric Company (cg)
LFP SA 836 various various 10 (jm)(189)(189)
130 Obsidian Renewables NextEra Energy Resources, LLC Public Utility District No. 2 of Grant County (ch)
AD SA 880 Wallula
Substation various (jn)(38)(38)
131 Pacific Gas & Electric Company various signatories various signatories NF SA 338 various various 2,544 2,544 13,802 (jo)1,005 14,807
132 Portland General Electric Company various signatories various signatories NF SA 8 various various 13,464 13,464 498,484 (jp)31,997 530,481
133 Portland General Electric Company various signatories various signatories SFP SA 248 various various 8,921 8,921 147,658 (jq)9,444 157,102
134 Powerex Corporation Bonneville Power Administration California Independent System Operator Corporation (ci)
LFP SA 169 BonnevillePowerAdministration
CRAG View
Substation 83 499,047 499,047 2,678,984 (jr)183,234 2,862,218
135 Powerex Corporation Bonneville Power Administration California Independent System Operator Corporation (cj)
AD SA 169 BonnevillePowerAdministration
CRAG View
Substation 83 48,826 48,826 (js)76,978 76,978
136 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (ck)
LFP SA 1016 Borah Red Butte/MonaSub 104 1,618,878 (jt)103,948 1,722,826
137 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cl)
LFP SA 1017 Borah Red Butte/MonaSub 104 1,618,878 (ju)103,948 1,722,826
138 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cm)
LFP SA 700 Malin 500
Substation
Round Mountain
Sub 100 3,218,608 (jv)73,150 3,291,758
139 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cn)
AD SA 700 Malin 500
Substation
Round Mountain
Sub 100 (jw)87,540 87,540
140 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (co)
LFP SA 701 Malin 500Substation Round MountainSub 100 3,218,608 (jx)73,150 3,291,758
141 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cp)
AD SA 701 Malin 500Substation Round MountainSub 100 (jy)87,540 87,540
142 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cq)
LFP SA 702 Malin 500Substation Round MountainSub 100 3,218,608 (jz)73,150 3,291,758
143 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cr)
AD SA 702 Malin 500
Substation
Round Mountain
Sub 100 (ka)87,540 87,540
144 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cs)
LFP SA 748 Malin 500
Substation
Round Mountain
Sub 50 1,609,305 (kb)36,575 1,645,880
145 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (ct)
AD SA 748 Malin 500Substation Round MountainSub 50 (kc)43,770 43,770
146 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cu)
LFP SA 749 Malin 500Substation Round MountainSub 150 4,827,913 (kd)109,725 4,937,638
147 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cv)
AD SA 749 Malin 500Substation Round MountainSub 150 (ke)131,310 131,310
148 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cw)
LFP SA 995 Malin 500
Substation
Round Mountain
Sub 100 3,218,608 (kf)73,150 3,291,758
149 Powerex Corporation Powerex Corporation California Independent System Operator Corporation (cx)
LFP SA 996 Malin 500
Substation
Round Mountain
Sub 100 3,218,608 (kg)73,150 3,291,758
150 Powerex Corporation various signatories various signatories NF SA 47 various various 299,468 299,468 1,969,800 (kh)130,066 2,099,866
151 Powerex Corporation various signatories various signatories (cy)
AD SA 47 various various 3,445 3,445 (ki)2,681 2,681
152 Powerex Corporation various signatories various signatories SFP SA 151 various various 197,766 197,766 2,282,733 (kj)147,351 2,430,084
153 Public Utility District No. 1 of Cowlitz County PUD No. 1 of Cowlitz County Bonneville Power Administration (cz)
OS RS 234 Swift Unit No.
2
Woodland
Substation (kk)195,608 195,608
154 Public Utility District No. 1 of Cowlitz County PUD No. 1 of Cowlitz County Bonneville Power Administration (da)
AD RS 234 Swift Unit No.2 WoodlandSubstation (kl)15,467 15,467
155 Rainbow Energy Marketing Corporation various signatories various signatories NF SA 316 various various 41,143 41,143 423,603 (km)29,070 452,673
156 Rainbow Energy Marketing Corporation various signatories various signatories (db)
AD SA 316 various various 2,796 2,796 (kn)20,749 20,749
157 Rainbow Energy Marketing Corporation various signatories various signatories SFP SA 261 various various 86,788 (ko)6,267 93,055
158 Rainbow Energy Marketing Corporation various signatories various signatories (dc)
AD SA 261 various various (kp)553 553
159 Sacramento Municipal Utility District Sacramento Municipal Utility District Sacramento Municipal Utility District (dd)
LFP SA 863 MalinSubstation MalinSubstation 20 113,587 113,587 636,275 (kq)43,518 679,793
160 Sacramento Municipal Utility District Sacramento Municipal Utility District Sacramento Municipal Utility District SA 863 20 11,305 11,305 (kr)18,282 18,282
(de)
AD Malin
Substation
Malin
Substation
161 Salt River Project Agricultural Improvement and Power District Salt River Project Agricultural Improvement and Power District Salt River Project Agricultural Improvement and Power District (df)
LFP SA 809 Enel CoveFort Red ButteSubstation 26 133,707 133,707 837,197 (ks)57,263 894,460
162 Salt River Project Agricultural Improvement and Power District Salt River Project Agricultural Improvement and Power District Salt River Project Agricultural Improvement and Power District (dg)
AD SA 809 Enel CoveFort Red ButteSubstation 26 9,062 9,062 (kt)24,056 24,056
163 Salt River Project Agricultural Improvement and Power District various signatories various signatories SFP SA 556 various various 325 325 3,887 (ku)249 4,136
164 Shell Energy North America (US), L.P.NextEra Energy Resources, LLC Public Utility District No. 2 of Grant County (dh)
LFP SA 791 Wallula
Substation Wala-MIDC path 30,548 30,548 837,197 (kv)57,263 894,460
165 Shell Energy North America (US), L.P.NextEra Energy Resources, LLC Public Utility District No. 2 of Grant County (di)
AD SA 791 WallulaSubstation Wala-MIDC path 2,563 2,563 (kw)23,631 23,631
166 Shell Energy North America (US), L.P.various signatories various signatories NF SA 23 various various 492,667 492,667 2,949,205 (kx)197,012 3,146,217
167 Shell Energy North America (US), L.P.various signatories various signatories (dj)
AD SA 23 various various 20,339 20,339 (ky)63,643 63,643
168 Shell Energy North America (US), L.P.various signatories various signatories SFP SA 162 various various 17,031 17,031 84,390 (kz)5,605 89,995
169 Shell Energy North America (US), L.P.various signatories various signatories (dk)
AD SA 162 various various 404 404 (la)4,486 4,486
170 (a)
Sierra Pacific Power Company
(c)
See footnote
(i)
See footnote
(dl)
OS RS 674 SigurdSubstation Utah-NevadaBorder (lb)33,147 33,147
171 Sierra Pacific Power Company (d)
See footnote
(j)
See footnote
(dm)
AD RS 674 Sigurd
Substation
Utah-Nevada
Border (lc)3,013 3,013
172 Southern California Edison Company various signatories various signatories NF SA 642 various various 274,883 274,883 2,557,444 (ld)1,047,760 3,605,204
173 Southern California Edison Company various signatories various signatories (dn)
AD SA 642 various various 19,848 19,848 (le)273,694 273,694
174 Southern California Edison Company various signatories various signatories SFP SA 643 various various 1,793 (lf)115 1,908
175 Southern California Edison Company various signatories various signatories (do)
AD SA 643 various various (lg)8 8
176 Southern California Public Power Authority Powerex Corporation (k)
Southern California Public Power Authority NF SA 629 TietonSubstation various 38 38 (lh)64,450 64,450
177 State of South Dakota Western Area Power Administration Black Hills Corporation (dp)
LFP SA 779 Yellowtail Sub WyodakSubstation 4 17,784 17,784 133,949 (li)9,163 143,112
178 State of South Dakota Western Area Power Administration Black Hills Corporation (dq)
AD SA 779 Yellowtail Sub WyodakSubstation 4 1,671 1,671 (lj)3,848 3,848
179 TEC Energy Inc.various signatories various signatories NF SA 1001 various various 276 276 7,071 (lk)463 7,534
180 Tenaska Power Services Co.various signatories various signatories NF SA 125 various various 30,914 30,914 209,551 (ll)128,259 337,810
181 Tenaska Power Services Co.various signatories various signatories (dr)
AD SA 125 various various 6,546 6,546 (lm)54,154 54,154
182 Tenaska Power Services Co.various signatories various signatories SFP SA 126 various various 104,264 104,264 674,820 (ln)43,235 718,055
183 The Energy Authority, Inc.various signatories various signatories NF SA 310 various various 55,133 55,133 500,714 (lo)33,076 533,790
184 The Energy Authority, Inc.various signatories various signatories (ds)
AD SA 310 various various 338 338 (lp)1,384 1,384
185 The Energy Authority, Inc.various signatories various signatories SFP SA 311 various various 1,560 1,560 14,595 (lq)931 15,526
186 The Energy Authority, Inc.various signatories various signatories (dt)
AD SA 311 various various (lr)3,515 3,515
187 Thermo No. 1 BE-01, LLC Thermo Geothermal Project various signatories (du)
LFP SA 568 South MilfordSub MonaSubstation 11 48,513 48,513 368,377 (ls)74,756 443,133
188 Thermo No. 1 BE-01, LLC Thermo Geothermal Project various signatories (dv)
AD SA 568 South MilfordSub MonaSubstation 11 5,981 5,981 (lt)14,048 14,048
189 TransAlta Energy Marketing (U.S.) Inc.various signatories various signatories NF SA 127 various various 68,832 68,832 781,748 (lu)53,535 835,283
190 TransAlta Energy Marketing (U.S.) Inc.various signatories various signatories (dw)
AD SA 127 various various 3,318 3,318 (lv)19,807 19,807
191 TransAlta Energy Marketing (U.S.) Inc.various signatories various signatories SFP SA 128 various various 5,186 5,186 43,700 (lw)2,833 46,533
192 TransAlta Energy Marketing (U.S.) Inc.various signatories various signatories (dx)
AD SA 128 various various 20 20 (lx)169 169
193 Tri-State Generation and Transmission Association, Inc various signatories Tri-State Generation and Transmission Association, Inc FNO SA 628 Dave
Johnston Sub
Thermopolis
Sub 17 118,049 118,049 567,431 (ly)93,142 660,573
194 Tri-State Generation and Transmission Association, Inc various signatories Tri-State Generation and Transmission Association, Inc (dy)
AD SA 628 Dave
Johnston Sub
Thermopolis
Sub 17 13,011 13,011 (lz)14,291 14,291
195 Tri-State Generation and Transmission Association, Inc various signatories various signatories NF SA 33 various various 12 12 149 (ma)9 158
196 Uniper Global Commodoties various signatories various signatories NF SA 992 various various 150 150 2,337 (mb)149 2,486
197 United States Department of Interior, Bureau of Reclamation Bonneville Power Administration United States Department of Interior, Bureau of Reclamation FNO SA 506 Burbank Pumps 1 2,466 2,466 10,547 (mc)12,268 22,815
Walla Walla
Sub
198 United States Department of Interior, Bureau of Reclamation Bonneville Power Administration United States Department of Interior, Bureau of Reclamation (dz)
AD SA 506 Walla Walla
Sub Burbank Pumps 1 5 5 (md)(465)(465)
199 United States Department of Interior, Bureau of Reclamation Western Area Power Administration Weber Basin Water Conservancy District (ea)
OS RS 286 various various 40,394 40,394 (me)40,395 40,395
200 United States Department of Interior, Bureau of Reclamation Western Area Power Administration Weber Basin Water Conservancy District (eb)
AD RS 286 various various 1,193 1,193 (mf)1,193 1,193
201 United States Department of Interior, Bureau of Reclamation Bonneville Power Administration Crooked River Irrigation District (ec)
OS RS 67 RedmondSubstation Crooked RiverPumps 11,787 11,787 10,972 10,972
202 Utah Associated Municipal Power Systems Utah Associated Municipal Power Systems Utah Associated Municipal Power Systems (ed)
OS RS 297 various various 559 3,199,788 3,199,788 18,147,969 (mg)3,308,462 21,456,431
203 Utah Associated Municipal Power Systems Utah Associated Municipal Power Systems Utah Associated Municipal Power Systems (ee)
AD RS 297 various various 453 272,146 272,146 (mh)492,360 492,360
204 Utah Associated Municipal Power Systems various signatories various signatories NF SA 009 various various 6,489 (mi)417 6,906
205 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency (ef)
OS RS 637 various various 88 628,404 628,404 2,908,193 (mj)405,076 3,313,269
206 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency (eg)
AD RS 637 various various 48 49,785 49,785 (mk)(308,976)(308,976)
207 Utah Municipal Power Agency various signatories various signatories NF SA 20 various various 39,466 39,466 189,641 (ml)12,211 201,852
208 Utah Municipal Power Agency various signatories various signatories SFP SA 20 various various 4 (mm)0 4
209 Vitol, Inc various signatories various signatories NF SA 1027 various various 49 49 308 (mn)20 328
210 Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric Company (eh)
OS RS 591 Pelton
Reregulating
Round Butte
Sub 51,676 51,676 (mo)109,725 109,725
211 Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric Company (ei)
AD RS 591 PeltonReregulating Round ButteSub 6,476 6,476 9,975 9,975
212 Western Area Power Administration Western Area Power Administration (l)
See footnote
(ej)
OS RS 262 various various 330 1,551,743 1,458,636 2,302,477 (mp)550,000 2,852,477
213 Western Area Power Administration Western Area Power Administration (m)
See footnote
(ek)
AD RS 262 various various 330 161,400 151,716 (mq)275,797 275,797
214 Western Area Power Administration Western Area Power Administration (n)
See footnote
(el)
OS RS 263 various various 43,865 40,991 (mr)33,489 33,489
215 Western Area Power Administration Western Area Power Administration (o)
See footnote
(em)
AD RS 263 various various 4,111 3,863 (ms)4,047 4,047
216 Western Area Power Administration Western Area Power Administration various signatories (en)
OS RS 684 DaveJohnston Sub various
217 Western Area Power Administration Western Area Power Administration Western Area Power Administration FNO SA 175 WyomingDistribution WyomingDistribution 3 11,623 11,623 48,553 (mt)46,573 95,126
218 Western Area Power Administration Western Area Power Administration Colorado River StorageProject Western Area Power Administration (eo)
AD SA 175 various WyomingDistribution 1 4 4 (mu)(2,381)(2,381)
219 Western Area Power Administration Colorado River Storage
Project
Western Area Power Administration Colorado River Storage
Project various signatories NF SA 132 various various 67 67 16,298 (mv)1,044 17,342
220 Western Area Power Administration Colorado Missouri Western Area Power Administration Colorado River Storage
Project various signatories NF SA 724 various various 1,881 1,881 1,587 (mw)101 1,688
221 Accrual 119,846 121,775 (mx)4,462,024 4,462,024
35 TOTAL 6,354 17,968,595 17,864,611 91,502,704 42,582,161 27,743,144 161,828,009
FERC FORM NO. 1 (ED. 12-90)Page 328-330
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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
Capacity exchanged and operated by each transmission provider with no receipt or delivery of energy.
(c) Concept: TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName
Operation, maintenance or facility lease services with no receipt or delivery of energy.
(d) Concept: TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName
Operation, maintenance or facility lease services with no receipt or delivery of energy.
(e) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Avangrid Renewables, LLC and Utah Associated Municipal Power Systems
(f) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Avangrid Renewables, LLC and Utah Associated Municipal Power Systems
(g) 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.
(h) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Capacity exchanged and operated by each transmission provider with no receipt or delivery of energy.
(i) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Operation, maintenance or facility lease services with no receipt or delivery of energy.
(j) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Operation, maintenance or facility lease services with no receipt or delivery of energy.
(k) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
(l) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Various Western Area Power Administration customers in PacifiCorp's control area.
(m) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Various Western Area Power Administration customers in PacifiCorp's control area.
(n) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Various Western Area Power Administration customers in PacifiCorp's control area.
(o) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Various Western Area Power Administration customers in PacifiCorp's control area.
(p) 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.
(q) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 965) terminating on December 31, 2024.
(r) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 965) terminating on December 31, 2024.
(s) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(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
Ancillary services under the Open Access Transmission Tariff (1st Revised Service Agreement 476) in effect until superseded.
(v) Concept: StatisticalClassificationCode
Ancillary services under the Open Access Transmission Tariff (1st Revised Service Agreement 476) in effect until superseded.
(w) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 895) terminating on April 30, 2024.
(x) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 895) terminating on April 30, 2024.
(y) 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.
(z) 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.
(aa) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ab) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ac) Concept: StatisticalClassificationCode
Network transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 347) terminating on December 31, 2023.
(ad) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 67) terminating on December 31, 2023.
(ae) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 67) terminating on December 31, 2023.
(af) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ag) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ah) 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 No. 1.
(ai) 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.
(aj) 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.
(ak) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 656) terminating on August 31, 2030.
(al) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 656) terminating on August 31, 2030.
(am) 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.
(an) 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.
(ao) Concept: StatisticalClassificationCode
Network transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 538) terminating on September 30, 2028.
(ap) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (5th Revised Service Agreement 179) terminating on September 30, 2025.
(aq) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (5th Revised Service Agreement 179) terminating on September 30, 2025.
(ar) 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.
(as) 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.
(at) 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.
(au) Concept: StatisticalClassificationCode
Network transmission service under the Open Access Transmission Tariff (2nd Revised Service Agreement 827) terminating on September 30, 2028.
(av) 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.
(aw) 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.
(ax) Concept: StatisticalClassificationCode
Network transmission service under the Open Access Transmission Tariff (2nd Revised Service Agreement 735) terminating on September 30, 2028.
(ay) 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.
(az) 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.
(ba) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bb) Concept: StatisticalClassificationCode
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.
(bc) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 881) terminating on February 28, 2023.
(bd) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 881) terminating on February 28, 2023.
(be) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 899) terminating on September 30, 2023.
(bf) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 899) terminating on September 30, 2023.
(bg) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 901) terminating on September 30, 2023.
(bh) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 901) terminating on September 30, 2023.
(bi) 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.
(bj) 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.
(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
Transmission resale service under the Open Access Transmission Tariff (Service Agreement 780). Termination upon mutual consent.
(bm) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 874) terminating on December 31, 2032.
(bn) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 874) terminating on December 31, 2032.
(bo) 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.
(bp) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(bq) 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.
(br) 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.
(bs) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 868) terminating on December 31, 2034.
(bt) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 868) terminating on December 31, 2034.
(bu) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 966) terminating on November 30, 2024.
(bv) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 966) terminating on November 30, 2024.
(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
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 212) terminating on May 31, 2024.
(by) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 212) terminating on May 31, 2024.
(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
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 836) terminating on September 30, 2024.
(ch) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 880) terminating on September 30, 2024.
(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 1017) terminating on June 30, 2024.
(cm) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 700) terminating on March 31, 2022.
(cn) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 700) terminating on March 31, 2022.
(co) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 701) terminating on March 31, 2022.
(cp) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 701) terminating on March 31, 2022.
(cq) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 702) terminating on March 31, 2022.
(cr) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 702) terminating on March 31, 2022.
(cs) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 748) terminating on December 31, 2023.
(ct) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 748) terminating on December 31, 2023.
(cu) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 749) terminating on December 31, 2023.
(cv) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 749) terminating on December 31, 2023.
(cw) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 995) terminating on December 31, 2025.
(cx) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 996) terminating on December 31, 2025.
(cy) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(cz) 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.
(da) 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.
(db) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dc) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dd) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 863) terminating on June 30, 2022.
(de) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 863) terminating on June 30, 2022.
(df) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 809) terminating on October 31, 2025.
(dg) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 809) terminating on October 31, 2025.
(dh) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 791) terminating upon written notification.
(di) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 791) terminating upon written notification.
(dj) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dk) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dl) Concept: StatisticalClassificationCode
Legacy contract (Rate Schedule 674) executed between PacifiCorp and Sierra Pacific Power Company for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Terminating in September 2022.
(dm) Concept: StatisticalClassificationCode
Legacy contract (Rate Schedule 674) executed between PacifiCorp and Sierra Pacific Power Company for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Terminating in September 2022.
(dn) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(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
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 779) terminating on August 31, 2024.
(dq) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 779) terminating on August 31, 2024.
(dr) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(ds) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dt) Concept: StatisticalClassificationCode
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(du) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 568) terminating on April 30, 2029.
(dv) Concept: StatisticalClassificationCode
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 568) terminating on April 30, 2029.
(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
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.
(dy) Concept: StatisticalClassificationCode
Network transmission service under the Open Access Transmission Tariff (10th Revised Service Agreement 628) terminating on June 30, 2031.
(dz) Concept: StatisticalClassificationCode
Network transmission service and distribution delivery service under the Open Access Transmission Tariff (2nd Revised Service Agreement 506) terminating upon written notification.
(ea) 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.
(eb) 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.
(ec) 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.
(ed) 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.
(ee) 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.
(ef) 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.
(eg) 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.
(eh) 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.
(ei) 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.
(ej) 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.
(ek) 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.
(el) 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.
(em) 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.
(en) Concept: StatisticalClassificationCode
Legacy contract (Rate Schedule 684) executed between PacifiCorp and Western Area Power Administration concerning the exchange of transmission services over agreed-upon facilities. The contract is subject to terminate upon the earlier of five years after written notice or June 30, 2042. See also page 332, Transmission of electricity by others in this Form No. 1.
(eo) Concept: StatisticalClassificationCode
Evergreen network transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 175).
(ep) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(eq) 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.
(er) 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.
(es) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(et) 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.
(eu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(ev) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ew) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(ex) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(ey) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(ez) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fa) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(fb) 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.
(fc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(fd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fe) 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.
(ff) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(fg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(fi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(fk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(fn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(fp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(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
Prior period refunds/surcharge for transmission and ancillary services.
(fu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(fv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
(fw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(fx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Reactive supply and voltage control service.
(fy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(fz) 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.
(ga) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(gb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(gc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(gd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(ge) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(gf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Reactive supply and voltage control service.
(gg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(gh) 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.
(gi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(gj) 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.
(gk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(gl) 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.
(gm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(gn) 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.
(go) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(gp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(gq) 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.
(gr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(gs) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(gt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(gu) 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.
(gv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(gw) 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.
(gx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(gy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(gz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(ha) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(hc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(hd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(he) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(hf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(hh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(hj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(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 refunds and/or surcharge.
(hn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ho) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(hs) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(ht) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(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 refunds and/or surcharge.
(hy) 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.
(hz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(ia) 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.
(ib) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(ic) 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.
(id) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(ie) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(if) 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.
(ig) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(ih) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ii) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ij) 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.
(ik) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(il) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(im) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(in) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(io) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ip) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(iq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ir) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(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
Prior period refunds/surcharge for transmission and ancillary services.
(iv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(iw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ix) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(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
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.
(jb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(jc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(je) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jf) 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.
(jg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(jh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ji) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jj) 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.
(jk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(jl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jm) 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.
(jn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(jo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service. Generation regulation and frequency response service.
(jp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(jq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service. Generation regulation and frequency response service.
(jr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(js) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(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.
(jw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(jx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(jy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(jz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(ka) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(kb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(kc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(kd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(ke) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(kf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(kg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service.
(kh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ki) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(kj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kk) 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.
(kl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(km) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(ko) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(kq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(ks) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(ku) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(kw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(kx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service. Generation regulation and frequency response service.
(ky) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(kz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Transmission resale - purchase of point-to-point transmission. Scheduling, system control and dispatch service. Reactive supply and voltage control service. Generation regulation and
frequency response service.
(la) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(lb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
(lc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(ld) 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.
(le) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(lf) 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.
(lg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(lh) 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.
(li) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(lk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(ll) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(ln) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(lq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(ls) 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.
(lt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(lu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(lw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(lx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Prior period refunds/surcharge for transmission and ancillary services.
(ly) 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.
(lz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(ma) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mc) 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. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.
(md) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(me) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Energy consumption charge for deliveries at and below 138kV.
(mf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(mg) 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.
(mh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(mi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service. Generation regulation and frequency response service.
(mj) 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.
(mk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(ml) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mo) 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.
(mp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Fixed termination fee associated with a contract cancellation applied for the duration of this agreement.
(mq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Fixed termination fee associated with a contract cancellation applied for the duration of this agreement. Prior period adjustment.
(mr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Charges for low-voltage transmission of power and energy.
(ms) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Charges for low-voltage transmission of power and energy. Prior period adjustment.
(mt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Distribution voltage service charge. Primary delivery service. Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Annual transmission services true-up refunds and/or surcharge.
(mv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Scheduling, system control and dispatch service. Reactive supply and voltage control service.
(mx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers
Represents the difference between actual wheeling revenues for the period as reflected on the individual line items within this schedule and the accruals credited to Account 456.1, Revenues
from transmission of electricity for others, during the period.
FERC FORM NO. 1 (ED. 12-90)Page 328-330
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 – FirmNetwork Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accountingadjustments 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).
LineNo.Payment Received by (Transmission Owner Name)(a)
StatisticalClassification
(b)
FERC Rate Schedule or TariffNumber
(c)
Total Revenue by RateSchedule or Tariff
(d)
Total Revenue(e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
40 TOTAL
FERC FORM NO. 1 (REV 03-07)Page 331
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 publicauthorities 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 relatedto 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
LineNo.(a)(b)(c)(d)(e)(f)(g)(h)
1 Adams Solar Center, LLC (h)
AD (bu)22,500 22,500
2 Adams Solar Center, LLC (i)(j)
LFP (bv)(37,189)(37,189)
3 Adams Solar Center, LLC (k)
OS (bw)(9,023)(9,023)
4 Arizona Public Service Company (l)
AD (bx)2,391 2,391
5 Arizona Public Service Company NF 7,508 7,508 45,192 45,192
6 Arizona Public Service Company (m)(n)
OS 1,314,000 1,314,000 6,663,040 (by)61,683 6,724,723
7 Arizona Public Service Company SFP 456,519 456,519 7,291,453 7,291,453
8 Ashland, City of (o)
AD (bz)2,953 2,953
9 Ashland, City of FNS 2,891 2,891 25,970 25,970
10 Avista Corporation FNS 21,406 20,420 232,841 232,841
11 Avista Corporation NF 37,972 38,563 243,084 243,084
12 Avista Corporation SFP 12,480 12,644 47,996 47,996
13 Basin Electric PowerCooperative, Inc.NF 2,631 2,631 6,317 6,317
14 Basin Electric PowerCooperative, Inc.
(p)
OS (ca)1,165 1,165
15 Big Horn Rural Electric Company (q)(r)
OLF 29,990 29,990 (cb)138,144 138,144
16 Black Hills Power, Inc.(s)
AD (cc)(2,844)(2,844)
17 Black Hills Power, Inc.NF 65 65 65 65
18 Black Hills Power, Inc.(t)
OS (cd)3,099 3,099
19 Black Hills Power, Inc.SFP 3,340 3,340 22,213 22,213
20 Bonneville Power Administration (u)
AD (ce)66,409 66,409
21 Bonneville Power Administration FNS 1,475,751 1,503,399 5,050,253 5,050,253
22 Bonneville Power Administration (v)
LFP 5,497,979 5,610,642 52,974,167 52,974,167
23 Bonneville Power Administration NF 1,851,871 1,888,772 7,961,834 7,961,834
24 Bonneville Power Administration (w)
OLF 4,031,089 4,113,837 19,774,437 19,774,437
25 Bonneville Power Administration (x)(y)(z)
OS (cf)(cg)14,948,460 14,948,460
26 Bonneville Power Administration SFP 109,365 111,713 308,332 308,332
Name of Company or Public
Authority (Footnote
Affiliations)
StatisticalClassification MegaWatt Hours
Received
MegaWatt Hours
Delivered
Demand Charges
($)
Energy Charges
($)
Other
Charges ($)
Total Cost ofTransmission($)
27 California Independent System
Operator Corporation
(aa)
AD
(ch)1,281 1,281
28 California Independent SystemOperator Corporation
(ab)
OS (ci)10,946,455 10,946,455
29 California Independent SystemOperator Corporation SFP 307,641 307,641
30 Deseret Generation &Transmission Cooperative
(ac)
LFP 714,204 714,204 2,519,231 2,519,231
31 Deseret Generation &
Transmission Cooperative NF 10,042 10,042 61,654 61,654
32 Elbe Solar Center, LLC (ad)
AD (cj)112,500 112,500
33 Elbe Solar Center, LLC (ae)(af)
LFP (ck)(176,295)(176,295)
34 Elbe Solar Center, LLC (ag)
OS (cl)(44,220)(44,220)
35 El Paso Electric Company NF 9,833 9,833
36 El Paso Electric Company SFP 1 1
37 Flathead Electric Cooperative,Inc.
(ah)
OS (cm)99,603 99,603
38
(a)
Hermiston Generating Company,L.P.
(ai)
OS (cn)212,280 212,280
39 Idaho Power Company (aj)
AD (co)1,592 1,592
40 Idaho Power Company FNS 12,041 12,041
41 Idaho Power Company (ak)
LFP 4,467,600 4,467,600 15,432,498 15,432,498
42 Idaho Power Company NF 126,451 126,451 701,433 701,433
43 Idaho Power Company (al)(am)
OLF (cp)29,760 29,760
44 Idaho Power Company (an)
OS (cq)(31,789)(31,789)
45 Idaho Power Company SFP 100,504 100,504 398,387 398,387
46 Los Angeles Department ofWater and Power
(ao)
AD (cr)21,794 21,794
47 Los Angeles Department ofWater and Power NF 9,677 9,677 75,285 75,285
48 Los Angeles Department of
Water and Power
(ap)
OS (cs)6,672 6,672
49 Moon Lake Electric Association,
Inc.
(aq)
FNS 14 14 (ct)250,722 250,722
50 Morgan City Corporation (ar)
AD (cu)303 303
51 Morgan City Corporation (as)
LFP 1,419 1,419
52 (b)
Nevada Power Company
(at)
AD (cv)21,402 21,402
53 (c)
Nevada Power Company NF 72,864 72,864 390,295 390,295
54 (d)
Nevada Power Company
(au)
OS (cw)180,856 180,856
55 (e)
Nevada Power Company SFP 229,464 229,464 815,600 815,600
56 NorthWestern Corporation (av)
AD (cx)42,538 42,538
57 NorthWestern Corporation NF 10,737 10,737 60,939 60,939
58 NorthWestern Corporation (aw)
OS (cy)125,489 125,489
59 NorthWestern Corporation SFP 283,582 294,985 1,358,357 1,358,357
60 Platte River Power Authority (ax)
LFP 207,983 207,983 849,351 849,351
61 Platte River Power Authority (ay)
OS (cz)18,530 18,530
62 Portland General Electric
Company
(az)
LFP 105,120 105,120 75,360 75,360
63 Portland General Electric
Company NF 1,851 1,851 1,015 1,015
64 Portland General Electric
Company
(ba)(bb)
OLF (da)216 216
65 Portland General ElectricCompany
(bc)
OS 3,530 (db)8,276 8,276
66 Portland General ElectricCompany SFP 2,376 2,376 2,169 2,169
67 Public Service Company ofColorado
(bd)
LFP 97,786 97,786 335,405 335,405
68 Public Service Company of New
Mexico NF 212 212 1,524 1,524
69 Public Service Company of New
Mexico
(be)
OS (dc)140 140
70 Salt River Project (bf)
AD (dd)3,536 3,536
71 Salt River Project NF 2,101 2,101 12,961 12,961
72 Salt River Project (bg)
OS (de)1,869 1,869
73 (f)
Sierra Pacific Power Company NF 4,536 4,536 18,649 18,649
74 (g)
Sierra Pacific Power Company
(bh)
OS (df)2,825 2,825
75 Surprise Valley ElectrificationCorp.
(bi)(bj)
OLF (dg)7,840 7,840
76 Tri-State Generation andTransmission Association, Inc.
(bk)
LFP 420,480 420,480 1,130,447 1,130,447
77 Tri-State Generation andTransmission Association, Inc.NF 1,783 1,783 24,775 24,775
78 Tri-State Generation and
Transmission Association, Inc.
(bl)
OS (dh)11,100 11,100
79 Tucson Electric Power Company (bm)
AD (di)(10)(10)
80 Western Area PowerAdministration
(bn)
AD (dj)(880,724)(880,724)
81 Western Area PowerAdministration FNS 923,750 923,750 6,689,110 6,689,110
82 Western Area PowerAdministration
(bo)
LFP 719,750 719,750 1,689,167 1,689,167
83 Western Area Power
Administration NF 142,721 142,721 504,443 504,443
84 Western Area Power
Administration
(bp)(bq)(br)
OS (dk)(dl)786,946 786,946
85 Western Area PowerAdministration SFP 6,702 6,702 150,399 150,399
86 Westport Field Services, LLC (bs)(bt)
LFP (dm)(1,747,251)(1,747,251)
87 Accrual (dn)(430,070)(430,070)
TOTAL 23,517,147 23,794,157 133,941,553 335,030 24,781,914 159,058,497
FERC FORM NO. 1 (REV. 02-04)
Page 332
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
Settlement adjustment.
(i) Concept: StatisticalClassificationCode
Reimbursement for third-party services.
(j) Concept: StatisticalClassificationCode
Adams Solar Center LLC - contract termination date: October 30, 2036.
(k) Concept: StatisticalClassificationCode
Ancillary services.
(l) Concept: StatisticalClassificationCode
Settlement adjustment.
(m) Concept: StatisticalClassificationCode
Arizona Public Service Company - Legacy contract executed between PacifiCorp and Arizona Public Service Company concerning the exchange of transmission services over agreed-upon facilities (Restated Transmission Service Agreement between PacifiCorp and Arizona Public Service Company, Rate Schedule 436). The contract terminated December 31, 2021. See also page 328, Transmission of electricity for others in this Form No. 1.
(n) Concept: StatisticalClassificationCode
Ancillary services.
(o) Concept: StatisticalClassificationCode
Settlement adjustment.
(p) Concept: StatisticalClassificationCode
Ancillary services.
(q) Concept: StatisticalClassificationCode
Use of facilities.
(r) Concept: StatisticalClassificationCode
Big Horn Rural Electric Company - contract termination date: March 10, 2024.
(s) Concept: StatisticalClassificationCode
Settlement adjustment.
(t) Concept: StatisticalClassificationCode
Ancillary services.
(u) Concept: StatisticalClassificationCode
Settlement adjustment.
(v) Concept: StatisticalClassificationCode
Bonneville Power Administration - contract termination dates: January 2022; February 2022; March 2022; April 2022; July 2022; November 2022; 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; October 2027; November 2033; December 2041; and evergreen.
(w) Concept: StatisticalClassificationCode
Bonneville Power Administration - contract termination dates: September 30, 2023; September 30, 2027 and evergreen.
(x) 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.
(y) Concept: StatisticalClassificationCode
Ancillary services.
(z) Concept: StatisticalClassificationCode
Use of facilities.
(aa) Concept: StatisticalClassificationCode
Settlement adjustment.
(ab) Concept: StatisticalClassificationCode
Ancillary services.
(ac) Concept: StatisticalClassificationCode
Deseret Generation & Transmission Cooperative - contract termination date: November 2022.
(ad) Concept: StatisticalClassificationCode
Settlement adjustment.
(ae) Concept: StatisticalClassificationCode
Elbe Solar Center, LLC - contract termination date: October 30, 2036.
(af) Concept: StatisticalClassificationCode
Reimbursement for third-party services.
(ag) Concept: StatisticalClassificationCode
Ancillary services.
(ah) Concept: StatisticalClassificationCode
Use of facilities.
(ai) Concept: StatisticalClassificationCode
Use of facilities.
(aj) Concept: StatisticalClassificationCode
Settlement adjustment.
(ak) Concept: StatisticalClassificationCode
Idaho Power Company - contract termination dates: April 1, 2025 and July 1, 2025.
(al) 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 byPacifiCorp, 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.
(am) Concept: StatisticalClassificationCode
Use of facilities.
(an) Concept: StatisticalClassificationCode
Ancillary services.
(ao) Concept: StatisticalClassificationCode
Settlement adjustment.
(ap) Concept: StatisticalClassificationCode
Ancillary services.
(aq) Concept: StatisticalClassificationCode
Use of facilities.
(ar) Concept: StatisticalClassificationCode
Settlement adjustment.
(as) Concept: StatisticalClassificationCode
Morgan City Corporation - contract termination date: evergreen.
(at) Concept: StatisticalClassificationCode
Settlement adjustment.
(au) Concept: StatisticalClassificationCode
Ancillary services.
(av) Concept: StatisticalClassificationCode
Settlement adjustment.
(aw) Concept: StatisticalClassificationCode
Ancillary services.
(ax) Concept: StatisticalClassificationCode
Platte River Power Authority - contract termination date: October 31, 2022.
(ay) Concept: StatisticalClassificationCode
Ancillary services.
(az) Concept: StatisticalClassificationCode
Portland General Electric Company - contract termination date: April 1, 2027.
(ba) Concept: StatisticalClassificationCode
Portland General Electric Company - contract termination date: Upon two years written notice.
(bb) Concept: StatisticalClassificationCode
Use of facilities.
(bc) Concept: StatisticalClassificationCode
Ancillary services.
(bd) Concept: StatisticalClassificationCode
Public Service Company of Colorado - contract termination date: The date that all generating plants comprising PacifiCorp resources associated with this agreement have been retired from service or interests transferred.
(be) Concept: StatisticalClassificationCode
Ancillary services.
(bf) Concept: StatisticalClassificationCode
Settlement adjustment.
(bg) Concept: StatisticalClassificationCode
Ancillary services.
(bh) Concept: StatisticalClassificationCode
Ancillary services.
(bi) Concept: StatisticalClassificationCode
Use of facilities.
(bj) Concept: StatisticalClassificationCode
Surprise Valley Electrification Corp. - contract termination date: evergreen
(bk) 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.
(bl) Concept: StatisticalClassificationCode
Ancillary services.
(bm) Concept: StatisticalClassificationCode
Settlement adjustment.
(bn) Concept: StatisticalClassificationCode
Settlement adjustment.
(bo) Concept: StatisticalClassificationCode
Western Area Power Administration - contract termination date: May 31, 2022 (contract was early terminated on February 15, 2021).
(bp) Concept: StatisticalClassificationCode
Use of facilities.
(bq) Concept: StatisticalClassificationCode
Ancillary services.
(br) Concept: StatisticalClassificationCode
Western Area Power Administration - Legacy contract (Rate Schedule 684) executed between PacifiCorp and Western Area Power Administration concerning the exchange of transmission services over
agreed-upon facilities. The contract is subject to terminate upon the earlier of five years after written notice or June 30, 2042. See also page 328, Transmission of electricity for others in
this Form No. 1.
(bs) Concept: StatisticalClassificationCode
Westport Field Services, LLC - contract termination date: evergreen.
(bt) Concept: StatisticalClassificationCode
Reimbursement for third-party services.
(bu) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(bv) Concept: OtherChargesTransmissionOfElectricityByOthers
Reimbursement for third-party services.
(bw) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(bx) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(by) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(bz) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(ca) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cb) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(cc) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cd) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(ce) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cf) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cg) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(ch) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(ci) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cj) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(ck) Concept: OtherChargesTransmissionOfElectricityByOthers
Reimbursement for third-party services.
(cl) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cm) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(cn) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(co) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cp) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(cq) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cr) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cs) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(ct) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(cu) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cv) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cw) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cx) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(cy) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(cz) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(da) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(db) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(dc) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(dd) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(de) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(df) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(dg) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(dh) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(di) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(dj) Concept: OtherChargesTransmissionOfElectricityByOthers
Settlement adjustment.
(dk) Concept: OtherChargesTransmissionOfElectricityByOthers
Ancillary services.
(dl) Concept: OtherChargesTransmissionOfElectricityByOthers
Use of facilities.
(dm) Concept: OtherChargesTransmissionOfElectricityByOthers
Reimbursement for third-party services.
(dn) Concept: OtherChargesTransmissionOfElectricityByOthers
Represents the difference between actual wheeling expenses for the period as reflected on the individual line items within this schedule and the accruals charged to Account 565, Transmission of electricity by others, during this period.FERC FORM NO. 1 (REV. 02-04)
Page 332
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.Description(a)Amount(b)
1 1,577,509
2
3
4
5
6 Business & Economic Development and Corporate Memberships & Subscriptions:
7 Clatsop Economic Development Resources 5,000
8 Economic Development for Central Oregon 7,500
9 Greater Portland Inc 5,000
10 Greater Yakima Chamber of Commerce 5,000
11 Jordan River Commission 7,500
12 Klamath County Economic Development Association 5,000
13 Laramie Chamber of Business Alliance 5,000
14 Ogden-Weber Chamber of Commerce 6,000
15 Oregon Business Council 31,879
16 Portland Business Alliance 33,310
17 Redmond Economic Development, Inc.5,000
18 Salt Lake Chamber 60,000
19 South Coast Development Council, Inc.5,000
20 South Valley Chamber 6,000
21 Sport Oregon 5,000
22 Utah Manufacturers Association 7,220
23 Utah Taxpayers Association 18,700
24 Utah Valley Chamber of Commerce 6,000
25 Walla Walla Valley Chamber of Commerce 10,000
26 Wyoming Business Alliance 5,000
27 Wyoming Construction Coalition, Inc.5,000
28 Yakima County Development Association 7,500
29 Other (Individually < $5,000)112,877
30 Rating Agency and Trustee Fees:
31 Computershare Shareowner Services, LLC 25,301
32 Moody's Investors Service 120,574
33 Standard and Poor's Financial Services, LLC 259,558
34 The Bank of New York Mellon 142,625
35 U.S. Bank National Association 12,063
36 Directors' Fees - Regional Advisory Board 18,000
46 2,520,116
FERC FORM NO. 1 (ED. 12-94)Page 335
Industry Association Dues
Nuclear Power Research Expenses
Other Experimental and General Research Expenses
Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities
Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
TOTAL
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 havebeen 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 completereport 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 ofsection C the manner in which column balances are obtained. If average balances, state the method of averaging used.For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification listed in column (a). If plant mortality studies are prepared to
assist in estimating average service Lives, show in column (f) the type of mortality curve selected as most appropriate for the account and in column (g), if available, the weighted
average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature ofthe provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
LineNo.(a)(b)(c)(d)(e)(f)
1 Intangible Plant 58,013,199 58,013,199
2 Steam Production Plant 368,244,798 368,244,798
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 35,728,185 311,696 36,039,881
5 Hydraulic Production Plant-PumpedStorage
6 Other Production Plant 205,563,622 15,652 205,579,274
7 Transmission Plant 134,616,361 134,616,361
8 Distribution Plant 195,020,683 195,020,683
9 Regional Transmission and Market
Operation
10 General Plant 47,034,116 591,957 47,626,073
11 Common Plant-Electric
12 TOTAL (a)986,207,765 (b)0 58,932,504 1,045,140,269
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
(c)(d)
STEAM
PRODUCTION
PLANT:COLSTRIPPLANT: 311.00
68.862 29 years, 8 months, 12 days (6)7.24 S0.5 6 years, 10 months, 24 days
13
STEAMPRODUCTIONPLANT:
COLSTRIP
PLANT: 312.00
122.758 24 years, 2 months, 12 days (7)8.26 L0.5 6 years, 8 months, 12 days
14
STEAM
PRODUCTION
PLANT:COLSTRIPPLANT: 314.00
40.007 19 years, 3 months, 18 days (6)9.08 S0 6 years, 8 months, 12 days
15
STEAMPRODUCTIONPLANT:COLSTRIP
PLANT: 315.00
9.72 35 years, 1 month, 6 days (6)6.81 R2.5 6 years, 10 months, 24 days
16 0.435 17 years, 9 months, 18 days (5)9.59 L0 6 years, 7 months, 6 days
Functional Classification Depreciation Expense
(Account 403)
Depreciation Expensefor Asset RetirementCosts (Account 403.1)
Amortization of LimitedTerm 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
STEAM
PRODUCTION
PLANT:COLSTRIPPLANT: 316.00
17
STEAMPRODUCTIONPLANT: CRAIGUNIT 1: 311.00
11.663 42 years, 4 months, 24 days (1)5.42 S0.5 5 years
18
STEAMPRODUCTIONPLANT: CRAIG
UNIT 1: 312.00
32.691 26 years, 6 months (2)7.11 L0.5 4 years, 10 months, 24 days
19
STEAMPRODUCTION
PLANT: CRAIG
UNIT 1: 314.00
12.875 17 years, 9 months, 18 days (2)9.39 S0 4 years, 10 months, 24 days
20
STEAM
PRODUCTION
PLANT: CRAIGUNIT 1: 315.00
6.994 41 years, 9 months, 18 days (1)5.5 R2.5 4 years, 10 months, 24 days
21
STEAM
PRODUCTIONPLANT: CRAIGUNIT 1: 316.00
0.253 31 years, 6 months (1)6.3 L0 4 years, 8 months, 12 days
22
STEAMPRODUCTIONPLANT: CRAIGUNIT 2: 311.00
11.688 44 years, 8 months, 12 days (2)4.86 S0.5 5 years, 10 months, 24 days
23
STEAMPRODUCTION
PLANT: CRAIG
UNIT 2: 312.00
75.532 13 years, 6 months (2)11.02 L0.5 5 years, 10 months, 24 days
24
STEAM
PRODUCTION
PLANT: CRAIGUNIT 2: 314.00
13.266 16 years, 10 months, 24 days (2)9 S0 5 years, 9 months, 18 days
25
STEAM
PRODUCTIONPLANT: CRAIGUNIT 2: 315.00
7.367 17 years, 6 months (1)8.45 R2.5 5 years, 10 months, 24 days
26
STEAMPRODUCTIONPLANT: CRAIGCOMMON:
311.00
15.247 19 years, 8 months, 12 days (1)7.73 S0.5 6 years
27
STEAMPRODUCTION
PLANT: CRAIG
COMMON:312.00
29.437 17 years, 1 month, 6 days (2)8.52 L0.5 5 years, 10 months, 24 days
28
STEAM
PRODUCTIONPLANT: CRAIGCOMMON:314.00
3.544 17 years, 10 months, 24 days (2)8.43 S0 5 years, 9 months, 18 days
29
STEAMPRODUCTIONPLANT: CRAIG
COMMON:
315.00
2.968 33 years, 1 month, 6 days (1)5.72 R2.5 5 years, 10 months, 24 days
30
STEAM
PRODUCTIONPLANT: CRAIGCOMMON:316.00
0.988 29 years, 4 months, 24 days (1)6 L0 5 years, 7 months, 6 days
31
STEAMPRODUCTIONPLANT: DAVE
JOHNSTON
UNIT 1: 311.00
1.432 18 years, 6 months (3)6.64 S0.5 7 years
32
STEAM
PRODUCTION
PLANT: DAVEJOHNSTONUNIT 1: 312.00
57.727 20 years, 6 months (4)6.03 L0.5 6 years, 9 months, 18 days
33
STEAMPRODUCTIONPLANT: DAVEJOHNSTON
UNIT 1: 314.00
14.95 23 years, 2 months, 12 days (4)5.93 S0 6 years, 7 months, 6 days
34 STEAM
PRODUCTION
PLANT: DAVEJOHNSTONUNIT 1: 315.00
2.899 40 years, 2 months, 12 days (3)2.93 R2.5 6 years, 9 months, 18 days
35
STEAMPRODUCTIONPLANT: DAVEJOHNSTON
UNIT 1: 316.00
0.003 25 years, 7 months, 6 days (3)4.74 L0 6 years, 6 months
36
STEAMPRODUCTION
PLANT: DAVE
JOHNSTONUNIT 2: 311.00
0.567 14 years, 4 months, 24 days (3)8.45 S0.5 7 years
37
STEAM
PRODUCTIONPLANT: DAVEJOHNSTONUNIT 2: 312.00
59.168 21 years (4)5.97 L0.5 6 years, 9 months, 18 days
38
STEAMPRODUCTIONPLANT: DAVE
JOHNSTON
UNIT 2: 314.00
17.273 20 years, 8 months, 12 days (4)6.5 S0 6 years, 8 months, 12 days
39
STEAM
PRODUCTION
PLANT: DAVEJOHNSTONUNIT 2: 315.00
3.396 24 years, 9 months, 18 days (3)4.84 R2.5 6 years, 10 months, 24 days
40
STEAMPRODUCTIONPLANT: DAVE
JOHNSTON
UNIT 3: 311.00
19.3 19 years, 9 months, 18 days (3)6.19 S0.5 7 years
41
STEAM
PRODUCTION
PLANT: DAVEJOHNSTONUNIT 3: 312.00
232.755 17 years, 3 months, 18 days (3)7.07 L0.5 6 years, 9 months, 18 days
42
STEAMPRODUCTIONPLANT: DAVEJOHNSTON
UNIT 3: 314.00
23.494 19 years, 3 months, 18 days (4)6.78 S0 6 years, 8 months, 12 days
43
STEAMPRODUCTION
PLANT: DAVE
JOHNSTONUNIT 3: 315.00
14.832 19 years, 3 months, 18 days (3)6.28 R2.5 7 years
44
STEAM
PRODUCTIONPLANT: DAVEJOHNSTONUNIT 3: 316.00
0.24 24 years, 3 months, 18 days (3)5 L0 6 years, 6 months
45
STEAMPRODUCTIONPLANT: DAVE
JOHNSTON
UNIT 4: 311.00
15.443 17 years, 2 months, 12 days (3)7.13 S0.5 7 years
46
STEAM
PRODUCTION
PLANT: DAVEJOHNSTONUNIT 4: 312.00
237.238 17 years (3)7.19 L0.5 6 years, 9 months, 18 days
47
STEAMPRODUCTIONPLANT: DAVE
JOHNSTON
UNIT 4: 314.00
42.323 20 years (4)6.44 S0 6 years, 8 months, 12 days
48
STEAM
PRODUCTION
PLANT: DAVEJOHNSTONUNIT 4: 315.00
14.48 19 years, 7 months, 6 days (3)6.22 R2.5 6 years, 10 months, 24 days
49
STEAMPRODUCTIONPLANT: DAVEJOHNSTON
UNIT 4: 316.00
0.596 22 years, 4 months, 24 days (3)5.43 L0 6 years, 7 months, 6 days
50 0.1 53 years, 10 months, 24 days 3.45 SQUARE 7 years
STEAM
PRODUCTION
PLANT: DAVEJOHNSTONCOMMON:310.20
51
STEAMPRODUCTIONPLANT: DAVE
JOHNSTON
COMMON:311.00
132.76 19 years, 10 months, 24 days (3)6.1 S0.5 7 years
52
STEAM
PRODUCTIONPLANT: DAVEJOHNSTONCOMMON:
312.00
134.041 16 years, 1 month, 6 days (3)7.48 L0.5 6 years, 9 months, 18 days
53
STEAMPRODUCTION
PLANT: DAVE
JOHNSTONCOMMON:314.00
9.895 13 years, 9 months, 18 days (3)8.83 S0 6 years, 9 months, 18 days
54
STEAMPRODUCTIONPLANT: DAVEJOHNSTON
COMMON:
315.00
27.933 16 years (3)7.16 R2.5 7 years
55
STEAM
PRODUCTION
PLANT: DAVEJOHNSTONCOMMON:
316.00
9.38 18 years, 2 months, 12 days (3)6.7 L0 6 years, 7 months, 6 days
56
STEAMPRODUCTION
PLANT:
GADSBY UNIT1: 311.00
1.204 36 years (14)2.24 S0.5 11 years, 10 months, 24 days
57
STEAM
PRODUCTIONPLANT:GADSBY UNIT1: 312.00
10.29 35 years, 2 months, 12 days (14)2.35 L0.5 11 years, 2 months, 12 days
58
STEAMPRODUCTIONPLANT:
GADSBY UNIT
1: 314.00
5.823 38 years, 6 months (14)1.56 S0 10 years, 6 months
59
STEAM
PRODUCTION
PLANT:GADSBY UNIT1: 315.00
1.395 47 years, 9 months, 18 days (14)0.96 R2.5 11 years, 9 months, 18 days
60
STEAMPRODUCTIONPLANT:GADSBY UNIT
1: 316.00
0.021 42 years, 10 months, 24 days (10)1.04 L0 9 years, 6 months
61
STEAMPRODUCTION
PLANT:
GADSBY UNIT2: 311.00
1.076 35 years, 10 months, 24 days (15)2.25 S0.5 11 years, 10 months, 24 days
62
STEAMPRODUCTIONPLANT:GADSBY UNIT
2: 312.00
14.824 36 years, 10 months, 24 days (14)2.11 L0.5 11 years, 1 month, 6 days
63
STEAMPRODUCTION
PLANT:
GADSBY UNIT2: 314.00
6.475 33 years, 2 months, 12 days (14)2.3 S0 10 years, 9 months, 18 days
64
STEAM
PRODUCTIONPLANT:GADSBY UNIT2: 315.00
1.394 50 years, 4 months, 24 days (14)0.87 R2.5 11 years, 9 months, 18 days
65 0.013 43 years (10)1.04 L0 9 years, 4 months, 24 days
STEAM
PRODUCTION
PLANT:GADSBY UNIT2: 316.00
66
STEAMPRODUCTIONPLANT:GADSBY UNIT
3: 311.00
1.156 33 years, 6 months (14)2.6 S0.5 11 years, 10 months, 24 days
67
STEAMPRODUCTION
PLANT:
GADSBY UNIT3: 312.00
14.473 35 years, 4 months, 24 days (14)2.3 L0.5 11 years, 2 months, 12 days
68
STEAM
PRODUCTIONPLANT:GADSBY UNIT3: 314.00
7.968 28 years, 3 months, 18 days (14)3.2 S0 11 years
69
STEAMPRODUCTIONPLANT:
GADSBY UNIT
3: 315.00
2.553 34 years, 4 months, 24 days (14)2.48 R2.5 11 years, 9 months, 18 days
70
STEAM
PRODUCTION
PLANT:GADSBY UNIT3: 316.00
0.047 42 years, 7 months, 6 days (10)1.03 L0 9 years, 7 months, 6 days
71
STEAMPRODUCTIONPLANT:
GADSBY
COMMON:311.00
11.964 38 years, 8 months, 12 days (14)2.09 S0.5 11 years, 9 months, 18 days
72
STEAM
PRODUCTIONPLANT:GADSBYCOMMON:
312.00
1.385 20 years, 9 months, 18 days (14)5.44 L0.5 11 years, 6 months
73
STEAMPRODUCTION
PLANT:
GADSBYCOMMON:314.00
0.476 30 years (14)3.21 S0 11 years, 1 month, 6 days
74
STEAMPRODUCTIONPLANT:GADSBY
COMMON:
315.00
3.196 25 years, 3 months, 18 days (14)4.28 R2.5 11 years, 10 months, 24 days
75
STEAM
PRODUCTION
PLANT:GADSBYCOMMON:316.00
0.433 28 years, 4 months, 24 days (12)3.12 L0 10 years, 8 months, 12 days
76
STEAMPRODUCTIONPLANT:
HAYDEN UNIT1: 311.00
1.135 51 years, 4 months, 24 days (2)1.25 S0.5 9 years, 9 months, 18 days
77
STEAM
PRODUCTIONPLANT:HAYDEN UNIT1: 312.00
46.931 20 years, 10 months, 24 days (2)5.49 L0.5 9 years, 7 months, 6 days
78
STEAMPRODUCTIONPLANT:
HAYDEN UNIT
1: 314.00
5.775 23 years, 7 months, 6 days (2)4.53 S0 9 years, 4 months, 24 days
79
STEAM
PRODUCTION
PLANT:HAYDEN UNIT1: 315.00
1.033 44 years, 9 months, 18 days (2)2.53 R2.5 9 years, 8 months, 12 days
80 0.25 29 years, 10 months, 24 days (1)3.51 L0 9 years
STEAM
PRODUCTION
PLANT:HAYDEN UNIT1: 316.00
81
STEAMPRODUCTIONPLANT:HAYDEN UNIT
2: 311.00
1.828 47 years, 1 month, 6 days (2)1.48 S0.5 9 years, 9 months, 18 days
82
STEAMPRODUCTION
PLANT:
HAYDEN UNIT2: 312.00
23.933 20 years, 2 months, 12 days (2)5.7 L0.5 9 years, 7 months, 6 days
83
STEAM
PRODUCTIONPLANT:HAYDEN UNIT2: 314.00
4.641 22 years, 10 months, 24 days (2)4.69 S0 9 years, 4 months, 24 days
84
STEAMPRODUCTIONPLANT:
HAYDEN UNIT
2: 315.00
1.331 49 years (1)2.16 R2.5 9 years, 8 months, 12 days
85
STEAM
PRODUCTION
PLANT:HAYDEN UNIT2: 316.00
0.225 36 years, 10 months, 24 days (1)2.58 L0 8 years, 8 months, 12 days
86
STEAMPRODUCTIONPLANT:
HAYDEN
COMMON:311.00
14.854 21 years, 3 months, 18 days (1)4.82 S0.5 9 years, 10 months, 24 days
87
STEAM
PRODUCTIONPLANT:HAYDENCOMMON:
312.00
12.481 28 years, 10 months, 24 days (2)3.69 L0.5 9 years, 6 months
88
STEAMPRODUCTION
PLANT:
HAYDENCOMMON:314.00
0.252 21 years, 9 months, 18 days (2)5.05 S0 9 years, 6 months
89
STEAMPRODUCTIONPLANT:HAYDEN
COMMON:
315.00
0.209 50 years, 4 months, 24 days (2)2.19 R2.5 9 years, 8 months, 12 days
90
STEAM
PRODUCTION
PLANT:HAYDENCOMMON:316.00
0.162 36 years, 7 months, 6 days (1)2.61 L0 8 years, 8 months, 12 days
91
STEAMPRODUCTIONPLANT:
HUNTER UNIT
1: 311.00
23.117 57 years, 1 month, 6 days (7)2.3 S0.5 20 years, 10 months, 24 days
92
STEAM
PRODUCTIONPLANT:HUNTER UNIT1: 312.00
268.512 30 years, 10 months, 24 days (8)3.85 L0.5 20 years
93
STEAMPRODUCTIONPLANT:
HUNTER UNIT
1: 314.00
67.153 32 years, 7 months, 6 days (8)3.66 S0 19 years, 1 month, 6 days
94
STEAM
PRODUCTION
PLANT:HUNTER UNIT1: 315.00
34.588 46 years (7)2.77 R2.5 20 years, 9 months, 18 days
95 0.803 38 years, 2 months, 12 days (5)3.21 L0 16 years, 6 months
STEAM
PRODUCTION
PLANT:HUNTER UNIT1: 316.00
96
STEAMPRODUCTIONPLANT:HUNTER UNIT
2: 311.00
12.563 54 years, 7 months, 6 days (7)2.38 S0.5 20 years, 10 months, 24 days
97
STEAMPRODUCTION
PLANT:
HUNTER UNIT2: 312.00
170.902 31 years (8)3.83 L0.5 20 years
98
STEAM
PRODUCTIONPLANT:HUNTER UNIT2: 314.00
46.505 32 years, 4 months, 24 days (8)3.68 S0 19 years, 1 month, 6 days
99
STEAMPRODUCTIONPLANT:
HUNTER UNIT
2: 315.00
16.921 50 years, 2 months, 12 days (7)2.58 R2.5 20 years, 8 months, 12 days
100
STEAM
PRODUCTION
PLANT:HUNTER UNIT3: 311.00
56.228 54 years, 8 months, 12 days (7)2.38 S0.5 21 years
101
STEAMPRODUCTIONPLANT:
HUNTER UNIT
3: 312.00
303.994 37 years, 1 month, 6 days (8)3.28 L0.5 19 years, 4 months, 24 days
102
STEAM
PRODUCTION
PLANT:HUNTER UNIT3: 314.00
84.957 29 years, 9 months, 18 days (7)3.88 S0 19 years, 4 months, 24 days
103
STEAMPRODUCTIONPLANT:HUNTER UNIT
3: 315.00
54.921 52 years, 3 months, 18 days (7)2.49 R2.5 20 years, 8 months, 12 days
104
STEAMPRODUCTION
PLANT:
HUNTER UNIT3: 316.00
1.634 36 years, 4 months, 24 days (5)3.33 L0 16 years, 10 months, 24 days
105
STEAM
PRODUCTIONPLANT:HUNTER UNITS1 AND 2
COMMON:
311.00
9.496 56 years, 4 months, 24 days (7)2.32 S0.5 20 years, 10 months, 24 days
106
STEAM
PRODUCTION
PLANT:HUNTER UNITS1 AND 2COMMON:
312.00
12.859 35 years (8)3.45 L0.5 19 years, 7 months, 6 days
107
STEAM
PRODUCTION
PLANT:HUNTER UNITS1 AND 2COMMON:
314.00
3.715 35 years, 8 months, 12 days (8)3.39 S0 18 years, 7 months, 6 days
108
STEAMPRODUCTION
PLANT:
HUNTER UNITS1 AND 2COMMON:315.00
0.052 35 years, 2 months, 12 days (6)3.41 R2.5 21 years, 3 months, 18 days
109
STEAMPRODUCTIONPLANT:
HUNTER UNITS
1 AND 2COMMON:316.00
0.824 38 years, 10 months, 24 days (5)3.16 L0 16 years, 6 months
110 STEAMPRODUCTIONPLANT:
HUNTER UNITS
1, 2 AND 3COMMON:310.20
0.246 60 years, 10 months, 24 days 2.04 SQUARE 22 years
111
STEAMPRODUCTIONPLANT:HUNTER UNITS
1, 2 AND 3
COMMON:311.00
112.575 46 years, 9 months, 18 days (7)2.68 S0.5 21 years, 1 month, 6 days
112
STEAM
PRODUCTIONPLANT:HUNTER UNITS1, 2 AND 3
COMMON:
312.00
28.25 31 years, 3 months, 18 days (8)3.77 L0.5 19 years, 10 months, 24 days
113
STEAM
PRODUCTION
PLANT:HUNTER UNITS1, 2 AND 3COMMON:
314.00
1.192 34 years, 1 month, 6 days (8)3.53 S0 18 years, 8 months, 12 days
114
STEAMPRODUCTION
PLANT:
HUNTER UNITS1, 2 AND 3COMMON:
315.00
1.635 29 years, 6 months (5)3.85 R2.5 21 years, 7 months, 6 days
115
STEAMPRODUCTION
PLANT:
HUNTER UNITS1, 2 AND 3COMMON:316.00
0.485 29 years, 3 months, 18 days (5)3.95 L0 18 years, 1 month, 6 days
116
STEAMPRODUCTIONPLANT:
HUNTINGTON
UNIT 1: 311.00
19.94 50 years (7)2.52 S0.5 15 years, 4 months, 24 days
117
STEAM
PRODUCTION
PLANT:HUNTINGTONUNIT 1: 312.00
293.285 26 years, 2 months, 12 days (7)4.41 L0.5 15 years
118
STEAMPRODUCTIONPLANT:HUNTINGTON
UNIT 1: 314.00
62.237 26 years, 10 months, 24 days (7)4.37 S0 14 years, 7 months, 6 days
119
STEAMPRODUCTION
PLANT:
HUNTINGTONUNIT 1: 315.00
20.953 43 years, 3 months, 18 days (6)2.77 R2.5 15 years, 4 months, 24 days
120
STEAM
PRODUCTIONPLANT:HUNTINGTON
UNIT 1: 316.00
1.028 26 years, 7 months, 6 days (5)4.27 L0 13 years, 9 months, 18 days
121
STEAMPRODUCTION
PLANT:
HUNTINGTONUNIT 2: 311.00
26.688 39 years, 4 months, 24 days (6)3.09 S0.5 15 years, 7 months, 6 days
122
STEAM
PRODUCTIONPLANT:HUNTINGTONUNIT 2: 312.00
254.61 27 years, 1 month, 6 days (7)4.25 L0.5 15 years
123
STEAMPRODUCTIONPLANT:
HUNTINGTON
UNIT 2: 314.00
59.707 28 years, 2 months, 12 days (7)4.16 S0 14 years, 6 months
124 24.655 34 years, 9 months, 18 days (6)3.39 R2.5 15 years, 7 months, 6 days
STEAM
PRODUCTION
PLANT:HUNTINGTONUNIT 2: 315.00
125
STEAMPRODUCTIONPLANT:HUNTINGTON
UNIT 2: 316.00
0.971 29 years, 3 months, 18 days (5)3.89 L0 13 years, 7 months, 6 days
126
STEAMPRODUCTION
PLANT:
HUNTINGTONCOMMON:311.00
82.353 38 years, 7 months, 6 days (7)3.22 S0.5 15 years, 7 months, 6 days
127
STEAMPRODUCTIONPLANT:HUNTINGTON
COMMON:
312.00
38.232 23 years, 8 months, 12 days (7)4.81 L0.5 15 years, 1 month, 6 days
128
STEAM
PRODUCTION
PLANT:HUNTINGTONCOMMON:314.00
7.432 31 years, 10 months, 24 days (8)3.8 S0 14 years, 1 month, 6 days
129
STEAMPRODUCTIONPLANT:
HUNTINGTONCOMMON:315.00
4.186 24 years, 4 months, 24 days (5)4.68 R2.5 15 years, 9 months, 18 days
130
STEAMPRODUCTIONPLANT:HUNTINGTON
COMMON:
316.00
1.434 19 years, 7 months, 6 days (5)5.68 L0 14 years, 4 months, 24 days
131
STEAM
PRODUCTION
PLANT: JIMBRIDGER UNIT1: 311.00
15.425 42 years, 1 month, 6 days (5)3.84 S0.5 7 years, 10 months, 24 days
132
STEAMPRODUCTIONPLANT: JIMBRIDGER UNIT
1: 312.00
177.317 23 years, 1 month, 6 days (5)6.07 L0.5 7 years, 8 months, 12 days
133
STEAMPRODUCTION
PLANT: JIM
BRIDGER UNIT1: 314.00
47.333 20 years, 9 months, 18 days (5)6.52 S0 7 years, 8 months, 12 days
134
STEAM
PRODUCTIONPLANT: JIMBRIDGER UNIT1: 315.00
10.769 41 years, 4 months, 24 days (5)3.96 R2.5 7 years, 9 months, 18 days
135
STEAMPRODUCTION
PLANT: JIM
BRIDGER UNIT1: 316.00
0.298 36 years, 1 month, 6 days (4)4.02 L0 7 years, 2 months, 12 days
136
STEAM
PRODUCTIONPLANT: JIMBRIDGER UNIT2: 311.00
13.003 49 years, 8 months, 12 days (6)2.97 S0.5 11 years, 8 months, 12 days
137
STEAMPRODUCTIONPLANT: JIM
BRIDGER UNIT
2: 312.00
173.405 26 years, 3 months, 18 days (6)4.86 L0.5 11 years, 3 months, 18 days
138
STEAM
PRODUCTION
PLANT: JIMBRIDGER UNIT2: 314.00
59.894 22 years (5)5.55 S0 11 years, 3 months, 18 days
139 9.329 45 years, 6 months (5)3.1 R2.5 11 years, 7 months, 6 days
STEAM
PRODUCTION
PLANT: JIMBRIDGER UNIT2: 315.00
140
STEAMPRODUCTIONPLANT: JIMBRIDGER UNIT
2: 316.00
0.198 36 years, 9 months, 18 days (4)3.53 L0 10 years, 2 months, 12 days
141
STEAMPRODUCTION
PLANT: JIM
BRIDGER UNIT3: 311.00
12.969 43 years, 7 months, 6 days (6)2.9 S0.5 16 years, 6 months
142
STEAM
PRODUCTIONPLANT: JIMBRIDGER UNIT3: 312.00
268.993 25 years, 7 months, 6 days (6)4.6 L0.5 15 years, 10 months, 24 days
143
STEAMPRODUCTIONPLANT: JIM
BRIDGER UNIT
3: 314.00
44.992 28 years, 10 months, 24 days (7)4.11 S0 15 years, 3 months, 18 days
144
STEAM
PRODUCTION
PLANT: JIMBRIDGER UNIT3: 315.00
8.2 38 years, 8 months, 12 days (6)3.24 R2.5 16 years, 4 months, 24 days
145
STEAMPRODUCTIONPLANT: JIM
BRIDGER UNIT
3: 316.00
0.192 38 years, 1 month, 6 days (4)3.17 L0 13 years, 6 months
146
STEAM
PRODUCTION
PLANT: JIMBRIDGER UNIT4: 311.00
40.518 51 years, 7 months, 6 days (6)2.54 S0.5 16 years, 4 months, 24 days
147
STEAMPRODUCTIONPLANT: JIMBRIDGER UNIT
4: 312.00
302.86 25 years, 6 months (6)4.61 L0.5 15 years, 10 months, 24 days
148
STEAMPRODUCTION
PLANT: JIM
BRIDGER UNIT4: 314.00
46.049 30 years, 4 months, 24 days (7)3.91 S0 15 years, 2 months, 12 days
149
STEAM
PRODUCTIONPLANT: JIMBRIDGER UNIT4: 315.00
17.263 48 years, 9 months, 18 days (6)2.68 R2.5 16 years, 2 months, 12 days
150
STEAMPRODUCTIONPLANT: JIM
BRIDGER UNIT
4: 316.00
1.249 38 years, 2 months, 12 days (4)3.16 L0 13 years, 6 months
151
STEAM
PRODUCTION
PLANT: JIMBRIDGERCOMMON:
310.20
0.281 61 years, 3 months, 18 days 2.13 SQUARE 17 years
152
STEAMPRODUCTION
PLANT: JIM
BRIDGERCOMMON:311.00
68.727 34 years, 10 months, 24 days (6)3.55 S0.5 16 years, 7 months, 6 days
153
STEAMPRODUCTIONPLANT: JIMBRIDGER
COMMON:
312.00
94.216 28 years, 2 months, 12 days (7)4.24 L0.5 15 years, 9 months, 18 days
154 STEAM
PRODUCTION
PLANT: JIMBRIDGERCOMMON:314.00
9.504 25 years, 8 months, 12 days (6)4.48 S0 15 years, 7 months, 6 days
155
STEAMPRODUCTION
PLANT: JIM
BRIDGERCOMMON:315.00
16.656 32 years (5)3.77 R2.5 16 years, 6 months
156
STEAMPRODUCTIONPLANT: JIMBRIDGER
COMMON:
316.00
3.803 22 years, 8 months, 12 days (4)5 L0 14 years, 10 months, 24 days
157
STEAM
PRODUCTION
PLANT:NAUGHTONUNIT 1: 311.00
21.073 24 years, 3 months, 18 days (9)5.74 S0.5 8 years, 10 months, 24 days
158
STEAMPRODUCTIONPLANT:NAUGHTON
UNIT 1: 312.00
154.475 17 years, 10 months, 24 days (9)7.39 L0.5 8 years, 8 months, 12 days
159
STEAMPRODUCTION
PLANT:
NAUGHTONUNIT 1: 314.00
20.553 21 years, 7 months, 6 days (9)6.65 S0 8 years, 6 months
160
STEAM
PRODUCTIONPLANT:NAUGHTON
UNIT 1: 315.00
20.713 19 years, 1 month, 6 days (9)6.81 R2.5 8 years, 10 months, 24 days
161
STEAMPRODUCTION
PLANT:
NAUGHTONUNIT 1: 316.00
0.096 40 years, 6 months (8)4 L0 7 years, 8 months, 12 days
162
STEAM
PRODUCTIONPLANT:NAUGHTONUNIT 2: 311.00
29.217 19 years, 3 months, 18 days (9)6.98 S0.5 8 years, 10 months, 24 days
163
STEAMPRODUCTIONPLANT:
NAUGHTON
UNIT 2: 312.00
190.425 18 years, 1 month, 6 days (9)7.28 L0.5 8 years, 8 months, 12 days
164
STEAM
PRODUCTION
PLANT:NAUGHTONUNIT 2: 314.00
26.53 17 years, 9 months, 18 days (9)7.51 S0 8 years, 7 months, 6 days
165
STEAMPRODUCTIONPLANT:NAUGHTON
UNIT 2: 315.00
30.17 19 years, 3 months, 18 days (9)6.74 R2.5 8 years, 10 months, 24 days
166
STEAMPRODUCTION
PLANT:
NAUGHTONUNIT 2: 316.00
0.389 37 years, 7 months, 6 days (8)4 L0 7 years, 10 months, 24 days
167
STEAMPRODUCTIONPLANT:NAUGHTON
UNIT 3: 311.00
14.081 39 years, 7 months, 6 days (9)3.83 S0.5 8 years, 10 months, 24 days
168
STEAMPRODUCTION
PLANT:
NAUGHTONUNIT 3: 312.00
95.896 21 years, 2 months, 12 days (9)9.64 L0.5 8 years, 8 months, 12 days
169
STEAM
PRODUCTIONPLANT:NAUGHTONUNIT 3: 314.00
39.545 23 years, 3 months, 18 days (9)5.99 S0 8 years, 6 months
170
STEAMPRODUCTIONPLANT:
NAUGHTON
UNIT 3: 315.00
11.44 33 years, 3 months, 18 days (9)4.13 R2.5 8 years, 9 months, 18 days
171 STEAM
PRODUCTION
PLANT:NAUGHTONUNIT 3: 316.00
0.206 38 years, 2 months, 12 days (8)3.66 L0 7 years, 10 months, 24 days
172
STEAMPRODUCTIONPLANT:NAUGHTON
COMMON:
310.20
0.015 66 years, 8 months, 12 days 3.25 SQUARE 9 years
173
STEAM
PRODUCTION
PLANT:NAUGHTONCOMMON:311.00
69.585 19 years, 4 months, 24 days (9)6.87 S0.5 8 years, 10 months, 24 days
174
STEAMPRODUCTIONPLANT:
NAUGHTON
COMMON:312.00
32.826 19 years, 1 month, 6 days (9)6.82 L0.5 8 years, 8 months, 12 days
175
STEAM
PRODUCTIONPLANT:NAUGHTONCOMMON:
314.00
8.036 17 years (9)8 S0 8 years, 8 months, 12 days
176
STEAMPRODUCTION
PLANT:NAUGHTONCOMMON:315.00
3.878 18 years, 10 months, 24 days (9)6.75 R2.5 8 years, 10 months, 24 days
177
STEAMPRODUCTIONPLANT:
NAUGHTON
COMMON:316.00
1.717 18 years, 8 months, 12 days (8)7.02 L0 8 years, 4 months, 24 days
178
STEAM
PRODUCTIONPLANT:WYODAKPLANT: 310.20
0.165 57 years, 7 months, 6 days 1.92 SQUARE 19 years
179
STEAMPRODUCTIONPLANT:
WYODAK
PLANT: 311.00
53.157 47 years, 6 months (4)2.4 S0.5 18 years, 3 months, 18 days
180
STEAM
PRODUCTION
PLANT:WYODAKPLANT: 312.00
317.978 30 years, 7 months, 6 days (5)3.59 L0.5 17 years, 4 months, 24 days
181
STEAMPRODUCTIONPLANT:WYODAK
PLANT: 314.00
66.827 31 years, 4 months, 24 days (5)3.52 S0 16 years, 7 months, 6 days
182
STEAMPRODUCTION
PLANT:WYODAKPLANT: 315.00
27.529 40 years, 7 months, 6 days (4)2.73 R2.5 18 years, 3 months, 18 days
183
STEAMPRODUCTIONPLANT:WYODAK
PLANT: 316.00
1.457 27 years (3)3.89 L0 16 years, 1 month, 6 days
184
STEAMPRODUCTION
PLANT:
BLUNDELLGEOTHERMALUNIT 1: 311.00
6.591 46 years, 10 months, 24 days (9)2.84 S0.5 16 years, 6 months
185
STEAMPRODUCTIONPLANT:BLUNDELL
GEOTHERMAL
UNIT 1: 312.00
14.687 38 years (10)3.41 L0.5 15 years, 2 months, 12 days
186 17.941 33 years, 3 months, 18 days (9)4 S0 14 years, 10 months, 24 days
STEAM
PRODUCTION
PLANT:BLUNDELLGEOTHERMALUNIT 1: 314.00
187
STEAMPRODUCTIONPLANT:
BLUNDELL
GEOTHERMALUNIT 1: 315.00
4.98 45 years, 3 months, 18 days (8)2.82 R2.5 16 years, 4 months, 24 days
188
STEAM
PRODUCTIONPLANT:BLUNDELLGEOTHERMAL
UNIT 1: 316.00
0.641 30 years, 8 months, 12 days (7)3.92 L0 14 years, 2 months, 12 days
189
STEAMPRODUCTION
PLANT:
BLUNDELLGEOTHERMALUNIT 2: 311.00
0.689 28 years, 10 months, 24 days (8)4.23 S0.5 16 years, 8 months, 12 days
190
STEAMPRODUCTIONPLANT:BLUNDELL
GEOTHERMAL
UNIT 2: 312.00
8.263 26 years, 8 months, 12 days (9)4.58 L0.5 15 years, 10 months, 24 days
191
STEAM
PRODUCTION
PLANT:BLUNDELLGEOTHERMAL
UNIT 2: 314.00
17.617 27 years, 4 months, 24 days (9)4.45 S0 15 years, 6 months
192
STEAMPRODUCTION
PLANT:
BLUNDELLGEOTHERMALUNIT 2: 315.00
2.454 29 years, 10 months, 24 days (8)4.08 R2.5 16 years, 8 months, 12 days
193
STEAMPRODUCTIONPLANT:BLUNDELL
GEOTHERMAL
UNIT 2: 316.00
0.545 25 years, 7 months, 6 days (7)4.61 L0 14 years, 8 months, 12 days
194
STEAM
PRODUCTION
PLANT:BLUNDELLGEOTHERMALSTEAM FIELD:
310.20
40.982 46 years, 9 months, 18 days 1.69 SQUARE 17 years
195
STEAMPRODUCTION
PLANT:
BLUNDELLGEOTHERMALSTEAM FIELD:311.00
0.251 27 years, 7 months, 6 days (7)3.87 S0.5 16 years, 9 months, 18 days
196
STEAMPRODUCTIONPLANT:
BLUNDELL
GEOTHERMALSTEAM FIELD:312.00
37.46 24 years, 1 month, 6 days (8)4.57 L0.5 16 years
197
STEAMPRODUCTIONPLANT:
BLUNDELL
GEOTHERMALSTEAM FIELD:315.00
1.079 23 years, 2 months, 12 days (7)4.84 R2.5 16 years, 9 months, 18 days
198
STEAMPRODUCTIONPLANT:BLUNDELL
GEOTHERMAL
STEAM FIELD:316.00
0.125 20 years, 9 months, 18 days (6)5.24 L0 15 years, 1 month, 6 days
199 0.942 27 years, 7 months, 6 days (8)4.4 S0.5 16 years, 9 months, 18 days
STEAM
PRODUCTION
PLANT:BLUNDELLGEOTHERMALCOMMON:
311.00
200
STEAMPRODUCTION
PLANT:
BLUNDELLGEOTHERMALCOMMON:312.00
0.271 17 years, 8 months, 12 days (8)6.28 L0.5 16 years, 4 months, 24 days
201
STEAMPRODUCTIONPLANT:
BLUNDELL
GEOTHERMALCOMMON:315.00
0.042 25 years, 1 month, 6 days (8)4.78 R2.5 16 years, 9 months, 18 days
202
STEAMPRODUCTIONPLANT:BLUNDELL
GEOTHERMAL
COMMON:316.00
0.075 36 years, 9 months, 18 days (7)3.35 L0 13 years, 8 months, 12 days
203
HYDRAULIC
PRODUCTIONPLANT:ASHTON/ST.ANTHONY:
330.20
0.328 12 years, 6 months 11.48 SQUARE 7 years
204
HYDRAULIC
PRODUCTION
PLANT:ASHTON/ST.ANTHONY:331.00
2.149 20 years 8.88 R1 6 years, 10 months, 24 days
205
HYDRAULICPRODUCTIONPLANT:
ASHTON/ST.
ANTHONY:332.00
28.138 15 years, 9 months, 18 days 8.72 R1.5 7 years
206
HYDRAULIC
PRODUCTIONPLANT:ASHTON/ST.ANTHONY:
333.00
1.978 33 years, 2 months, 12 days (1)7.56 S0 6 years, 10 months, 24 days
207
HYDRAULICPRODUCTION
PLANT:
ASHTON/ST.ANTHONY:334.00
1.337 24 years, 8 months, 12 days (1)8.4 L0 6 years, 9 months, 18 days
208
HYDRAULICPRODUCTIONPLANT:ASHTON/ST.
ANTHONY:
335.00
0.008 41 years, 7 months, 6 days (1)7.36 R0.5 6 years, 9 months, 18 days
209
HYDRAULIC
PRODUCTIONPLANT:ASHTON/ST.ANTHONY:
336.00
0.192 15 years, 9 months, 18 days (1)10.87 S0.5 6 years, 10 months, 24 days
210
HYDRAULICPRODUCTION
PLANT: BEAR
RIVER: 330.20
0.006 115 years, 3 months, 18 days 1.53 SQUARE 12 years, 10 months, 24 days
211
HYDRAULIC
PRODUCTION
PLANT: BEARRIVER: 330.40
0.038 7.02
212
HYDRAULIC
PRODUCTIONPLANT: BEARRIVER: 331.00
8.162 26 years, 3 months, 18 days (1)4.39 R1 12 years, 8 months, 12 days
213 34.449 23 years, 4 months, 24 days (1)4.77 R1.5 12 years, 9 months, 18 days
HYDRAULIC
PRODUCTION
PLANT: BEARRIVER: 332.00
214
HYDRAULIC
PRODUCTIONPLANT: BEARRIVER: 333.00
21.965 23 years (2)4.92 S0 12 years, 8 months, 12 days
215
HYDRAULICPRODUCTIONPLANT: BEARRIVER: 334.00
6.727 24 years, 3 months, 18 days (2)4.71 L0 12 years, 3 months, 18 days
216
HYDRAULICPRODUCTIONPLANT: BEAR
RIVER: 335.00
0.079 42 years, 7 months, 6 days (1)2.94 R0.5 12 years, 3 months, 18 days
217
HYDRAULICPRODUCTION
PLANT: BEAR
RIVER: 336.00
1.382 22 years, 8 months, 12 days (2)5.09 S0.5 12 years, 9 months, 18 days
218
HYDRAULIC
PRODUCTION
PLANT: BEND:331.00
0.062 23 years, 6 months (1)0.89 R1 9 years, 10 months, 24 days
219
HYDRAULIC
PRODUCTIONPLANT: BEND:332.00
2.705 15 years, 10 months, 24 days (1)R1.5
220
HYDRAULICPRODUCTIONPLANT: BEND:
333.00
0.798 13 years, 6 months (1)7.14 S0 9 years, 10 months, 24 days
221
HYDRAULICPRODUCTION
PLANT: BEND:
334.00
0.627 36 years, 4 months, 24 days (2)L0
222
HYDRAULIC
PRODUCTION
PLANT: BEND:335.00
0.015 28 years (1)R0.5
223
HYDRAULIC
PRODUCTIONPLANT: BEND:336.00
88 years, 3 months, 18 days (5)S0.5
224
HYDRAULICPRODUCTIONPLANT: BIGFORK: 331.00
0.758 47 years (3)1.75 R1 31 years, 6 months
225
HYDRAULICPRODUCTIONPLANT: BIG
FORK: 332.00
7.834 47 years, 2 months, 12 days (3)1.75 R1.5 31 years, 10 months, 24 days
226
HYDRAULICPRODUCTION
PLANT: BIG
FORK: 333.00
1.57 48 years, 7 months, 6 days (7)1.64 S0 30 years, 6 months
227
HYDRAULIC
PRODUCTION
PLANT: BIGFORK: 334.00
0.933 41 years, 8 months, 12 days (5)2.01 L0 28 years
228
HYDRAULICPRODUCTIONPLANT: BIGFORK: 336.00
0.504 45 years, 1 month, 6 days (5)1.9 S0.5 31 years, 4 months, 24 days
229
HYDRAULICPRODUCTIONPLANT:
CUTLER: 330.20
0.001 59 years, 7 months, 6 days 1.22 SQUARE 45 years, 7 months, 6 days
230
HYDRAULICPRODUCTION
PLANT:
CUTLER: 330.30
0.005 137 years, 8 months, 12 days SQUARE
231
HYDRAULIC
PRODUCTION
PLANT:CUTLER: 330.40
0.091 114 years, 4 months, 24 days SQUARE
232 4.887 64 years, 8 months, 12 days (4)0.6 R1 41 years, 1 month, 6 days
HYDRAULIC
PRODUCTION
PLANT:CUTLER: 331.00
233
HYDRAULIC
PRODUCTIONPLANT:CUTLER: 332.00
10.55 60 years, 6 months (6)0.86 R1.5 42 years, 1 month, 6 days
234
HYDRAULICPRODUCTIONPLANT:CUTLER: 333.00
12.091 52 years, 8 months, 12 days (9)1.2 S0 39 years, 10 months, 24 days
235
HYDRAULICPRODUCTIONPLANT:
CUTLER: 334.00
2.925 46 years, 3 months, 18 days (6)1.32 L0 35 years, 4 months, 24 days
236
HYDRAULICPRODUCTION
PLANT:
CUTLER: 335.00
0.011 61 years, 1 month, 6 days (4)R0.5 35 years, 6 months
237
HYDRAULIC
PRODUCTION
PLANT:CUTLER: 336.00
1.086 61 years (10)0.78 S0.5 41 years, 3 months, 18 days
238
HYDRAULIC
PRODUCTIONPLANT: EAGLEPOINT: 330.20
0.012 83 years, 7 months, 6 days SQUARE
239
HYDRAULICPRODUCTIONPLANT: EAGLE
POINT: 331.00
0.191 37 years, 9 months, 18 days (2)1.58 R1 19 years, 6 months
240
HYDRAULICPRODUCTION
PLANT: EAGLE
POINT: 332.00
1.856 33 years, 4 months, 24 days (2)2.11 R1.5 19 years, 7 months, 6 days
241
HYDRAULIC
PRODUCTION
PLANT: EAGLEPOINT: 333.00
0.473 27 years, 1 month, 6 days (3)3.3 S0 19 years, 7 months, 6 days
242
HYDRAULIC
PRODUCTIONPLANT: EAGLEPOINT: 334.00
0.135 32 years (3)2.03 L0 18 years, 4 months, 24 days
243
HYDRAULICPRODUCTIONPLANT: EAGLEPOINT: 336.00
0.178 31 years, 9 months, 18 days (2)2.3 S0.5 19 years, 7 months, 6 days
244
HYDRAULICPRODUCTIONPLANT:
GRANITE:
331.00
0.548 29 years, 8 months, 12 days (1)2.93 R1 14 years, 8 months, 12 days
245
HYDRAULIC
PRODUCTION
PLANT:GRANITE:332.00
3.773 34 years, 7 months, 6 days (1)2.44 R1.5 14 years, 9 months, 18 days
246
HYDRAULICPRODUCTIONPLANT:
GRANITE:
333.00
0.721 43 years, 1 month, 6 days (3)1.83 S0 14 years, 4 months, 24 days
247
HYDRAULIC
PRODUCTION
PLANT:GRANITE:334.00
0.224 34 years, 6 months (2)2.42 L0 13 years, 10 months, 24 days
248
HYDRAULICPRODUCTIONPLANT:GRANITE:
335.00
0.001 53 years, 2 months, 12 days (1)1.24 R0.5 14 years, 4 months, 24 days
249
HYDRAULICPRODUCTION
PLANT:
KLAMATH:331.00
1.69 20
250 1.493 20
HYDRAULIC
PRODUCTION
PLANT: KLAMATH:332.00
251
HYDRAULICPRODUCTIONPLANT: KLAMATH:
333.00
1.234 20
252
HYDRAULICPRODUCTION
PLANT:
KLAMATH:334.00
0.386 20
253
HYDRAULIC
PRODUCTIONPLANT: KLAMATH:336.00
0.095 20
254
HYDRAULICPRODUCTIONPLANT: LAST
CHANCE:
331.00
0.492 42 years, 6 months (1)1.42 R1 12 years, 8 months, 12 days
255
HYDRAULIC
PRODUCTION
PLANT: LASTCHANCE:332.00
0.958 37 years, 7 months, 6 days (1)1.73 R1.5 12 years, 9 months, 18 days
256
HYDRAULICPRODUCTIONPLANT: LAST
CHANCE:
333.00
1.396 32 years (2)2.53 S0 12 years, 8 months, 12 days
257
HYDRAULIC
PRODUCTION
PLANT: LASTCHANCE:334.00
0.266 28 years, 6 months (2)2.66 L0 12 years, 2 months, 12 days
258
HYDRAULICPRODUCTIONPLANT: LASTCHANCE:
336.00
0.065 48 years, 1 month, 6 days (3)1.16 S0.5 12 years, 7 months, 6 days
259
HYDRAULICPRODUCTION
PLANT: LIFTON:
330.20
0.021 99 years, 9 months, 18 days 1.55 SQUARE 13 years
260
HYDRAULIC
PRODUCTION
PLANT: LIFTON:330.30
0.024 92 years, 9 months, 18 days 1.61 SQUARE 13 years
261
HYDRAULIC
PRODUCTIONPLANT: LIFTON:331.00
1.24 48 years, 3 months, 18 days (2)2.62 R1 12 years, 7 months, 6 days
262
HYDRAULICPRODUCTIONPLANT: LIFTON:332.00
8.279 27 years, 4 months, 24 days (2)4.11 R1.5 12 years, 9 months, 18 days
263
HYDRAULICPRODUCTION
PLANT: LIFTON:
333.00
7.88 20 years, 8 months, 12 days (1)5.13 S0 12 years, 9 months, 18 days
264
HYDRAULIC
PRODUCTION
PLANT: LIFTON:334.00
0.415 16 years, 10 months, 24 days (1)6.28 L0 12 years, 6 months
265
HYDRAULIC
PRODUCTIONPLANT: LIFTON:335.00
0.012 21 years, 7 months, 6 days (1)5.39 R0.5 12 years, 6 months
266
HYDRAULICPRODUCTIONPLANT: LIFTON:336.00
0.187 22 years, 7 months, 6 days (1)4.81 S0.5 12 years, 9 months, 18 days
267 HYDRAULICPRODUCTIONPLANT:
MERWIN:
330.20
0.301 121 years, 7 months, 6 days 0.72 SQUARE 38 years
268
HYDRAULIC
PRODUCTIONPLANT:MERWIN:330.30
0.021 2.03
269
HYDRAULICPRODUCTIONPLANT:
MERWIN:
330.40
0.15 2.63
270
HYDRAULIC
PRODUCTION
PLANT:MERWIN:330.50
0.212 125 years 0.69 SQUARE 38 years
271
HYDRAULICPRODUCTIONPLANT:MERWIN:
331.00
98.204 45 years, 6 months (3)2.25 R1 36 years, 1 month, 6 days
272
HYDRAULICPRODUCTION
PLANT:
MERWIN:332.00
39.053 44 years, 1 month, 6 days (4)2.36 R1.5 36 years, 6 months
273
HYDRAULIC
PRODUCTIONPLANT:MERWIN:333.00
9.302 57 years, 1 month, 6 days (11)1.88 S0 33 years, 9 months, 18 days
274
HYDRAULICPRODUCTION
PLANT:
MERWIN:334.00
10.458 40 years, 1 month, 6 days (5)2.6 L0 31 years, 10 months, 24 days
275
HYDRAULIC
PRODUCTIONPLANT:MERWIN:335.00
0.169 47 years, 4 months, 24 days (3)2.12 R0.5 33 years
276
HYDRAULICPRODUCTIONPLANT:
MERWIN:
336.00
4.253 44 years, 2 months, 12 days (5)2.39 S0.5 36 years, 2 months, 12 days
277
HYDRAULIC
PRODUCTION
PLANT: NORTHUMPQUA:331.00
36.751 31 years, 1 month, 6 days (1)3.48 R1 17 years, 7 months, 6 days
278
HYDRAULICPRODUCTIONPLANT: NORTHUMPQUA:
332.00
202.738 30 years, 9 months, 18 days (2)3.7 R1.5 17 years, 8 months, 12 days
279
HYDRAULICPRODUCTION
PLANT: NORTH
UMPQUA:333.00
25.961 32 years, 3 months, 18 days (3)3.55 S0 17 years, 3 months, 18 days
280
HYDRAULIC
PRODUCTIONPLANT: NORTHUMPQUA:
334.00
20.154 27 years, 2 months, 12 days (2)4.05 L0 16 years, 8 months, 12 days
281
HYDRAULICPRODUCTION
PLANT: NORTH
UMPQUA:335.00
0.722 36 years, 2 months, 12 days (1)3.22 R0.5 16 years, 9 months, 18 days
282
HYDRAULIC
PRODUCTIONPLANT: NORTHUMPQUA:336.00
10.016 32 years, 10 months, 24 days (3)3.59 S0.5 17 years, 6 months
283
HYDRAULICPRODUCTIONPLANT: PARIS:
331.00
0.11 18 years, 2 months, 12 days R1
284 0.113 29 years, 10 months, 24 days (1)0.15 R1.5 4 years
HYDRAULIC
PRODUCTION
PLANT: PARIS:332.00
285
HYDRAULIC
PRODUCTIONPLANT: PARIS:333.00
0.372 39 years, 2 months, 12 days (1)0.07 S0 3 years, 10 months, 24 days
286
HYDRAULICPRODUCTIONPLANT: PARIS:334.00
0.162 21 years L0
287
HYDRAULICPRODUCTIONPLANT: PARIS:
335.00
40 years, 8 months, 12 days R0.5
288
HYDRAULICPRODUCTION
PLANT:
PIONEER:330.20
0.009 134 years 1.15 SQUARE 10 years
289
HYDRAULIC
PRODUCTIONPLANT:PIONEER:330.30
0.111 133 years, 3 months, 18 days 1.15 SQUARE 10 years
290
HYDRAULICPRODUCTIONPLANT:
PIONEER:
331.00
1.133 23 years, 7 months, 6 days (1)4.59 R1 9 years, 10 months, 24 days
291
HYDRAULIC
PRODUCTIONPLANT:PIONEER:332.00
8.203 25 years, 10 months, 24 days (1)4.25 R1.5 9 years, 10 months, 24 days
292
HYDRAULICPRODUCTIONPLANT:
PIONEER:
333.00
1.616 24 years, 7 months, 6 days (1)4.32 S0 9 years, 9 months, 18 days
293
HYDRAULIC
PRODUCTION
PLANT:PIONEER:334.00
1.066 20 years, 9 months, 18 days (1)5.48 L0 9 years, 7 months, 6 days
294
HYDRAULICPRODUCTIONPLANT:PIONEER:
335.00
0.01 39 years (1)2.93 R0.5 9 years, 7 months, 6 days
295
HYDRAULICPRODUCTION
PLANT:
PIONEER:336.00
0.061 20 years (1)5.25 S0.5 9 years, 10 months, 24 days
296
HYDRAULIC
PRODUCTIONPLANT:PROSPECT # 1,2 AND 4: 330.20
0.004 56 years, 2 months, 12 days 2.07 SQUARE 18 years
297
HYDRAULICPRODUCTION
PLANT:
PROSPECT # 1,2 AND 4: 330.40
0.003 102 years, 2 months, 12 days 1.36 SQUARE 18 years
298
HYDRAULIC
PRODUCTIONPLANT:PROSPECT # 1,2 AND 4: 331.00
6.752 28 years, 1 month, 6 days (1)3.9 R1 17 years, 7 months, 6 days
299
HYDRAULICPRODUCTIONPLANT:
PROSPECT # 1,
2 AND 4: 332.00
37.482 30 years, 6 months (1)3.5 R1.5 17 years, 8 months, 12 days
300
HYDRAULIC
PRODUCTION
PLANT:PROSPECT # 1,2 AND 4: 333.00
4.219 32 years, 3 months, 18 days (3)3.41 S0 17 years, 4 months, 24 days
301 6.791 26 years, 8 months, 12 days (2)4.09 L0 16 years, 8 months, 12 days
HYDRAULIC
PRODUCTION
PLANT:PROSPECT # 1,2 AND 4: 334.00
302
HYDRAULICPRODUCTIONPLANT:PROSPECT # 1,
2 AND 4: 335.00
0.019 35 years, 2 months, 12 days (1)3.11 R0.5 16 years, 10 months, 24 days
303
HYDRAULICPRODUCTION
PLANT:
PROSPECT # 1,2 AND 4: 336.00
0.697 22 years, 10 months, 24 days (2)4.68 S0.5 17 years, 9 months, 18 days
304
HYDRAULIC
PRODUCTIONPLANT:PROSPECT #3:331.00
0.719 50 years, 10 months, 24 days (3)0.8 R1 36 years, 1 month, 6 days
305
HYDRAULICPRODUCTIONPLANT:
PROSPECT #3:
332.00
4.748 61 years, 1 month, 6 days (5)0.11 R1.5 36 years, 8 months, 12 days
306
HYDRAULIC
PRODUCTION
PLANT:PROSPECT #3:333.00
1.928 55 years, 1 month, 6 days (9)0.32 S0 34 years, 10 months, 24 days
307
HYDRAULICPRODUCTIONPLANT:
PROSPECT #3:
334.00
1.887 41 years, 1 month, 6 days (5)1.53 L0 31 years, 10 months, 24 days
308
HYDRAULIC
PRODUCTION
PLANT:PROSPECT #3:335.00
0.063 54 years, 4 months, 24 days (3)0.09 R0.5 32 years, 4 months, 24 days
309
HYDRAULICPRODUCTIONPLANT:PROSPECT #3:
336.00
0.269 43 years, 6 months (6)1.84 S0.5 36 years, 8 months, 12 days
310
HYDRAULICPRODUCTION
PLANT: SANTA
CLARA: 331.00
0.18 28 years, 4 months, 24 days R1
311
HYDRAULIC
PRODUCTION
PLANT: SANTACLARA: 332.00
1.341 29 years, 4 months, 24 days R1.5
312
HYDRAULIC
PRODUCTIONPLANT: SANTACLARA: 333.00
0.464 30 years, 1 month, 6 days (1)S0
313
HYDRAULICPRODUCTIONPLANT: SANTACLARA: 334.00
0.707 23 years, 3 months, 18 days 0.76 L0 3 years, 10 months, 24 days
314
HYDRAULICPRODUCTION
PLANT: SANTA
CLARA: 335.00
0.008 35 years, 6 months R0.5
315
HYDRAULIC
PRODUCTION
PLANT: SANTACLARA: 336.00
0.022 13 years, 10 months, 24 days 9.53 S0.5 4 years
316
HYDRAULIC
PRODUCTIONPLANT: STAIRS:331.00
0.181 39 years (1)2.49 R1 9 years, 9 months, 18 days
317
HYDRAULICPRODUCTIONPLANT: STAIRS:332.00
1.051 19 years, 7 months, 6 days (1)5.44 R1.5 9 years, 10 months, 24 days
318
HYDRAULICPRODUCTIONPLANT: STAIRS:
333.00
0.519 35 years, 8 months, 12 days (2)2.75 S0 9 years, 8 months, 12 days
319 HYDRAULIC
PRODUCTION
PLANT: STAIRS:334.00
0.177 24 years, 7 months, 6 days (1)4.35 L0 9 years, 7 months, 6 days
320
HYDRAULIC
PRODUCTIONPLANT: STAIRS:336.00
0.033 12 years, 3 months, 18 days 8.59 S0.5 10 years
321
HYDRAULICPRODUCTIONPLANT: SWIFT:330.20
6.277 99 years, 8 months, 12 days 0.98 SQUARE 38 years
322
HYDRAULICPRODUCTIONPLANT: SWIFT:
330.50
0.097 98 years 1 SQUARE 38 years
323
HYDRAULICPRODUCTION
PLANT: SWIFT:
331.00
75.307 45 years, 1 month, 6 days (3)2.28 R1 36 years, 1 month, 6 days
324
HYDRAULIC
PRODUCTION
PLANT: SWIFT:332.00
49.423 64 years, 9 months, 18 days (6)1.62 R1.5 35 years, 8 months, 12 days
325
HYDRAULIC
PRODUCTIONPLANT: SWIFT:333.00
17.198 55 years, 2 months, 12 days (10)2.02 S0 34 years
326
HYDRAULICPRODUCTIONPLANT: SWIFT:
334.00
8.08 42 years, 4 months, 24 days (5)2.49 L0 31 years, 4 months, 24 days
327
HYDRAULICPRODUCTION
PLANT: SWIFT:
335.00
0.41 64 years, 7 months, 6 days (5)1.61 R0.5 29 years, 4 months, 24 days
328
HYDRAULIC
PRODUCTION
PLANT: SWIFT:336.00
1.303 50 years, 7 months, 6 days (6)2.09 S0.5 35 years, 7 months, 6 days
329
HYDRAULIC
PRODUCTIONPLANT: VIVANAUGHTON:331.00
0.403 39 years, 1 month, 6 days (1)4.26 R1 8 years, 10 months, 24 days
330
HYDRAULICPRODUCTIONPLANT: VIVA
NAUGHTON:
332.00
0.104 41 years (1)4.16 R1.5 8 years, 10 months, 24 days
331
HYDRAULIC
PRODUCTION
PLANT: VIVANAUGHTON:333.00
0.497 38 years, 10 months, 24 days (2)4.36 S0 8 years, 9 months, 18 days
332
HYDRAULICPRODUCTIONPLANT: VIVANAUGHTON:
334.00
0.207 27 years, 9 months, 18 days (1)5.33 L0 8 years, 7 months, 6 days
333
HYDRAULIC
PRODUCTION
PLANT: VIVANAUGHTON:335.00
0.021 38 years, 3 months, 18 days (1)4.34 R0.5 8 years, 8 months, 12 days
334
HYDRAULICPRODUCTIONPLANT:WALLOWA
FALLS: 331.00
0.168 58 years, 9 months, 18 days (3)R1
335
HYDRAULICPRODUCTION
PLANT:
WALLOWAFALLS: 332.00
2.597 44 years, 7 months, 6 days (4)1.41 R1.5 35 years, 9 months, 18 days
336
HYDRAULIC
PRODUCTIONPLANT:WALLOWAFALLS: 333.00
0.807 53 years (8)S0
337 1.334 46 years, 2 months, 12 days (6)L0
HYDRAULIC
PRODUCTION
PLANT:WALLOWAFALLS: 334.00
338
HYDRAULICPRODUCTIONPLANT:WALLOWA
FALLS: 336.00
0.649 48 years, 1 month, 6 days (6)0.74 S0.5 35 years, 6 months
339
HYDRAULICPRODUCTION
PLANT: WEBER:
331.00
0.387 67 years, 4 months, 24 days (4)0.4 R1 37 years, 7 months, 6 days
340
HYDRAULIC
PRODUCTION
PLANT: WEBER:332.00
1.999 60 years, 1 month, 6 days (6)0.79 R1.5 38 years, 4 months, 24 days
341
HYDRAULIC
PRODUCTIONPLANT: WEBER:333.00
1.121 60 years (11)0.67 S0 36 years, 1 month, 6 days
342
HYDRAULICPRODUCTIONPLANT: WEBER:334.00
0.321 44 years, 10 months, 24 days (6)1.04 L0 33 years, 2 months, 12 days
343
HYDRAULICPRODUCTIONPLANT: WEBER:
335.00
0.022 57 years, 6 months (4)0.6 R0.5 33 years, 3 months, 18 days
344
HYDRAULIC
PRODUCTION
PLANT: WEBER:336.00
0.04 60 years, 9 months, 18 days (8)0.7 S0.5 36 years, 4 months, 24 days
345
HYDRAULIC
PRODUCTIONPLANT: YALE:330.20
0.762 103 years, 9 months, 18 days 0.8 SQUARE 38 years
346
HYDRAULICPRODUCTIONPLANT: YALE:331.00
18.212 47 years, 10 months, 24 days (3)2.14 R1 36 years
347
HYDRAULICPRODUCTIONPLANT: YALE:
332.00
35.017 72 years, 8 months, 12 days (7)1.32 R1.5 35 years, 3 months, 18 days
348
HYDRAULICPRODUCTION
PLANT: YALE:
333.00
14.13 55 years (10)1.9 S0 34 years, 1 month, 6 days
349
HYDRAULIC
PRODUCTION
PLANT: YALE:334.00
3.976 46 years, 2 months, 12 days (6)2.2 L0 30 years, 9 months, 18 days
350
HYDRAULIC
PRODUCTIONPLANT: YALE:335.00
0.75 65 years, 1 month, 6 days (5)1.41 R0.5 28 years, 9 months, 18 days
351
HYDRAULICPRODUCTIONPLANT: YALE:
336.00
2.194 51 years, 1 month, 6 days (6)2.02 S0.5 35 years, 6 months
352
OTHERPRODUCTION
PLANT:
CHEHALIS:341.00
24.483 39 years (3)2.89 S2.5 22 years, 7 months, 6 days
353
OTHER
PRODUCTIONPLANT:CHEHALIS:342.00
1.597 36 years, 6 months (3)3.11 R2 20 years, 8 months, 12 days
354
OTHERPRODUCTIONPLANT:
CHEHALIS:
343.00
215.612 28 years, 2 months, 12 days (5)4.12 L0 18 years, 2 months, 12 days
355 70.184 36 years, 8 months, 12 days (5)3.14 R2.5 21 years
OTHER
PRODUCTION
PLANT:CHEHALIS:344.00
356
OTHERPRODUCTIONPLANT:CHEHALIS:
345.00
38.563 38 years, 10 months, 24 days (2)2.87 R3 22 years, 4 months, 24 days
357
OTHERPRODUCTION
PLANT:
CHEHALIS:346.00
3.269 38 years, 7 months, 6 days (2)2.91 R3 22 years
358
OTHER
PRODUCTIONPLANT:CURRANTCREEK: 341.00
44.268 39 years, 9 months, 18 days (3)3.07 S2.5 24 years, 6 months
359
OTHERPRODUCTIONPLANT:
CURRANT
CREEK: 342.00
3.3 36 years, 6 months (3)3.36 R2 22 years, 6 months
360
OTHER
PRODUCTION
PLANT:CURRANTCREEK: 343.00
199.114 28 years, 8 months, 12 days (6)4.35 L0 19 years, 4 months, 24 days
361
OTHERPRODUCTIONPLANT:
CURRANT
CREEK: 344.00
64.063 36 years, 8 months, 12 days (5)3.37 R2.5 22 years, 10 months, 24 days
362
OTHER
PRODUCTION
PLANT:CURRANTCREEK: 345.00
42.994 38 years, 8 months, 12 days (2)3.09 R3 24 years, 3 months, 18 days
363
OTHERPRODUCTIONPLANT:CURRANT
CREEK: 346.00
2.983 38 years, 10 months, 24 days (2)3.11 R3 23 years, 10 months, 24 days
364
OTHERPRODUCTION
PLANT:
HERMISTON:341.00
12.845 37 years (3)2.91 S2.5 15 years, 8 months, 12 days
365
OTHER
PRODUCTIONPLANT:HERMISTON:342.00
0.22 36 years, 6 months (2)2.91 R2 14 years, 7 months, 6 days
366
OTHERPRODUCTIONPLANT:
HERMISTON:
343.00
116.87 26 years, 4 months, 24 days (4)4.19 L0 13 years, 6 months
367
OTHER
PRODUCTION
PLANT:HERMISTON:344.00
43.35 35 years (4)3.11 R2.5 14 years, 9 months, 18 days
368
OTHERPRODUCTIONPLANT:
HERMISTON:
345.00
9.768 37 years (2)2.88 R3 15 years, 7 months, 6 days
369
OTHER
PRODUCTION
PLANT:HERMISTON:346.00
0.213 27 years, 7 months, 6 days (2)3.96 R3 15 years, 7 months, 6 days
370
OTHERPRODUCTIONPLANT: LAKESIDE UNIT 1:
341.00
2.597 38 years, 3 months, 18 days (3)3.11 S2.5 26 years, 7 months, 6 days
371 212.019 28 years, 1 month, 6 days (6)4.35 L0 20 years, 10 months, 24 days
OTHER
PRODUCTION
PLANT: LAKESIDE UNIT 1:343.00
372
OTHERPRODUCTIONPLANT: LAKESIDE UNIT 1:
344.00
69.509 37 years (5)3.36 R2.5 24 years, 8 months, 12 days
373
OTHERPRODUCTION
PLANT: LAKE
SIDE UNIT 1:345.00
44.606 39 years, 2 months, 12 days (3)3.1 R3 26 years, 3 months, 18 days
374
OTHER
PRODUCTIONPLANT: LAKESIDE UNIT 1:346.00
2.451 39 years, 1 month, 6 days (2)3.11 R3 25 years, 9 months, 18 days
375
OTHERPRODUCTIONPLANT: LAKE
SIDE UNIT 2:
341.00
86.143 41 years, 2 months, 12 days (3)2.48 S2.5 33 years, 3 months, 18 days
376
OTHER
PRODUCTION
PLANT: LAKESIDE UNIT 2:342.00
8.506 38 years, 3 months, 18 days (3)2.66 R2 30 years
377
OTHERPRODUCTIONPLANT: LAKE
SIDE UNIT 2:
343.00
333.597 29 years, 9 months, 18 days (6)3.62 L0 25 years, 1 month, 6 days
378
OTHER
PRODUCTION
PLANT: LAKESIDE UNIT 2:344.00
157.58 37 years, 3 months, 18 days (5)2.79 R2.5 31 years, 2 months, 12 days
379
OTHERPRODUCTIONPLANT: LAKESIDE UNIT 2:
345.00
75.362 39 years, 6 months (2)2.57 R3 33 years, 1 month, 6 days
380
OTHERPRODUCTION
PLANT: LAKE
SIDE UNIT 2:346.00
3.702 40 years (1)2.5 R3 32 years, 6 months
381
OTHER
PRODUCTIONPLANT:GADBSYPEAKER UNIT
4-6: 341.00
4.273 29 years, 8 months, 12 days (2)3.9 S2.5 11 years, 10 months, 24 days
382
OTHERPRODUCTION
PLANT:
GADBSYPEAKER UNIT4-6: 342.00
2.789 21 years, 9 months, 18 days (2)5.27 R2 11 years, 7 months, 6 days
383
OTHERPRODUCTIONPLANT:
GADBSY
PEAKER UNIT4-6: 343.00
57.995 22 years, 8 months, 12 days (4)5.01 R1 11 years, 4 months, 24 days
384
OTHER
PRODUCTIONPLANT:GADBSYPEAKER UNIT
4-6: 344.00
17.8 25 years, 6 months (2)4.48 R2.5 11 years, 7 months, 6 days
385
OTHERPRODUCTION
PLANT:
GADBSYPEAKER UNIT4-6: 345.00
2.901 27 years, 3 months, 18 days (2)4.19 R3 11 years, 10 months, 24 days
386 8.144 37 years, 9 months, 18 days (1)2.33 R2 28 years, 2 months, 12 days
OTHER
PRODUCTION
PLANT:DUNLAP -WIND: 341.00
387
OTHERPRODUCTIONPLANT:DUNLAP -
WIND: 343.00
179.959 31 years, 10 months, 24 days (1)5.34 R2.5 28 years, 4 months, 24 days
388
OTHERPRODUCTION
PLANT:
DUNLAP -WIND: 344.00
10.06 26 years, 7 months, 6 days (2)7.72 S0 25 years, 10 months, 24 days
389
OTHER
PRODUCTIONPLANT:DUNLAP -WIND: 345.00
12.333 36 years, 8 months, 12 days (1)2.43 S0.5 27 years, 1 month, 6 days
390
OTHERPRODUCTIONPLANT:
DUNLAP -
WIND: 346.00
0.158 37 years 2.46 R3 28 years, 10 months, 24 days
391
OTHER
PRODUCTION
PLANT: FOOTECREEK - WIND:340.20
5.656 3.2
392
OTHERPRODUCTIONPLANT: FOOTE
CREEK - WIND:
341.00
2.364 30 years, 8 months, 12 days (1)4.94 R2 28 years, 9 months, 18 days
393
OTHER
PRODUCTION
PLANT: FOOTECREEK - WIND:343.00
64.986 29 years, 8 months, 12 days (1)4.11 R2.5 28 years, 10 months, 24 days
394
OTHERPRODUCTIONPLANT: FOOTECREEK - WIND:
344.00
3.601 26 years, 9 months, 18 days (2)5.52 S0 25 years, 10 months, 24 days
395
OTHERPRODUCTION
PLANT: FOOTE
CREEK - WIND:345.00
3.431 30 years (1)5.01 S0.5 28 years, 3 months, 18 days
396
OTHER
PRODUCTIONPLANT: FOOTECREEK - WIND:346.00
0.49 4.2
397
OTHERPRODUCTIONPLANT:
GLENROCK /
ROLLINGHILLS- WIND:340.20
0.023 3.39
398
OTHERPRODUCTIONPLANT:
GLENROCK /
ROLLINGHILLS- WIND:341.00
10.739 36 years, 6 months (1)2.39 R2 27 years, 4 months, 24 days
399
OTHERPRODUCTIONPLANT:GLENROCK /
ROLLING
HILLS- WIND:343.00
408.124 32 years, 4 months, 24 days (1)4.26 R2.5 27 years, 6 months
400
OTHER
PRODUCTIONPLANT:GLENROCK /ROLLING
HILLS- WIND:
344.00
19.781 27 years, 4 months, 24 days (2)5.94 S0 24 years, 3 months, 18 days
401 29.91 36 years, 8 months, 12 days (1)2.34 S0.5 26 years, 2 months, 12 days
OTHER
PRODUCTION
PLANT:GLENROCK /ROLLINGHILLS- WIND:
345.00
402
OTHERPRODUCTION
PLANT:
GLENROCK /ROLLINGHILLS- WIND:346.00
1.666 31 years, 9 months, 18 days 3.02 R3 28 years, 4 months, 24 days
403
OTHERPRODUCTIONPLANT:
GOODNOE
HILLS - WIND:341.00
5.519 38 years, 8 months, 12 days (1)2.21 R2 27 years, 2 months, 12 days
404
OTHER
PRODUCTIONPLANT:GOODNOEHILLS - WIND:
343.00
131.825 31 years, 4 months, 24 days (1)5.83 R2.5 27 years, 6 months
405
OTHERPRODUCTION
PLANT:
GOODNOEHILLS - WIND:344.00
6.823 26 years, 6 months (2)7.1 S0 25 years, 1 month, 6 days
406
OTHERPRODUCTIONPLANT:
GOODNOE
HILLS - WIND:345.00
8.78 34 years, 3 months, 18 days (1)3.89 S0.5 26 years, 6 months
407
OTHER
PRODUCTIONPLANT:GOODNOEHILLS - WIND:
346.00
0.332 37 years, 10 months, 24 days 2.33 R3 27 years, 10 months, 24 days
408
OTHERPRODUCTION
PLANT: HIGH
PLAINS /MCFADDENRIDGE I- WIND:341.00
8.119 37 years, 10 months, 24 days (1)2.28 R2 27 years, 3 months, 18 days
409
OTHERPRODUCTIONPLANT: HIGH
PLAINS /
MCFADDENRIDGE I- WIND:343.00
205.447 31 years, 9 months, 18 days (1)5.47 R2.5 27 years, 6 months
410
OTHERPRODUCTIONPLANT: HIGHPLAINS /
MCFADDEN
RIDGE I- WIND:344.00
11.342 26 years, 7 months, 6 days (2)7.5 S0 25 years
411
OTHERPRODUCTIONPLANT: HIGHPLAINS /
MCFADDEN
RIDGE I- WIND:345.00
14.763 36 years, 8 months, 12 days (1)2.39 S0.5 26 years, 2 months, 12 days
412
OTHER
PRODUCTIONPLANT: HIGHPLAINS /MCFADDEN
RIDGE I- WIND:
346.00
0.114 35 years, 10 months, 24 days 2.54 R3 28 years, 1 month, 6 days
413
OTHER
PRODUCTION
PLANT:LEANINGJUNIPER -WIND: 341.00
4.998 40 years, 1 month, 6 days (1)2 R2 27 years, 1 month, 6 days
414 151.934 33 years, 8 months, 12 days (1)4.96 R2.5 27 years, 2 months, 12 days
OTHER
PRODUCTION
PLANT:LEANINGJUNIPER -WIND: 343.00
415
OTHERPRODUCTIONPLANT:
LEANING
JUNIPER -WIND: 344.00
8.559 26 years, 7 months, 6 days (2)9.48 S0 25 years
416
OTHER
PRODUCTIONPLANT:LEANINGJUNIPER -
WIND: 345.00
9.507 38 years, 2 months, 12 days (2)2.43 S0.5 25 years, 10 months, 24 days
417
OTHERPRODUCTION
PLANT:
LEANINGJUNIPER -WIND: 346.00
0.081 37 years (1)2.4 R3 27 years, 10 months, 24 days
418
OTHERPRODUCTIONPLANT:MARENGO -
WIND: 341.00
10.595 39 years, 1 month, 6 days (1)2.06 R2 27 years, 2 months, 12 days
419
OTHERPRODUCTION
PLANT:
MARENGO -WIND: 343.00
273.084 31 years, 7 months, 6 days (1)4.98 R2.5 27 years, 6 months
420
OTHERPRODUCTIONPLANT:MARENGO -
WIND: 344.00
16.498 26 years, 8 months, 12 days (2)6.72 S0 25 years
421
OTHERPRODUCTION
PLANT:
MARENGO -WIND: 345.00
19.624 37 years, 6 months (2)2.77 S0.5 26 years, 1 month, 6 days
422
OTHER
PRODUCTIONPLANT:MARENGO -WIND: 346.00
0.352 37 years, 10 months, 24 days 2.24 R3 27 years, 10 months, 24 days
423
OTHERPRODUCTIONPLANT: SEVEN
MILE HILL I and
II - WIND:341.00
6.522 38 years, 3 months, 18 days (1)2.28 R2 27 years, 3 months, 18 days
424
OTHER
PRODUCTIONPLANT: SEVENMILE HILL I andII - WIND:
343.00
194.059 31 years, 10 months, 24 days (1)5.23 R2.5 27 years, 6 months
425
OTHERPRODUCTION
PLANT: SEVEN
MILE HILL I andII - WIND:344.00
10.834 26 years, 7 months, 6 days (2)7.4 S0 25 years, 1 month, 6 days
426
OTHERPRODUCTIONPLANT: SEVEN
MILE HILL I and
II - WIND:345.00
13.035 37 years, 1 month, 6 days (1)2.36 S0.5 26 years, 1 month, 6 days
427
OTHER
PRODUCTIONPLANT: SEVENMILE HILL I andII - WIND:
346.00
0.804 36 years, 2 months, 12 days 2.54 R3 28 years
428
OTHERPRODUCTION
PLANT: PRYOR
MOUNTAIN -WIND: 341.00
19.427 3.45
429 OTHER
PRODUCTION
PLANT: PRYORMOUNTAIN -WIND: 343.00
316.833 3.45
430
OTHERPRODUCTIONPLANT: PRYORMOUNTAIN -
WIND: 344.00
18.799 3.45
431
OTHERPRODUCTION
PLANT: PRYOR
MOUNTAIN -WIND: 345.00
28.316 3.45
432
OTHER
PRODUCTIONPLANT: PRYORMOUNTAIN -WIND: 346.00
1.511 3.45
433
OTHERPRODUCTIONPLANT: TB
FLATS - WIND:
341.00
8.375 29 years, 3 months, 18 days (1)3.44 R2 28 years, 10 months, 24 days
434
OTHER
PRODUCTION
PLANT: TBFLATS - WIND:343.00
505.423 29 years, 4 months, 24 days (1)3.43 R2.5 28 years, 10 months, 24 days
435
OTHERPRODUCTIONPLANT: TB
FLATS - WIND:
344.00
31.065 26 years, 6 months (2)3.85 S0 26 years
436
OTHER
PRODUCTION
PLANT: TBFLATS - WIND:345.00
44.86 29 years (1)3.49 S0.5 28 years, 6 months
437
OTHERPRODUCTIONPLANT: TBFLATS - WIND:
346.00
2.789 29 years, 10 months, 24 days 3.34 R3 29 years, 6 months
438
OTHERPRODUCTION
PLANT: EKOLA
FLATS - WIND:341.00
6.94 29 years, 3 months, 18 days (2)3.47 R2 28 years, 10 months, 24 days
439
OTHER
PRODUCTIONPLANT: EKOLAFLATS - WIND:343.00
258.122 29 years, 4 months, 24 days (2)3.47 R2.5 28 years, 10 months, 24 days
440
OTHERPRODUCTIONPLANT: EKOLA
FLATS - WIND:
344.00
15.859 26 years, 6 months (2)3.85 S0 26 years
441
OTHER
PRODUCTION
PLANT: EKOLAFLATS - WIND:345.00
27.131 29 years (2)3.53 S0.5 28 years, 6 months
442
OTHERPRODUCTIONPLANT: EKOLA
FLATS - WIND:
346.00
2.014 29 years, 10 months, 24 days (1)3.37 R3 29 years, 6 months
443
OTHER
PRODUCTION
PLANT: CEDARSPRINGS -WIND: 341.00
5.834 29 years, 3 months, 18 days (1)3.44 R2 28 years, 10 months, 24 days
444
OTHERPRODUCTIONPLANT: CEDARSPRINGS -
WIND: 343.00
200.928 29 years, 4 months, 24 days (1)3.43 R2.5 28 years, 10 months, 24 days
445 12.297 26 years, 6 months (2)3.85 S0 26 years
OTHER
PRODUCTION
PLANT: CEDARSPRINGS -WIND: 344.00
446
OTHERPRODUCTIONPLANT: CEDARSPRINGS -
WIND: 345.00
29.391 29 years (1)3.49 S0.5 28 years, 6 months
447
OTHERPRODUCTION
PLANT: CEDAR
SPRINGS -WIND: 346.00
1.523 29 years, 10 months, 24 days (1)3.37 R3 29 years, 6 months
448
OTHER
PRODUCTIONPLANT: SOLARPLANT &BATTERY
STORAGE:
341.00
0.073 (2)4.21 R3
449
OTHER
PRODUCTION
PLANT: SOLARPLANT &BATTERYSTORAGE:
344.00
0.285 (2)4.65 S2.5
450
OTHERPRODUCTION
PLANT: SOLARPLANT &BATTERYSTORAGE:
345.00
0.081 4.63 S2
451
OTHERPRODUCTION
PLANT: SOLAR
PLANT &BATTERYSTORAGE:346.00
4
452
OTHERPRODUCTIONPLANT: SOLAR
PLANT &
BATTERYSTORAGE:348.00
(5)7.24 L3
453
OTHERPRODUCTIONPLANT:ATLANTIC CITY:
344.00
0.006 20 years, 6 months 4.11 SQUARE 7 years
454
OTHERPRODUCTION
PLANT:
CANYONLANDS: 344.00
0.036 SQUARE
455
OTHER
PRODUCTIONPLANT: GREENRIVER: 344.00
0.055 SQUARE
456
OTHERPRODUCTIONPLANT:
OREGON HIGH
DESERT: 344.00
0.056 R2.5
457
OTHER
PRODUCTION
PLANT: MOBILEGENERATORS -EAST SIDE:344.00
1.917 50 years 1.43 R2.5 35 years, 10 months, 24 days
458
OTHERPRODUCTIONPLANT: MOBILE
GENERATORS -
WEST SIDE:344.00
0.849 50 years 1.64 R2.5 39 years, 4 months, 24 days
459 TRANSMISSION
PLANT: 360.20 252.089 90 years 1.06 R4 74 years, 9 months, 18 days
460 355.459 75 years (5)1.36 R2.5 63 years, 10 months, 24 days
TRANSMISSION
PLANT: 352.00
461 TRANSMISSIONPLANT: 353.00 2,514.023 60 years (10)1.78 S0 49 years, 1 month, 6 days
462 TRANSMISSIONPLANT: 354.00 1,498.22 72 years (8)1.44 R4 59 years, 3 months, 18 days
463 TRANSMISSIONPLANT: 355.00 1,217.838 62 years (40)2.15 R2.5 49 years, 9 months, 18 days
464 TRANSMISSION
PLANT: 356.00 1,600.613 68 years (30)1.81 R2.5 54 years, 2 months, 12 days
465 TRANSMISSION
PLANT: 357.00 3.858 60 years 1.55 S2.5 40 years, 7 months, 6 days
466 TRANSMISSIONPLANT: 358.00 9.08 60 years (5)1.61 S2.5 40 years, 10 months, 24 days
467 TRANSMISSIONPLANT: 359.00 12.142 75 years 1.21 R5 47 years
468
DISTRIBUTIONPLANT:OREGON -DISTRIBUTION:
360.20
5.275 70 years 1.15 S1.5 46 years, 7 months, 6 days
469
DISTRIBUTIONPLANT:
OREGON -
DISTRIBUTION:361.00
32.781 67 years (10)1.54 R2 55 years, 10 months, 24 days
470
DISTRIBUTION
PLANT:OREGON -DISTRIBUTION:
362.00
265.89 53 years (20)2.04 R1 41 years, 8 months, 12 days
471
DISTRIBUTIONPLANT:
OREGON -
DISTRIBUTION:364.00
475.489 58 years (100)3.13 R1 44 years, 8 months, 12 days
472
DISTRIBUTION
PLANT:OREGON -DISTRIBUTION:365.00
307.232 65 years (50)2.08 R1 48 years, 9 months, 18 days
473
DISTRIBUTIONPLANT:OREGON -
DISTRIBUTION:
366.00
111.333 75 years (45)1.75 R3 56 years, 6 months
474
DISTRIBUTION
PLANT:
OREGON -DISTRIBUTION:367.00
215.988 60 years (35)1.99 R2.5 44 years, 3 months, 18 days
475
DISTRIBUTIONPLANT:OREGON -DISTRIBUTION:
368.00
510.733 46 years (25)2.29 R1.5 32 years
476
DISTRIBUTIONPLANT:
OREGON -
DISTRIBUTION:369.10
108.82 60 years (35)1.98 R2 45 years, 6 months
477
DISTRIBUTIONPLANT:OREGON -DISTRIBUTION:
369.20
224.892 60 years (40)2.09 R4 45 years, 7 months, 6 days
478
DISTRIBUTIONPLANT:
OREGON -
DISTRIBUTION:370.00
99.228 20 years (3)1.71 S3 16 years, 8 months, 12 days
479
DISTRIBUTION
PLANT:OREGON -DISTRIBUTION:371.00
2.663 27 years (50)4.34 L0 16 years, 1 month, 6 days
480 25.151 45 years (30)2.48 R1 32 years, 4 months, 24 days
DISTRIBUTION
PLANT:
OREGON -DISTRIBUTION:373.00
481
DISTRIBUTIONPLANT:WASHINGTON-
DISTRIBUTION:
360.20
0.487 55 years 1.61 R3 38 years, 1 month, 6 days
482
DISTRIBUTION
PLANT:
WASHINGTON- DISTRIBUTION:361.00
8.471 67 years (5)1.52 R2 54 years, 10 months, 24 days
483
DISTRIBUTIONPLANT:WASHINGTON
-
DISTRIBUTION:362.00
83.917 54 years (25)2.22 R1 42 years, 3 months, 18 days
484
DISTRIBUTION
PLANT:WASHINGTON- DISTRIBUTION:
364.00
120.77 56 years (100)3.34 R1.5 40 years, 7 months, 6 days
485
DISTRIBUTIONPLANT:
WASHINGTON
- DISTRIBUTION:365.00
85.72 65 years (65)2.4 R1 49 years, 2 months, 12 days
486
DISTRIBUTIONPLANT:WASHINGTON
-
DISTRIBUTION:366.00
21.464 55 years (40)2.31 R3 36 years, 2 months, 12 days
487
DISTRIBUTION
PLANT:WASHINGTON- DISTRIBUTION:
367.00
34.217 60 years (35)2.1 R3 44 years
488
DISTRIBUTIONPLANT:
WASHINGTON
- DISTRIBUTION:368.00
124.999 46 years (25)2.34 R2 29 years, 10 months, 24 days
489
DISTRIBUTIONPLANT:WASHINGTON-
DISTRIBUTION:
369.10
26.777 62 years (40)2.14 R1 47 years, 4 months, 24 days
490
DISTRIBUTION
PLANT:
WASHINGTON- DISTRIBUTION:369.20
48.348 55 years (45)2.46 R4 38 years, 4 months, 24 days
491
DISTRIBUTIONPLANT:
WASHINGTON
- DISTRIBUTION:370.00
14.659 20 years (3)5.05 S3 10 years, 7 months, 6 days
492
DISTRIBUTIONPLANT:WASHINGTON-
DISTRIBUTION:
371.00
0.515 30 years (40)3.9 L0 13 years, 9 months, 18 days
493
DISTRIBUTION
PLANT:
WASHINGTON- DISTRIBUTION:373.00
3.991 45 years (40)2.93 R0.5 32 years, 3 months, 18 days
494 8.364 50 years 1.78 S4 32 years, 10 months, 24 days
DISTRIBUTION
PLANT:
WYOMING - DISTRIBUTION:360.20
495
DISTRIBUTIONPLANT:WYOMING - DISTRIBUTION:
361.00
20.499 65 years (10)1.64 R2.5 52 years
496
DISTRIBUTIONPLANT:
WYOMING -
DISTRIBUTION:362.00
149.553 57 years (10)1.83 R1 42 years, 6 months
497
DISTRIBUTION
PLANT:WYOMING - DISTRIBUTION:364.00
181.928 57 years (100)3.34 R1 44 years, 10 months, 24 days
498
DISTRIBUTIONPLANT:WYOMING -
DISTRIBUTION:
365.00
129.651 60 years (50)2.39 R0.5 45 years, 8 months, 12 days
499
DISTRIBUTION
PLANT:
WYOMING - DISTRIBUTION:366.00
33.84 45 years (35)2.8 R2.5 33 years
500
DISTRIBUTIONPLANT:WYOMING -
DISTRIBUTION:
367.00
70.134 45 years (30)2.52 R3 29 years, 6 months
501
DISTRIBUTION
PLANT:
WYOMING - DISTRIBUTION:368.00
133.459 42 years (30)2.91 R1 30 years, 9 months, 18 days
502
DISTRIBUTIONPLANT:WYOMING - DISTRIBUTION:
369.10
23.925 60 years (35)2.16 R1.5 45 years, 2 months, 12 days
503
DISTRIBUTIONPLANT:
WYOMING -
DISTRIBUTION:369.20
51.601 50 years (55)2.98 R4 35 years, 10 months, 24 days
504
DISTRIBUTION
PLANT:WYOMING - DISTRIBUTION:370.00
17.369 20 years (3)5.12 S3 10 years, 6 months
505
DISTRIBUTIONPLANT:WYOMING -
DISTRIBUTION:
371.00
0.989 30 years (60)3.55 O1 17 years, 7 months, 6 days
506
DISTRIBUTION
PLANT:
WYOMING - DISTRIBUTION:373.00
10.926 50 years (45)2.73 R0.5 35 years, 10 months, 24 days
507
DISTRIBUTIONPLANT:CALIFORNIA -
DISTRIBUTION:
360.20
1.095 60 years 1.09 R4 25 years, 2 months, 12 days
508
DISTRIBUTION
PLANT:
CALIFORNIA - DISTRIBUTION:361.00
5.252 55 years (5)1.87 R2.5 44 years, 10 months, 24 days
509
DISTRIBUTIONPLANT:CALIFORNIA - DISTRIBUTION:
362.00
30.702 50 years (25)2.44 R1 39 years, 7 months, 6 days
510 86.792 55 years (100)3.48 R1 43 years, 3 months, 18 days
DISTRIBUTION
PLANT:
CALIFORNIA - DISTRIBUTION:364.00
511
DISTRIBUTIONPLANT:CALIFORNIA - DISTRIBUTION:
365.00
42.054 65 years (70)2.47 R1 48 years, 2 months, 12 days
512
DISTRIBUTIONPLANT:
CALIFORNIA -
DISTRIBUTION:366.00
19.037 55 years (45)2.45 R4 35 years, 7 months, 6 days
513
DISTRIBUTION
PLANT:CALIFORNIA - DISTRIBUTION:367.00
21.611 50 years (35)2.51 R3 31 years, 9 months, 18 days
514
DISTRIBUTIONPLANT:CALIFORNIA -
DISTRIBUTION:
368.00
58.556 55 years (35)2.27 R2 38 years, 4 months, 24 days
515
DISTRIBUTION
PLANT:
CALIFORNIA - DISTRIBUTION:369.10
11.353 55 years (30)2.29 R1 41 years, 9 months, 18 days
516
DISTRIBUTIONPLANT:CALIFORNIA -
DISTRIBUTION:
369.20
17.662 60 years (40)2.24 R4 44 years, 2 months, 12 days
517
DISTRIBUTION
PLANT:
CALIFORNIA - DISTRIBUTION:370.00
8.78 20 years (4)3.45 S2.5 9 years, 4 months, 24 days
518
DISTRIBUTIONPLANT:CALIFORNIA - DISTRIBUTION:
371.00
0.281 25 years (50)5.32 L0 12 years, 6 months
519
DISTRIBUTIONPLANT:
CALIFORNIA -
DISTRIBUTION:373.00
0.788 35 years (30)3.52 L0 22 years, 10 months, 24 days
520
DISTRIBUTION
PLANT: UTAH - DISTRIBUTION:360.20
11.268 65 years 1.55 R4 47 years, 7 months, 6 days
521
DISTRIBUTIONPLANT: UTAH - DISTRIBUTION:361.00
62.85 60 years (10)1.86 R2 45 years, 10 months, 24 days
522
DISTRIBUTIONPLANT: UTAH - DISTRIBUTION:
362.00
512.052 50 years (15)2.31 S0 37 years
523
DISTRIBUTION
PLANT: UTAH -
DISTRIBUTION:364.00
444.647 50 years (80)3.62 R0.5 39 years, 4 months, 24 days
524
DISTRIBUTION
PLANT: UTAH - DISTRIBUTION:365.00
273.957 54 years (40)2.59 R0.5 41 years, 4 months, 24 days
525
DISTRIBUTIONPLANT: UTAH - DISTRIBUTION:366.00
240.562 60 years (40)2.34 R2.5 43 years, 10 months, 24 days
526
DISTRIBUTIONPLANT: UTAH - DISTRIBUTION:
367.00
643.643 60 years (15)1.89 R2.5 42 years, 10 months, 24 days
527 DISTRIBUTIONPLANT: UTAH -
DISTRIBUTION:
368.00
619.033 47 years (10)2.36 R1 35 years, 7 months, 6 days
528
DISTRIBUTION
PLANT: UTAH - DISTRIBUTION:369.00
393.786 55 years (25)2.3 R3 41 years, 6 months
529
DISTRIBUTIONPLANT: UTAH - DISTRIBUTION:370.00
104.406 20 years (3)5.88 S3 10 years, 3 months, 18 days
530
DISTRIBUTIONPLANT: UTAH - DISTRIBUTION:
371.00
4.179 25 years (60)6.34 L0 12 years, 9 months, 18 days
531
DISTRIBUTIONPLANT: UTAH -
DISTRIBUTION:
373.00
21.195 25 years (30)5.36 R0.5 13 years, 6 months
532
DISTRIBUTION
PLANT: IDAHO
- DISTRIBUTION:360.20
1.404 60 years 1.54 R4 41 years, 2 months, 12 days
533
DISTRIBUTIONPLANT: IDAHO- DISTRIBUTION:
361.00
4.217 65 years (5)1.52 R3 48 years, 3 months, 18 days
534
DISTRIBUTIONPLANT: IDAHO
-
DISTRIBUTION:362.00
43.48 57 years (15)1.93 R1 44 years, 9 months, 18 days
535
DISTRIBUTIONPLANT: IDAHO- DISTRIBUTION:
364.00
101.855 53 years (90)3.44 R1 42 years, 3 months, 18 days
536
DISTRIBUTIONPLANT: IDAHO
-
DISTRIBUTION:365.00
43.396 54 years (30)2.27 R0.5 40 years, 3 months, 18 days
537
DISTRIBUTION
PLANT: IDAHO- DISTRIBUTION:366.00
12.675 60 years (40)2.23 R2 45 years, 7 months, 6 days
538
DISTRIBUTIONPLANT: IDAHO-
DISTRIBUTION:
367.00
33.233 60 years (15)1.76 R2.5 41 years, 7 months, 6 days
539
DISTRIBUTION
PLANT: IDAHO
- DISTRIBUTION:368.00
89.851 47 years (10)2.19 R1 34 years, 2 months, 12 days
540
DISTRIBUTIONPLANT: IDAHO- DISTRIBUTION:
369.00
49.819 55 years (30)2.26 R3 42 years, 1 month, 6 days
541
DISTRIBUTION
PLANT: IDAHO
- DISTRIBUTION:370.00
20.516 20 years (3)4.3 S3 13 years, 6 months
542
DISTRIBUTIONPLANT: IDAHO- DISTRIBUTION:
371.00
0.171 25 years (35)4.42 L0 13 years, 3 months, 18 days
543
DISTRIBUTIONPLANT: IDAHO
-
DISTRIBUTION:373.00
0.843 25 years (20)4.05 R0.5 16 years, 6 months
544
GENERAL
PLANT:OREGON -GENERAL:389.20
0.001 1.82
545 GENERAL
PLANT:
OREGON -GENERAL:390.00
99.093 55 years (15)2.07 R1.5 39 years, 6 months
546
GENERALPLANT:OREGON -GENERAL:
392.01
9.607 14 years 10 6.16 L2.5 7 years, 4 months, 24 days
547
GENERALPLANT:
OREGON -
GENERAL:392.05
15.291 16 years 10 5.3 S2 8 years
548
GENERAL
PLANT:OREGON -GENERAL:392.09
5.013 33 years 10 2.67 S1 19 years, 8 months, 12 days
549
GENERALPLANT:OREGON -
GENERAL:
396.03
14.321 10 years 10 9.07 S3 5 years, 7 months, 6 days
550
GENERAL
PLANT:
OREGON -GENERAL:396.07
33.789 17 years 15 4.83 L1 9 years, 8 months, 12 days
551
GENERALPLANT:WASHINGTON -
GENERAL:
389.20
0.095 2.5
552
GENERAL
PLANT:
WASHINGTON -GENERAL:390.00
13.892 40 years (10)2.06 S3 21 years, 6 months
553
GENERALPLANT:WASHINGTON -GENERAL:
392.01
2.606 14 years 10 2.78 S2 7 years, 6 months
554
GENERALPLANT:
WASHINGTON -
GENERAL:392.05
5.059 19 years 10 3.39 S1 11 years
555
GENERAL
PLANT:WASHINGTON -GENERAL:392.09
1.283 33 years 10 2.28 S0.5 20 years, 1 month, 6 days
556
GENERALPLANT:WASHINGTON -
GENERAL:
396.03
2.989 10 years 10 9.36 S2.5 5 years, 7 months, 6 days
557
GENERAL
PLANT:
WASHINGTON -GENERAL:396.07
7.442 16 years 15 3.78 L1.5 9 years, 9 months, 18 days
558
GENERALPLANT:WYOMING -
GENERAL:
389.20
0.074 55 years 1.87 R4 40 years, 6 months
559
GENERAL
PLANT:
WYOMING -GENERAL:390.00
16.765 55 years (20)2.28 R2 43 years, 7 months, 6 days
560
GENERALPLANT:WYOMING -GENERAL:
392.01
6.578 14 years 10 8.6 S1.5 6 years, 4 months, 24 days
561 10.001 16 years 5 6.79 L2 9 years, 1 month, 6 days
GENERAL
PLANT:
WYOMING -GENERAL:392.05
562
GENERALPLANT:WYOMING -GENERAL:
392.09
5.732 35 years 5 3.03 S2.5 19 years, 7 months, 6 days
563
GENERALPLANT:
WYOMING -
GENERAL:396.03
6.711 9 years 10 14.66 S3 3 years, 9 months, 18 days
564
GENERAL
PLANT:WYOMING -GENERAL:396.07
44.116 15 years 20 5.77 L0 10 years, 7 months, 6 days
565
GENERALPLANT:CALIFORNIA -
GENERAL:
390.00
4.257 60 years (20)1.99 R2 46 years, 6 months
566
GENERAL
PLANT:
CALIFORNIA -GENERAL:392.01
0.943 13 years 10 8.63 S2 7 years, 3 months, 18 days
567
GENERALPLANT:CALIFORNIA -
GENERAL:
392.05
1.744 17 years 10 5.31 L2 8 years
568
GENERAL
PLANT:
CALIFORNIA -GENERAL:392.09
0.657 35 years 5 2.68 S2 20 years, 3 months, 18 days
569
GENERALPLANT:CALIFORNIA -GENERAL:
396.03
2.055 9 years 10 12.21 S4 5 years, 2 months, 12 days
570
GENERALPLANT:
CALIFORNIA -
GENERAL:396.07
4.06 15 years 15 5.59 L2 6 years, 6 months
571
GENERAL
PLANT: UTAH -GENERAL:389.20
0.085 50 years 2.05 R1 34 years, 3 months, 18 days
572
GENERALPLANT: UTAH -GENERAL:390.00
102.476 50 years (20)2.55 R1 33 years, 4 months, 24 days
573
GENERALPLANT: UTAH -GENERAL:
392.01
17.921 13 years 10 8.92 L2.5 6 years, 3 months, 18 days
574
GENERAL
PLANT: UTAH -
GENERAL:392.30
27.351 10 years 20 6.23 SQ 7 years, 10 months, 24 days
575
GENERAL
PLANT: UTAH -GENERAL:392.05
13.264 17 years 5 6.38 L2 9 years, 4 months, 24 days
576
GENERALPLANT: UTAH -GENERAL:392.09
2.993 30 years 10 3.47 S1 16 years, 9 months, 18 days
577
GENERALPLANT: UTAH -GENERAL:
396.03
15.484 10 years 10 10.55 L3 5 years, 9 months, 18 days
578 GENERALPLANT: UTAH -
GENERAL:
396.07
62.71 14 years 20 6.09 L0.5 8 years, 8 months, 12 days
579
GENERAL
PLANT: IDAHO -GENERAL:389.20
0.005 60 years 1.7 R3 22 years, 7 months, 6 days
580
GENERALPLANT: IDAHO -GENERAL:390.00
13.918 60 years (10)1.84 R3 38 years, 4 months, 24 days
581
GENERALPLANT: IDAHO -GENERAL:
392.01
2.782 13 years 10 8.73 S1.5 7 years, 1 month, 6 days
582
GENERALPLANT: IDAHO -
GENERAL:
392.05
5.196 18 years 10 5.19 S1 12 years, 1 month, 6 days
583
GENERAL
PLANT: IDAHO -
GENERAL:392.09
2.479 35 years 15 2.44 S1 24 years, 7 months, 6 days
584
GENERAL
PLANT: IDAHO -GENERAL:396.03
3.573 9 years 10 11.95 S2 4 years, 9 months, 18 days
585
GENERALPLANT: IDAHO -GENERAL:396.07
11.617 18 years 10 5.39 L1 11 years, 2 months, 12 days
586
GENERALPLANT: AZ, CO,
MT, ETC. -
GENERAL:390.00
0.244 45 years (5)1.76 R2 20 years, 3 months, 18 days
587
GENERAL
PLANT: AZ, CO,MT, ETC. -GENERAL:392.01
0.312 17 years 5 3.82 R2.5 8 years
588
GENERALPLANT: AZ, CO,MT, ETC. -
GENERAL:
392.05
0.313 19 years 15 3.5 R2 10 years, 1 month, 6 days
589
GENERAL
PLANT: AZ, CO,
MT, ETC. -GENERAL:392.09
0.018 25 years 1.65 S1.5 9 years, 6 months
590
GENERALPLANT: AZ, CO,MT, ETC. -GENERAL:
396.07
1.146 25 years 10 2.66 R2.5 13 years, 4 months, 24 days
591 GENERALPLANT : ALL
STATES: 391.00
19.692 20 years 5
592 GENERALPLANT : ALL
STATES: 391.20
62.4 5 years 20
593
GENERAL
PLANT : ALL
STATES: 391.30
0.182 8 years 12.5
594
GENERAL
PLANT : ALL
STATES: 393.00
15.485 25 years 4
595
GENERAL
PLANT : ALL
STATES: 394.00
62.749 24 years 4.17
596
GENERAL
PLANT : ALL
STATES: 395.00
36.959 20 years 5
597
GENERAL
PLANT : ALL
STATES: 397.00
450.688 24 years 4.3
598
GENERAL
PLANT : ALL
STATES: 397.20
10.129 11 years 9.09
599 GENERAL
PLANT : ALL
STATES: 398.00
8.329 20 years 5
600
(e)
FERC Sub-
Accounts
601
(f)
Account 403 -
Provisions
FERC FORM NO. 1 (REV. 12-03)Page 336-337
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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, 2021, depreciation expense associated with transportation equipment was $21,897,241.
(b) Concept: DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as a regulatory asset or liability.
(c) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges
The Washington Utilities and Transportation Commission required modifications related to the depreciable lives of coal-fired generating facilities. Below are the affected facilities and the lives and rates required by Washington.
Account No.Depreciable Plant Base (InThousands)Estimated Avg. Service Life Net Salvage (Percent)Applied Depr. Rate(Percent)Mortality Curve Type Average Remaining Life
(a)(b)(c)(d)(e)(f)(g)
STEAM PRODUCTION PLANT
COLSTRIP GENERATING STATION
COLSTRIP PLANT
311.00 68,862 -6.00 16.76 S0.5 3.0
312.00 122,758 -6.00 17.93 L0.5 3.0
314.00 40,007 -6.00 19.23 S0 2.9
315.00 9,720 -6.00 16.22 R2.5 3.0
316.00 435 -5.00 20.88 L0 2.9
JIM BRIDGER GENERATING STATION
311.00 15,425 -4.00 12.75 S0.5 3.0
312.00 177,317 -4.00 17.31 L0.5 3.0
314.00 47,333 -4.00 16.80 S0 3.0
315.00 10,769 -4.00 13.42 R2.5 3.0
316.00 298 -4.00 12.94 L0 2.9
JIM BRIDGER UNIT 2
311.00 13,003 -4.00 14.21 S0.5 3.0
312.00 173,405 -4.00 18.06 L0.5 3.0
314.00 59,894 -4.00 19.05 S0 3.0
315.00 9,329 -4.00 14.64 R2.5 3.0
316.00 198 -4.00 14.75 L0 2.9
JIM BRIDGER UNIT 3
311.00 12,969 -4.00 19.21 S0.5 3.0
312.00 268,993 -4.00 23.09 L0.5 3.0
314.00 44,992 -4.00 20.89 S0 2.9
315.00 8,200 -4.00 20.05 R2.5 3.0
316.00 192 -4.00 18.62 L0 2.9
JIM BRIDGER UNIT 4
311.00 40,518 -4.00 16.82 S0.5 3.0
312.00 302,860 -4.00 23.12 L0.5 3.0
314.00 46,049 -4.00 19.63 S0 2.9
315.00 17,263 -4.00 17.29 R2.5 3.0
316.00 1,249 -4.00 17.42 L0 2.9
JIM BRIDGER COMMON
310.20 281 0.00 14.90 SQUARE 3.0
311.00 68,727 -4.00 19.39 S0.5 3.0
312.00 94,216 -4.00 20.51 L0.5 3.0
314.00 9,504 -4.00 21.62 S0 3.0
315.00 16,656 -4.00 20.34 R2.5 3.0
316.00 3,803 -4.00 25.10 L0 2.9
(d) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges
The Oregon Public Utility Commission required modifications related to the depreciable lives of coal-fired generating facilities. Below are the affected facilities and the lives and rates required by Oregon.
Account No.
Depreciable Plant Base (In
Thousands)Estimated Avg. Service Life Net Salvage (Percent)
Applied Depr. Rate
(Percent)Mortality Curve Type Average Remaining Life
(a)(b)(c)(d)(e)(f)(g)
STEAM PRODUCTION PLANT
COLSTRIP GENERATING STATION
COLSTRIP PLANT
311.00 68,862 -6.00 5.03 S0.5 6.9
312.00 122,758 -7.00 5.81 L0.5 6.7
314.00 40,007 -6.00 6.70 S0 6.7
315.00 9,720 -6.00 4.69 R2.5 6.9
316.00 435 -6.00 8.18 L0 6.6
CRAIG GENERATING STATION
CRAIG UNIT 1
311.00 11,663 -1.00 2.52 S0.5 5.0
312.00 32,691 -2.00 4.15 L0.5 4.9
314.00 12,875 -2.00 6.42 S0 4.9
315.00 6,994 -1.00 2.71 R2.5 4.9
316.00 253 -1.00 3.22 L0 4.7
CRAIG UNIT 2
311.00 11,688 -2.00 3.15 S0.5 5.9
312.00 75,532 -2.00 9.25 L0.5 5.9
314.00 13,266 -2.00 7.13 S0 5.8
315.00 7,367 -1.00 4.50 R2.5 5.9
CRAIG COMMON
311.00 15,247 -1.00 5.84 S0.5 6.0
312.00 29,437 -2.00 6.12 L0.5 5.9
314.00 3,544 -2.00 3.36 S0 5.7
315.00 2,968 -1.00 3.51 R2.5 5.9
316.00 988 -1.00 3.75 L0 5.6
DAVE JOHNSTON GENERATING STATION
DAVE JOHNSTON UNIT 1
311.00 1,432 -3.00 5.82 S0.5 7.0
312.00 57,727 -4.00 4.43 L0.5 6.8
314.00 14,950 -3.00 6.89 S0 6.8
315.00 2,899 -3.00 0.93 R2.5 7.0
316.00 3 -3.00 2.72 L0 6.5
DAVE JOHNSTON UNIT 2
311.00 567 -3.00 4.70 S0.5 7.0
312.00 59,168 -4.00 4.63 L0.5 6.8
314.00 17,273 -4.00 5.77 S0 6.8
315.00 3,396 -3.00 2.65 R2.5 6.9
DAVE JOHNSTON UNIT 3
311.00 19,300 -3.00 3.81 S0.5 7.0
312.00 232,755 -3.00 4.74 L0.5 6.9
314.00 23,494 -4.00 4.32 S0 6.8
315.00 14,832 -3.00 3.96 R2.5 7.0
316.00 240 -3.00 4.34 L0 6.7
DAVE JOHNSTON UNIT 4
311.00 15,443 -3.00 5.01 S0.5 7.0
312.00 237,238 -3.00 5.02 L0.5 6.9
314.00 42,323 -4.00 4.08 S0 6.8
315.00 14,480 -3.00 3.94 R2.5 7.0
316.00 596 -3.00 2.71 L0 6.6
DAVE JOHNSTON COMMON
310.20 100 0.00 0.52 SQUARE 7.0
311.00 132,760 -3.00 3.78 S0.5 7.0
312.00 134,041 -3.00 5.00 L0.5 6.9
314.00 9,895 -3.00 5.31 S0 6.8
315.00 27,933 -3.00 5.11 R2.5 7.0
316.00 9,380 -3.00 6.08 L0 6.7
HAYDEN GENERATING STATION
HAYDEN UNIT 1
311.00 1,135 -1.00 2.23 S0.5 3.0
312.00 46,931 -1.00 12.22 L0.5 3.0
314.00 5,775 -1.00 10.00 S0 2.9
315.00 1,033 -1.00 6.44 R2.5 3.0
316.00 250 -1.00 6.86 L0 2.9
HAYDEN UNIT 2
311.00 1,828 -1.00 2.69 S0.5 3.0
312.00 23,933 -1.00 13.29 L0.5 3.0
314.00 4,641 -1.00 9.97 S0 3.0
315.00 1,331 -1.00 6.26 R2.5 3.0
316.00 225 -1.00 5.26 L0 2.9
HAYDEN COMMON
311.00 14,854 0.00 8.54 S0.5 3.0
312.00 12,481 -1.00 6.61 L0.5 3.0
314.00 252 -1.00 8.96 S0 3.0
315.00 209 -1.00 4.75 R2.5 3.0
316.00 162 -1.00 4.11 L0 2.9
HUNTER GENERATING STATION
HUNTER UNIT 1
311.00 23,117 -5.00 3.63 S0.5 8.8
312.00 268,512 -5.00 6.71 L0.5 8.7
314.00 67,153 -5.00 5.89 S0 8.6
315.00 34,588 -5.00 4.79 R2.5 8.9
316.00 803 -4.00 4.42 L0 8.0
HUNTER UNIT 2
311.00 12,563 -5.00 3.63 S0.5 8.8
312.00 170,902 -5.00 6.39 L0.5 8.7
314.00 46,505 -5.00 5.65 S0 8.6
315.00 16,921 -5.00 3.92 R2.5 8.8
HUNTER UNIT 3
311.00 56,228 -5.00 3.51 S0.5 8.8
312.00 303,994 -5.00 4.94 L0.5 8.6
314.00 84,957 -5.00 6.58 S0 8.6
315.00 54,921 -5.00 3.66 R2.5 8.8
316.00 1,634 -4.00 4.48 L0 8.1
HUNTER UNITS 1 AND 2 COMMON
311.00 9,496 -5.00 3.50 S0.5 8.8
312.00 12,859 -5.00 5.29 L0.5 8.6
314.00 3,715 -5.00 4.88 S0 8.5
315.00 52 -4.00 6.78 R2.5 8.9
316.00 824 -4.00 3.99 L0 8.0
HUNTER UNITS 1, 2 AND 3 COMMON
310.20 246 0.00 3.17 SQUARE 9.0
311.00 112,575 -5.00 4.25 S0.5 8.9
312.00 28,250 -5.00 6.29 L0.5 8.7
314.00 1,192 -5.00 5.62 S0 8.6
315.00 1,635 -4.00 7.44 R2.5 8.9
316.00 485 -4.00 6.18 L0 8.4
HUNTINGTON GENERATING STATION
HUNTINGTON UNIT 1
311.00 19,940 -6.00 3.82 S0.5 8.8
312.00 293,285 -6.00 6.52 L0.5 8.7
314.00 62,237 -6.00 6.37 S0 8.6
315.00 20,953 -5.00 4.31 R2.5 8.8
316.00 1,028 -5.00 6.13 L0 8.3
HUNTINGTON UNIT 2
311.00 26,688 -5.00 4.31 S0.5 8.9
312.00 254,610 -6.00 6.03 L0.5 8.7
314.00 59,707 -6.00 5.85 S0 8.6
315.00 24,655 -5.00 4.84 R2.5 8.9
316.00 971 -5.00 5.17 L0 8.2
HUNTINGTON COMMON
311.00 82,353 -5.00 4.51 S0.5 8.9
312.00 38,232 -6.00 7.19 L0.5 8.7
314.00 7,432 -6.00 4.81 S0 8.4
315.00 4,186 -5.00 7.37 R2.5 8.9
316.00 1,434 -5.00 6.53 L0 8.4
JIM BRIDGER GENERATING STATION
JIM BRIDGER UNIT 1
311.00 15,425 -4.00 9.24 S0.5 3.0
312.00 177,317 -4.00 13.89 L0.5 3.0
314.00 47,333 -4.00 13.04 S0 3.0
315.00 10,769 -4.00 9.90 R2.5 3.0
316.00 298 -4.00 8.97 L0 2.9
JIM BRIDGER UNIT 2
311.00 13,003 -4.00 4.31 S0.5 4.9
312.00 173,405 -4.00 7.64 L0.5 4.9
314.00 59,894 -4.00 8.67 S0 4.9
315.00 9,329 -4.00 4.79 R2.5 4.9
316.00 198 -4.00 4.72 L0 4.7
JIM BRIDGER UNIT 3
311.00 12,969 -4.00 5.91 S0.5 5.0
312.00 268,993 -4.00 10.18 L0.5 4.9
314.00 44,992 -4.00 7.73 S0 4.9
315.00 8,200 -4.00 6.87 R2.5 5.0
316.00 192 -4.00 5.01 L0 4.7
JIM BRIDGER UNIT 4
311.00 40,518 -4.00 4.62 S0.5 5.0
312.00 302,860 -4.00 10.72 L0.5 4.9
314.00 46,049 -4.00 7.23 S0 4.9
315.00 17,263 -4.00 5.21 R2.5 4.9
316.00 1,249 -4.00 4.96 L0 4.7
JIM BRIDGER COMMON
310.20 281 0.00 4.04 SQUARE 5.0
311.00 68,727 -4.00 7.80 S0.5 5.0
312.00 94,216 -4.00 8.56 L0.5 4.9
314.00 9,504 -4.00 9.53 S0 4.9
315.00 16,656 -4.00 8.53 R2.5 5.0
316.00 3,803 -4.00 13.11 L0 4.9
NAUGHTON GENERATING STATION
NAUGHTON UNIT 1
311.00 21,073 -8.00 9.94 S0.5 5.0
312.00 154,475 -8.00 12.45 L0.5 4.9
314.00 20,553 -8.00 11.18 S0 4.8
315.00 20,713 -8.00 11.49 R2.5 5.0
316.00 96 -7.00 7.63 L0 4.6
NAUGHTON UNIT 2
311.00 29,217 -8.00 11.69 S0.5 5.0
312.00 190,425 -8.00 12.16 L0.5 4.9
314.00 26,530 -8.00 12.80 S0 4.9
315.00 30,170 -8.00 11.42 R2.5 5.0
316.00 389 -8.00 8.07 L0 4.7
NAUGHTON UNIT 3
311.00 14,081 -9.00 3.65 S0.5 8.9
312.00 95,896 -9.00 5.31 L0.5 8.6
314.00 39,545 -9.00 5.83 S0 8.5
315.00 11,440 -8.00 3.88 R2.5 8.8
316.00 206 -7.00 3.66 L0 7.9
NAUGHTON COMMON
310.20 15 0.00 2.86 SQUARE 9.0
311.00 69,585 -8.00 5.97 S0.5 8.9
312.00 32,826 -9.00 5.91 L0.5 8.7
314.00 8,036 -8.00 9.42 S0 8.8
315.00 3,878 -8.00 6.29 R2.5 8.9
316.00 1,717 -8.00 7.12 L0 8.4
WYODAK GENERATING STATION
WYODAK PLANT
310.20 165 0.00 1.81 SQUARE 9.0
311.00 53,157 -3.00 2.68 S0.5 8.9
312.00 317,978 -3.00 4.60 L0.5 8.7
314.00 66,827 -3.00 4.21 S0 8.6
315.00 27,529 -2.00 3.23 R2.5 8.9
316.00 1,457 -2.00 6.01 L0 8.5
(e) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges
FERC Sub Acct Description
310.2 Land Rights
330.2 Land Rights
330.3 Water Rights
330.4 Flood Rights
330.5 Fish/Wildlife
340.2 Land Rights
350.2 Land Rights
360.2 Land Rights
369.1 Overhead Services
369.2 Underground Services
389.2 Land Rights
391.2 Personal Computers and Printers
391.3 Office Equipment
392.01 Transportation Equipment - Light Trucks and Vans
392.05 Transportation Equipment - Medium Trucks
392.09 Transportation Equipment - Trailers
392.3 Aircraft
396.03 Light Power Operated Equipment
396.07 Heavy Power Operated Equipment
397.2 Mobile Radio Equipment
(f) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges
For a discussion on provisions for depreciation that were made during the year, refer to Note 3 of Notes to Financial Statements in this Form No. 1.
FERC FORM NO. 1 (REV. 12-03)Page 336-337
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 ServiceCommission:Annual Fee 6,577,403 6,577,403 Electric 928 6,577,403
2
Utah Public ServiceCommission: RateCases and
Proceedings
181,847 181,847 Electric 928 181,847
3 Oregon PublicUtility Commission:
Annual Fee
4,546,186 4,546,186 Electric 928 4,546,186
4
Oregon PublicUtility Commission:
Rate Cases and
Proceedings
1,236,197 1,236,197 Electric 928 1,236,197
5
Oregon Public
Utility Commission:
Deferred IntervenorFunding Grants
2,110,849 431,091 2,541,940
6
Wyoming Public
ServiceCommission:Annual Fee
1,913,485 1,913,485 Electric 928 1,913,485
7
Wyoming PublicServiceCommission: RateCases and
Proceedings
786,846 786,846 Electric 928 786,846
8
Washington Utilitiesand Transportation
Commission:
Annual Fee
704,124 704,124 Electric 928 704,124
9
Washington Utilities
and Transportation
Commission: RateCases andProceedings
78,569 78,569 Electric 928 78,569
10
Idaho PublicUtilitiesCommission:
Annual Fee
646,064 646,064 Electric 928 646,064
11
Idaho PublicUtilities
Commission: Rate
Cases andProceedings
239,143 239,143 Electric 928 239,143
12
Idaho Public
UtilitiesCommission:Deferred IntervenorFunding Grants (1
year amortization)
103,348 928 103,348
13
California PublicUtilities
Commission:
Annual Fee
1,394 1,394 Electric 928 1,394
Description(Furnish name of
regulatory
commission orbody the docketor case numberand a description
of the case)
Assessed byRegulatory
Commission
Expenses ofUtility
TotalExpenses for
Current Year
Deferred inAccount182.3 at
Beginning of
Year
Department AccountNo.Amount
Deferred
toAccount182.3
ContraAccount Amount
Deferred
in
Account182.3End ofYear
14 California Public
UtilitiesCommission: RateCases andProceedings
658,882 658,882 Electric 928 658,882
15
California PublicUtilitiesCommission:
Deferred Intervenor
Funding Grants
152,013 240,125 392,138
16
California
Environmental
Protection Agency:IndustryCompliance Fee
88,918 5,785 94,703 Electric 928 94,703
17 Multi-State: RateCases andProceedings 62,313 62,313 Electric 928 62,313
18 Multi-State: OtherRegulatory 503,143 503,143 Electric 928 503,143
19
Federal Energy
RegulatoryCommission:Annual Fee
2,587,098 2,587,098 Electric 928 2,587,098
20
Federal EnergyRegulatoryCommission:Annual Fee -
Hydroelectric Plants
3,408,208 3,408,208 Electric 928 3,408,208
21
Federal EnergyRegulatory
Commission:Transmission RateCases
329,045 329,045 Electric 928 329,045
22
Federal EnergyRegulatoryCommission: OtherRegulatory
1,769,419 1,769,419 Electric 928 1,769,419
46 TOTAL 20,472,880 5,851,189 26,324,069 2,366,210 26,324,069 671,216 103,348 2,934,078
FERC FORM NO. 1 (ED. 12-96)Page 350-351
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 ofAccounts).2. Indicate in column (a) the applicable classification, as shown below: Classifications:
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 specificarea 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 indicatethe 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
LineNo.(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
(1,131)394,044 908 392,913
3 (3) Distribution
(b)
Utah Sustainable Transportation and
Energy Plan - Innovative UtilityProjects
39,404 1,225,161 908 1,264,565
FERC FORM NO. 1 (ED. 12-87)Page 352-353
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
Overhead
Underground
DistributionRegional Transmission and Market Operation
Environment (other than equipment)
Other (Classify and include items in excess of $50,000.)Total Cost Incurred
Electric, R, D and D Performed Externally:
Research Support to the electrical Research Council or the Electric PowerResearch Institute
Research Support to Edison Electric Institute
Research Support to Nuclear Power GroupsResearch Support to Others (Classify)Total Cost Incurred
Classification Description Costs IncurredInternally Current
Year
Costs IncurredExternally Current
Year
AmountsCharged InCurrent Year:
Account
Amounts
Charged In
CurrentYear:Amount
UnamortizedAccumulation
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 forClearing Accounts(c)
Total
(d)
1
2
3 96,422,000
4 17,583,203
5
6 39,284,215
7 29,931,652
8 7,548,741
9
10 40,035,714
11 230,805,525
12
13 41,418,204
14 11,569,949
15
16 73,588,869
17 1,770,790
18 128,347,812
19
20 137,840,204
21 29,153,152
22
23 112,873,084
24 29,931,652
25 7,548,741
26
27 41,806,504
28 359,153,337 359,153,337
29
30
31
32
33
34
35
36
37
38
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
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65 359,153,337 359,153,337
66
67
68 172,011,416 172,011,416
69
70
71 172,011,416 172,011,416
72
73 11,524,282 11,524,282
74
75
76 11,524,282 11,524,282
77
78
79 5,951,587 5,951,587
80 269,709 269,709
81 1,563,321 1,563,321
82 4,615,612 4,615,612
Sales
Administrative and General
TOTAL Operation (Enter Total of lines 31 thru 40)
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 31thru
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
83
84
85
86
87
88
89
90
91
92
93
94
95 12,400,229 12,400,229
96 555,089,264 555,089,264
FERC FORM NO. 1 (ED. 12-88)Page 354-355
TOTAL Other Accounts
TOTAL SALARIES AND WAGES
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 toutility departments using the common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used.3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of
Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the
factors of allocation.4. Give date of approval by the Commission for use of the common utility plant classification and reference to the order of the Commission or other authorization.
FERC FORM NO. 1 (ED. 12-87)Page 356
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 hourlysale 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)3,949 190,998 4,056,184 4,180,698
2.1 Net Purchases (Account 555.1)
3 Net Sales (Account 447)(13,153)(13,153)(13,152)
4 Transmission Rights
5 Ancillary Services
6 Other Items (list separately)
7 Energy Imbalance Market (Account 555)(27,108,048)(57,200,825)(130,412,437)(191,498,843)
46 TOTAL (27,104,099)(57,022,980)(126,369,406)(187,331,297)
FERC FORM NO. 1 (NEW. 12-05)Page 397
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 foreach 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 andDispatch 149,010,073 MWh 14,000,907
2 Reactive Supply and Voltage 114,902,949 MWh 21,841,378 137,998,040 MWh 26,045,231
3 Regulation and Frequency Response 112,936,954 MWh 28,069,821 131,813,917 MWh 34,445,563
4 Energy Imbalance 3,973,728 MWh 189,152,268
5 Operating Reserve - Spinning 130,086,341 MWh 21,854,505 145,419,774 MWh 24,419,767
6 Operating Reserve - Supplement 130,086,341 MWh 21,854,505 144,932,666 MWh 24,337,438
7 Other
8 Total (Lines 1 thru 7)488,012,585 MWh 93,620,209 713,148,198 MWh 312,401,174
FERC FORM NO. 1 (New 2-04)
Page 398
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 statisticalclassification.
LineNo.Month(a)
Monthly PeakMW - Total
(b)
Day of MonthlyPeak
(c)
Hour ofMonthly Peak
(d)
Firm NetworkService for Self
(e)
Firm Network
Service forOthers(f)
Long-TermFirm Point-to-point
Reservations
(g)
Other
Long-
TermFirmService(h)
Short-TermFirm Point-to-point
Reservation
(i)
OtherService
(j)
NAME OF SYSTEM: 0
1 January 15,555 26 18 8,485 557 3,834 1,372 1,307
2 February 15,505 18 19 8,145 548 3,834 1,740 1,238
3 March 14,646 1 8 7,775 542 3,834 1,241 1,254
4 Total for Quarter 1 24,405 1,647 11,502 4,353 3,799
5 April 13,872 12 8 7,306 394 3,834 1,086 1,252
6 May 14,690 31 18 8,420 357 3,816 663 1,434
7 June 20,159 28 17 10,930 475 3,926 2,996 1,832
8 Total for Quarter 2 26,656 1,226 11,576 4,745 4,518
9 July 20,153 6 17 11,013 484 4,129 2,521 2,006
10 August 20,521 12 17 10,706 450 4,129 3,248 1,988
11 September 18,061 9 17 9,665 383 4,131 2,111 1,771
12 Total for Quarter 3 31,384 1,317 12,389 7,880 5,765
13 October 14,643 12 9 7,491 422 4,133 1,401 1,196
14 November 14,974 22 18 7,883 422 4,003 1,404 1,262
15 December 16,357 28 18 8,931 618 4,003 1,460 1,345
16 Total for Quarter 4 24,305 1,462 12,139 4,265 3,803
17 Total (a)106,750 (b)5,652 (c)47,606 (d)21,243 (e)17,885
FERC FORM NO. 1 (NEW. 07-04)
Page 400
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: FirmNetworkServiceForSelf
For the year being reported, the Net System Load information was compiled using metering and/or scheduling data. Reflects actual peak net system load for self at time of Transmission System Peak. Peak load includes behind-the-meter generation.
(b) Concept: FirmNetworkServiceForOther
For the year being reported, the Net System Load information was compiled using metering and/or scheduling data. Reflects actual peak of customers' load at time of Transmission System Peak.
(c) Concept: LongTermFirmPointToPointReservations
For the year being reported,the Net System Load information was compiled using reservations in OASIS at time of Transmission System Peak. Long-term firm point-to-point reservations have been adjusted so that the monthly megawatt reservations represent an amount at system input as measured by the transmission system loss factor. This adjustment has been made to ensure that transmission rates are designed fairly and in a non-discriminatory manner and is consistent with the system input measurement utilized for other long-term firm users of PacifiCorp’s transmission system, including network service.
(d) Concept: ShortTermFirmPointToPointReservations
For the year being reported, the Net System Load information was compiled using reservations in OASIS at time of Transmission System Peak.
(e) Concept: OtherService
For the year being reported, the Net System Load information was compiled using metering, scheduling and/or contractual data. Reflects actual peak and/or contractual demands of customers' load at time of Transmission System Peak.
FERC FORM NO. 1 (NEW. 07-04)
Page 400
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 fromthose amounts reported in Columns (e) and (f).
5. Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
LineNo.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)
Throughand OutService(g)
NetworkServiceUsage(h)
Point-
to-PointServiceUsage
(i)
Total
Usage
(j)
NAME OF SYSTEM: 0
1 January
2 February
3 March
4 Total for Quarter 1 0 0 0 0 0 0
5 April
6 May
7 June
8 Total for Quarter 2 0 0 0 0 0 0
9 July
10 August
11 September
12 Total for Quarter 3 0 0 0 0 0 0
13 October
14 November
15 December
16 Total for Quarter 4 0 0 0 0 0 0
17 Total Year to Date/Year 0 0 0 0 0 0
FERC FORM NO. 1 (NEW. 07-04)
Page 400a
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:2022-04-13 Year/Period of ReportEnd of: 2021/ 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 (IncludingInterdepartmental Sales)56,273,934
3 Steam 36,120,706 23 Requirements Sales for Resale (See instruction 4,
page 311.)278,833
4 Nuclear 24 Non-Requirements Sales for Resale (See
instruction 4, page 311.)4,833,964
5 Hydro-Conventional 2,793,849 25 Energy Furnished Without Charge
6 Hydro-Pumped Storage 26 Energy Used by the Company (Electric Dept Only,Excluding Station Use)(a)127,333
7 Other 15,681,531 27 Total Energy Losses 4,336,430
8 Less Energy for Pumping 4,527 27.1 Total Energy Stored
9 Net Generation (Enter Total of lines 3 through 8)54,591,559 28 TOTAL (Enter Total of Lines 22 Through 27.1)MUST EQUAL LINE 20 UNDER SOURCES 65,850,494
10 Purchases (other than for Energy Storage)14,523,353
10.1 Purchases for Energy Storage
11 Power Exchanges:
12 Received 6,856,077
13 Delivered 9,947,470
14 Net Exchanges (Line 12 minus line 13)(3,091,393)
15 Transmission For Other (Wheeling)
16 Received 17,968,595
17 Delivered 17,864,611
18 Net Transmission for Other (Line 16 minus line 17)103,984
19 Transmission By Others Losses (277,009)
20 TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and
19)65,850,494
FERC FORM NO. 1 (ED. 12-90)
Page 401a
Name of Respondent:
PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:2022-04-13 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: InternalUseEnergy
For metered locations only.FERC FORM NO. 1 (ED. 12-90)
Page 401a
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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).
LineNo.(a)(b)
(c)
(d)(e)(f)
NAME OF SYSTEM: 0
29 January 5,821,935 494,810 8,234 26 18
30 February 5,283,859 541,508 7,941 18 19
31 March 5,381,356 490,711 7,617 30 8
32 April 4,949,842 446,113 7,103 6 8
33 May 5,215,528 457,123 8,244 31 18
34 June 6,021,662 291,862 10,755 28 17
35 July 6,436,789 244,048 10,861 6 17
36 August 5,859,522 308,945 10,555 12 18
37 September 5,307,028 457,344 9,459 9 17
38 October 4,891,113 278,508 7,339 12 8
39 November 5,224,354 455,299 7,672 22 18
40 December 5,457,506 367,693 8,736 27 18
41 Total 65,850,494 4,833,964
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
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 of plant.
Line
No.
Item
(a)
Plant Name:
(a)
Blundell
Plant Name:
Chehalis
Plant Name:
(b)
Colstrip
Plant Name:
(c)
Craig
Plant Name:
Currant Creek
Plant Name:DaveJohnston
PlantName:
Gadsby
Peakers
PlantName:
Gadsby
Steam
PlantName:(d)
Hayden
Plant Name:
(e)
Hermiston
Plant Name:(f)
Hunter - Total
Plant
Plant Name:(g)
Hunter Unit
No. 1
Plant Name:(h)
Hunter Unit
No. 2
Plant Name:Hunter 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 OutdoorBoiler Outdoor OutdoorBoiler OutdoorBoiler OutdoorBoiler OutdoorBoiler OutdoorBoiler OutdoorBoiler Outdoor Outdoor OutdoorBoiler 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 37 508 154 161 568 717 120 161 77 238 1,162 417 270 475 920 1,381 545 636 606 269
7 7,789 6,543 8,554 8,760 7,926 8,760 322 1,236 8,758 8,005 8,760 8,515 8,593 8,360 8,757 8,760 8,542 8,755 8,756 7,795
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 20 18 (k)0 (l)0 19 172 (m)0 28 (n)0 (o)0 194 (p)0 (q)0 (r)0 139 300 32 (s)0 103 59
12 211,226,000 2,248,237,000 895,672,000 1,268,464,000 2,746,290,000 3,601,242,000 8,403,000 74,605,000 442,938,000 1,521,009,000 7,796,581,000 2,745,483,000 1,787,129,000 3,263,969,000 6,263,658,000 7,778,303,000 3,096,959,000 3,292,396,000 2,596,446,000 1,270,750,000
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 1,321,031 210,526
14 8,472,547 24,457,513 68,365,273 38,551,177 44,238,648 169,107,692 4,265,353 15,198,888 17,766,337 12,841,344 213,730,483 65,323,244 54,765,154 93,642,085 128,645,233 150,043,755 35,561,435 53,113,051 133,223,182 52,852,548
15 105,902,417 329,051,513 171,458,205 185,631,155 312,337,203 901,227,365 81,432,231 70,432,461 96,860,448 170,362,096 1,096,334,108 389,105,510 252,684,392 454,544,206 767,685,409 1,288,487,133 333,542,438 573,372,402 634,367,588 413,035,796
16 5,423,021 1,145,655 9,342,713 401,646 261,730 24,447,082 1,209,390 2,228,249 407,646 12,137,613 4,045,871 4,045,871 4,045,871 6,008,245 45,928,068 55,376,682 677,254
17 160,993,581 358,385,208 250,954,835 224,721,064 360,240,858 1,105,230,737 85,697,584 88,092,829 117,538,103 184,408,015 1,351,828,213 468,154,525 321,175,317 562,498,371 904,716,451 1,485,652,717 383,636,148 643,280,079 824,288,483 466,776,124
18 4,225.553 604.054 1,612.717 1,305.531 635.458 1,353.173 473.337 350.075 1,446.623 659.637 1,083.387 1,022.774 1,090.726 1,135.008 890.907 958.084 648.801 981.807 1,165.566 1,611.462
19 42,411 171,545 14,721 352,534 64,192 11,914 76,122 42,607 10,235 12,742,998 37,147 42,931 379,640 15,762
20 80,392,088 (t)16,610,338 24,912,585 64,267,970 41,772,491 1,083,661 4,659,396 11,573,309 41,464,719 137,919,167 50,367,152 31,551,254 56,000,761 132,962,664 (u)213,251,031 71,731,518 74,919,793 77,803,260 20,515,880
21
22 58,907 737,151 1,707,346 3,086,507 137,896 983,559 22,218,822 7,446,229 6,000,053 8,772,540 15,216,452 18,568,738 7,274,236 4,292,527
23 5,403,741
Kind of Plant (Internal
Comb, Gas Turb, Nuclear)
Type of Constr
(Conventional, Outdoor,Boiler, etc)
Year OriginallyConstructed
Year Last Unit wasInstalled
Total Installed Cap (Max
Gen Name Plate Ratings-
MW)
Net Peak Demand on Plant- MW (60 minutes)
Plant Hours Connected toLoad
Net Continuous PlantCapability (Megawatts)
When Not Limited by
Condenser Water
When Limited by
Condenser Water
Average Number ofEmployees
Net Generation, Exclusiveof Plant Use - kWh
Cost of Plant: Land andLand Rights
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
(Nuclear Plants Only)
Steam Expenses
Steam From Other
Sources
24
25 1,805,705 (46,032)661,438 2,118,082 582,595 351,240 5,929,222 (36,734)(39,275)62,982 (60,441)23,084 2,421,352 3,942,058 4,207
26 1,968,404 1,099,045 3,354,070 1,087,140 699,116 16,704,549 3,900,647 388,963 2,859,751 2,311,035 (2,518,719)3,067,435 10,339,941 (19,147,832)482,684 575,041 6,340,315 3,374,198
27 7,560 77,265 1,064 384 247 433 4,429 328,813 232 268 30,873 12,722
28
29 382,053 650,789 182,466 174,287 62,912 40,486 70,889 1,096,044 508,458 2,297,012
30 647,959 32,590 146,116 208,445 1,224,851 1,736,999 59,036 114,467 296,869 3,632,242 1,318,301 887,601 1,426,340 2,604,025 8,395,760 869,906 855,079 1,343,346 213,717
31 200,092 3,879,434 2,463,822 10,260,860 1,259,372 1,552,522 9,429,034 3,475,396 2,231,699 3,721,939 6,310,008 21,636,107 6,748,592 2,697,267
32 1,652,552 1,998,581 1,822,678 727,699 2,004,006 8,111,051 221,641 1,579,713 796,136 2,502,816 990,453 716,112 796,251 1,363,749 8,542,359 430,620 845,103 2,990,790 1,172,819
33 50,544 360,437 768,169 35,638 1,703,669 100,847 109,294 183,320 1,808,453 709,638 379,188 719,627 772,775 3,755,577 9,834 10,369 1,208,146 86,327
34 10,032,170 85,499,554 27,260,966 33,539,967 70,413,855 83,465,305 2,047,780 11,836,907 16,350,991 47,393,941 180,508,902 66,642,225 39,350,903 74,515,774 170,680,322 268,605,093 75,983,293 81,190,642 106,420,417 32,381,219
35 0.0475 0.0380 0.0304 0.0264 0.0256 0.0232 0.2437 0.1587 0.0369 0.0312 0.0232 0.0243 0.0220 0.0228 0.0272 0.0345 0.0245 0.0247 0.0410 0.0255
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 Wyod
36 Gas Coal (v)
Oil Coal (w)
Oil Gas Coal (x)
Oil Gas Gas Coal (y)
Oil Gas Coal (z)
Oil Coal (aa)
Oil Coal (ab)
Oil Coal (ac)
Oil Coal (ad)
Oil Coal (ae)
Oil Gas Gas Coal Gas Coal
37 Mcf T Boe T Boe Mcf T Boe Mcf Mcf T Boe Mcf T Boe T Boe T Boe T Boe T Boe T Boe Mcf Mcf T Mcf T
38 15,397,363 555,487 1,471 635,539 30 19,546,682 2,501,424 19,781 137,176 1,344,453 215,787 273 10,951,498 3,511,886 12,881 1,286,625 1,989 812,804 1,128 1,412,457 9,764 2,837,833 3,815 4,315,448 10,758 21,741,163 22,670,765 1,236,971 4,151,245 1,02
39 1,095 8,627 140,000 9,895 134,395 1,046 8,353 138,000 1,045 1,043 11,212 135,558 1,041 11,482 138,000 11,491 138,000 11,734 138,000 11,329 138,000 11,258 138,000 9,587 138,000 1,044 1,043 10,099 1,054
40 5.221 28.118 83.622 37.317 93.094 3.288 16.086 112.483 7.900 3.466 51.211 94.555 3.786 37.645 94.173 44.726 89.070 44.173 75.360 3.299 3.305 53.072 3.197 1
41 5.221 29.681 83.622 39.045 93.094 3.288 15.810 112.483 7.900 3.466 53.214 94.555 3.786 38.927 94.173 38.982 38.671 39.024 46.734 89.070 49.228 75.360 3.299 3.305 52.168 3.197 1
42 4.768 1.720 14.221 1.973 16.484 3.143 0.946 19.407 7.560 3.324 2.373 16.604 3.637 1.695 16.248 1.696 18.432 1.648 18.256 1.722 15.571 2.076 15.367 2.567 13.002 3.162 3.167 2.583 3.035
43 0.036 0.018 0.020 0.023 0.011 0.001 0.129 0.062 0.026 0.027 0.018 0.018 0.018 0.017 0.021 0.027 0.023 0.023 0.025 0.005
44 7,500.091 10,700.811 9.659 9,914.972 0.133 7,446.451 11,604.664 31.836 17,058.670 18,791.153 10,924.742 3.505 7,496.481 10,344.134 9.576 10,770.471 4.198 10,673.855 3.659 9,804.989 17.339 10,201.212 3.530 10,638.172 8.017 7,325.698 7,185.211 9,622.207 1,684.465 12,84
FERC FORM NO. 1 (REV. 12-03)
Page 402-403
Steam Transferred (Cr)
Electric Expenses
Misc Steam (or Nuclear)
Power Expenses
Rents
Allowances
Maintenance Supervision
and Engineering
Maintenance of Structures
Maintenance of Boiler (orreactor) Plant
Maintenance of ElectricPlant
Maintenance of MiscSteam (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 ofFuel/unit, asDelvd f.o.b.during year
Average
Cost of Fuel
per UnitBurned
AverageCost of FuelBurned per
Million BTU
Average
Cost of FuelBurned perkWh NetGen
Average
BTU per
kWh NetGeneration
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 2021 were $1.3 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 2021 were $6.7 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 2021 were $27.4 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 2021 were $3.9 million and were primarily credited to Account 506, Miscellaneous steam power expenses.
(k) Concept: PlantAverageNumberOfEmployees
PacifiCorp does not have employees at this plant.
(l) Concept: PlantAverageNumberOfEmployees
PacifiCorp does not have employees at this plant.
(m) Concept: PlantAverageNumberOfEmployees
Refer to the Gadsby Steam Plant for the average number of employees.
(n) Concept: PlantAverageNumberOfEmployees
PacifiCorp does not have employees at this plant.
(o) Concept: PlantAverageNumberOfEmployees
PacifiCorp does not have employees at this plant.
(p) Concept: PlantAverageNumberOfEmployees
Refer to Hunter - Total Plant for the average number of employees.
(q) Concept: PlantAverageNumberOfEmployees
Refer to Hunter - Total Plant for the average number of employees.
(r) Concept: PlantAverageNumberOfEmployees
Refer to Hunter - Total Plant for the average number of employees.
(s) Concept: PlantAverageNumberOfEmployees
Refer to Lake Side Plant for the average number of employees.
(t) Concept: FuelSteamPowerGeneration
Amount includes intercompany profits.
(u) Concept: FuelSteamPowerGeneration
Amount includes intercompany profits.
(v) Concept: FuelKind
Fuel oil is used for start-up purposes.
(w) Concept: FuelKind
Fuel oil is used for start-up purposes.
(x) Concept: FuelKind
Fuel oil is used for start-up purposes.
(y) Concept: FuelKind
Fuel oil is used for start-up purposes.
(z) Concept: FuelKind
Fuel oil is used for start-up purposes.
(aa) Concept: FuelKind
Fuel oil is used for start-up purposes.
(ab) Concept: FuelKind
Fuel oil is used for start-up purposes.
(ac) Concept: FuelKind
Fuel oil is used for start-up purposes.
(ad) Concept: FuelKind
Fuel oil is used for start-up purposes.
(ae) Concept: FuelKind
Fuel oil is used for start-up purposes.
(af) Concept: FuelKind
Fuel oil is used for start-up purposes.
FERC FORM NO. 1 (REV. 12-03)Page 402-403
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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
Project No.
14803Plant Name:(a)
Copco No. 1
FERC LicensedProject No.
14803
Plant Name:Copco No. 2
FERC LicensedProject No.
14803
Plant Name:Iron Gate
FERC LicensedProject No.
14803
Plant Name:JC Boyle
FERC LicensedProject No.
1927
Plant Name:Clearwater No. 1
FERCLicensedProjectNo.
1927
PlantName:ClearwaterNo. 2
FERCLicensedProjectNo.
1927
PlantName:FishCreek
FERCLicensedProjectNo.
1927
PlantName:LemoloNo. 1
FERC
Licensed
Project No.1927PlantName:
Lemolo No.
2
FERCLicensedProjectNo.
1927
PlantName:SlideCreek
FERCLicensedProjectNo.
1927
PlantName:SodaSprings
FERC
LicensedProject No.1927Plant Name:
Toketee
FERC
LicensedProject No.20Plant Name:
Grace
FERC
LicensedProject No.20Plant Name:
Oneida
FERC
LicensedProject No.20Plant Name:
Soda
FERC
LicensedProject No.2071Plant Name:
Yale
FERC
LicensedProject No.2111Plant Name:
Swift No. 1
FERC
LicensedProject No.2420Plant Name:
Cutler
FERCLicensedProject No.
2630
Plant Name:ProspectNo. 2
FERC
LicensedProject No.935Plant Name:
Merwin
1 (b)
Storage Run-of-River (c)
Storage
(d)
Storage
(e)
Run-of-River
(f)
Run-of-River
(g)
Run-of-River
(h)
Storage
(i)
Run-of-River
Run-of-
River
Storage
(Re-Reg)
(j)
Storage Storage Storage Storage Storage Storage Storage (k)
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 24 30 15 45 5 10 10 15 23 13 12 31 22 16 9 162 251 26 36 143
7 4,916 4,899 8,478 4,910 7,937 6,988 2,392 8,128 8,369 7,921 7,892 7,737 6,691 8,759 4,686 5,760 5,202 4,515 8,403 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 2 1 1 1 1 1 1 2 1 4 2 2 1 1 3 1 1
12 62,388,000 78,903,000 75,595,000 154,397,000 17,986,000 15,352,000 12,240,000 83,259,000 101,281,000 37,049,000 31,580,000 144,207,000 63,239,000 27,399,000 15,498,000 514,935,000 591,285,000 24,171,000 153,144,000 465,720,000
13
14 107,019 20,914 341,617 25,845 74,674 309,259 511,083 8,363,013 20,287,495 3,511,105 105,168 1,885,392
15 2,323,521 2,779,620 8,806,318 4,309,036 1,481,376 2,476,401 1,764,935 2,927,140 6,408,875 2,197,450 4,221,103 5,232,083 3,676,932 2,909,298 1,318,971 18,181,485 75,225,690 4,877,008 4,440,833 112,636,950
16 3,376,606 3,261,503 17,254,262 16,343,274 4,873,468 14,946,012 12,462,362 15,815,119 33,062,060 15,161,131 90,311,207 14,175,425 14,072,134 9,111,645 11,257,225 34,998,399 49,406,266 10,520,438 35,552,318 38,991,189
17 5,743,133 11,041,713 3,301,411 16,091,613 1,405,790 2,200,378 2,993,343 6,903,967 11,844,594 8,979,657 2,632,518 6,245,119 6,409,247 15,821,252 6,495,303 18,847,075 25,630,205 14,989,767 7,351,135 19,823,749
18 133,348 551,687 1,095,742 1,061,007 50,817 250,151 533,015 481,754 1,820,580 582,653 2,089,012 502,952 545,920 829,815 2,191,426 1,302,690 1,086,176 532,515 4,232,641
19
20 11,683,627 17,655,437 30,799,350 37,830,775 7,811,451 19,872,942 17,753,655 26,127,980 53,136,109 26,920,891 99,253,840 26,155,579 24,778,907 28,981,269 19,582,582 82,581,398 171,852,346 34,984,494 47,981,969 177,569,921
21 584.181 653.905 1,711.075 386.107 520.763 764.344 1,613.969 816.755 1,380.159 1,495.605 9,023.076 615.425 750.876 966.042 1,355.196 616.279 716.051 1,166.150 1,499.437 1,305.661
22
23 29,749 47,946 898,263 190,693 104,435 62,817 31,974 119,970 93,017 44,847 64,615 144,377 133,364 121,040 74,665 1,756,340 3,148,361 198,634 368,611 1,769,695
24 811 1,406 595 1,729 2,081 973 595 2,298 55,740 99,832 5,352 56,572
25 346 466 311 1,693 38,119 66,073 27,954 81,295 97,838 45,743 146,005 108,006 34,823 31,657 14,773 877,355 1,803,885 113,282 553 892,901
26
27 1,126,709 1,467,258 996,371 761,756 276,041 447,894 330,898 587,904 626,652 329,317 443,082 697,235 1,594,910 538,924 366,621 349,511 314,564 1,311,141 462,593 493,964
28 109,189 147,405 98,270 2,255 69,656 120,737 51,081 148,553 178,783 83,587 51,081 197,363 6,638 5,580 2,690 110,623 198,131 31,438 53,671 112,274
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 nameplate Rating in MW)
Net Peak Demand on Plant-
Megawatts (60 minutes)
Plant Hours Connect to Load
Net Plant Capability (in
megawatts)
(a) Under Most Favorable OperConditions
(b) Under the Most Adverse OperConditions
Average Number of Employees
Net Generation, Exclusive of PlantUse - kWh
Cost of Plant
Land and Land Rights
Structures and Improvements
Reservoirs, Dams, and Waterways
Equipment Costs
Roads, Railroads, and Bridges
Asset Retirement Costs
Total cost (total 13 thru 20)
Cost per KW of Installed Capacity
(line 20 / 5)
Production Expenses
Operation Supervision andEngineering
Water for Power
Hydraulic Expenses
Electric Expenses
Misc Hydraulic Power GenerationExpenses
Rents
29 263
30 6,681 9,019 7,184 143,666 31,707 51,750 24,629 65,632 81,099 53,312 34,745 116,922 34,522 37,868 61,886 61,862 59,099
31 3,184 3,894 13,821 25,142 22,351 47,126 48,418 44,271 27,367 14,326 11,297 159 1,880 1,880 54,076 89,731 5,933 104,213 70,263
32 154,525 157,800 87,633 27,834 61,659 20,762 71,734 44,854 26,495 123,063 58,754 163,533 53,783 52,446 43,272 84,523 103,192 786 31,450 103,022
33 11,110 14,999 9,999 72,266 41,870 72,574 73,455 89,294 107,466 50,479 30,705 119,104 126,809 81,171 37,880 519,942 931,691 396,905 311,469 532,651
34 1,441,493 1,848,787 2,098,031 1,213,984 649,440 866,364 659,446 1,187,649 1,257,702 758,688 843,908 1,560,135 1,985,008 832,698 541,781 3,845,978 6,751,273 2,058,119 1,400,037 4,090,441
35 0.023 0.023 0.028 0.008 0.036 0.056 0.054 0.014 0.012 0.020 0.027 0.011 0.031 0.030 0.035 0.007 0.011 0.085 0.009 0.009
FERC FORM NO. 1 (REV. 12-03)
Page 406-407
Maintenance Supervision and
Engineering
Maintenance of Structures
Maintenance of Reservoirs, Dams,
and Waterways
Maintenance of Electric Plant
Maintenance of Misc HydraulicPlant
Total Production Expenses (total23 thru 33)
Expenses per net kWh
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: PlantName
This footnote applies to all hydroelectric generating facilities with current generation. All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities.
(b) Concept: PlantKind
Copco No. 1 - Pondage for peaking - storage, Upper Klamath Lake
(c) Concept: PlantKind
Iron Gate - Storage for regulation
(d) Concept: PlantKind
JC Boyle - Pondage for peaking - storage, Upper Klamath Lake
(e) Concept: PlantKind
Clearwater No. 1 - Forebay for peaking
(f) Concept: PlantKind
Clearwater No. 2 - Forebay for peaking
(g) Concept: PlantKind
Fish Creek - Forebay for peaking
(h) Concept: PlantKind
Lemolo No. 1 - Storage, Lemolo Lake
(i) Concept: PlantKind
Lemolo No. 2 - Storage, Lemolo Lake
(j) Concept: PlantKind
Toketee - Pondage for peaking - storage, Lemolo Lake
(k) Concept: PlantKind
Prospect No. 2 - Forebay for peaking
FERC FORM NO. 1 (REV. 12-03)
Page 406-407
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 PowerSystem 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 thebottom 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 10percent 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 whichindividually 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
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
34 0
35
36
37
38
39 0
FERC FORM NO. 1 (REV. 12-03)Page 408-409
Maintenance of Misc Pumped Storage Plant
Production Exp Before Pumping Exp (24 thru 34)
Pumping Expenses
Total Production Exp (total 35 and 36)
Expenses per kWh (line 37 / 9)
Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 thefacts in a footnote. If licensed project, give project number in footnote.3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 402.4. If net peak demand for 60 minutes is not available, give the which is available, specifying period.
5. If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Production Expenses
Line
No.(a)(b)
(c)(d)(e)(f)
(g)
(h)(i)(j)(k)
(l)
(m)
1
Ashton
(Licensed
Project No.2381)
1917 6.85 7.0 29,846,000 34,214,910 4,994,877 464,664 144,052 Water (i)
Hydro
2 Bend 1913 1.11 1.0 636,000 4,192,919 3,777,405 65,822 15,010 Water Hydro
3
Big Fork
(Licensed
Project No.2652)
1910 4.15 4.6 28,399,000 11,563,446 2,786,373 504,983 21,563 Water Hydro
4 Eagle Point 1957 2.81 2.8 13,418,000 2,837,703 1,009,859 282,917 78,865 Water Hydro
5
(a)
East Side
(Licensed
Project No.2082)
1924 3.20 0.0 1,736,685 542,714 46,175 16,671 Water Hydro
6
Fall Creek
(LicensedProject No.2082)
1903 2.20 2.0 8,223,000 2,559,166 1,163,257 153,124 54,811 Water Hydro
7 Granite 1896 2.00 1.2 4,908,659 5,261,254 2,630,627 219,552 8,319 Water Hydro
8 Gunlock 1917 0.75 0.2 384,329 681,849 909,132 91,561 40,142 Water Hydro
9 Last Chance 1983 1.73 1.3 3,992,337 3,169,893 1,832,308 141,125 36,241 Water Hydro
10
Paris
(LicensedProject No.703)
1910 0.72 0.7 719,185 758,153 1,052,990 153,139 21,153 Water Hydro
11
Pioneer (LicensedProject No.2722)
1897 5.00 2.6 6,483,574 12,167,499 2,433,500 521,802 98,790 Water Hydro
12
Prospect No.1 (LicensedProject No.
2630)
1912 3.76 4.6 4,727,000 5,467,098 1,454,015 100,196 80,253 Water Hydro
13
Prospect No.
3 (Licensed
Project No.2337)
1932 7.20 6.0 10,632,000 9,604,145 1,333,909 353,120 187,455 Water Hydro
14
Prospect No.
4 (LicensedProject No.2630)
1944 1.00 0.9 981,000 2,517,002 2,517,002 30,821 18,351 Water Hydro
15 Sand Cove 1926 0.80 0.2 261,549 1,135,451 1,419,314 120,770 45,202 Water Hydro
16
Stairs
(Licensed
Project No.597)
1895 1.00 1.2 3,326,139 1,954,072 1,954,072 226,652 4,160 Water Hydro
17 Veyo 1920 0.50 0.2 201,190 894,057 1,788,114 74,663 80,756 Water Hydro
18 VivaNaughton 1986 0.74 0.1 348,463 1,232,115 1,665,020 141,135 60,096 Water Hydro
Name ofPlant
Year
Orig.
Const.
Installed
CapacityNamePlateRating
(MW)
Net PeakDemandMW (60min)
NetGenerationExcludingPlant Use
Cost ofPlant
Plant Cost(Incl Asset
Retire.
Costs) PerMW
Operation
Exc'l.
Fuel
Fuel
Production
Expenses
Maintenance
Production
Expenses
Kind
of
Fuel
FuelCosts(in
cents
(perMillionBtu)
GenerationType
19 Wallowa
Falls
(LicensedProject No.308)
1921 1.10 1.1 3,080,000 5,534,424 5,031,295 228,092 17,643 Water Hydro
20
Weber (LicensedProject No.1744)
1911 3.85 2.0 3,706,461 3,887,224 1,009,669 321,349 26,653 Water Hydro
21
(b)
West Side (Licensed
Project No.
2082)
1908 0.60 0.0 (53,000)577,606 962,677 16,947 590 Water Hydro
22
(c)
Keno
RegulatingDam (LicensedProject No.
2082)
7,806,394 17,387 564 Hydro
23
(d)
Upper
Klamath
Lake (LicensedProject No.2082)
3,851,986 348,797 (25,145,083)Hydro
24
(e)
NorthUmpqua
(Licensed
Project No.1927)
18,666,880 Hydro
25
(f)(g)
LiftonPumpingPlant
1917 19,527,706 (6,974,181)289,306 62,570 Water Hydro
26 CedarSprings II 2020 198.88 192.0 670,071,000 255,168,135 1,283,026 1,908,212 2,396,391 Wind (j)
Wind
27 DunlapRanch 1 2010 136.90 112.0 435,043,000 218,400,004 1,595,325 225,593 1,560,638 Wind Wind
28 Ekola Flats 2020 250.90 240.0 736,904,000 316,800,086 1,262,655 1,322,460 1,526,650 Wind Wind
29 Foote Creek 1999 48.00 42.0 154,512,000 82,218,387 1,712,883 631,790 207,246 Wind Wind
30 Glenrock 2008 119.30 107.0 339,298,000 192,532,473 1,613,851 1,507,193 1,656,843 Wind Wind
31 Glenrock III 2009 46.00 44.0 127,325,000 81,398,801 1,769,539 78,566 574,393 Wind Wind
32 GoodnoeHills 2008 103.40 94.0 296,244,000 154,902,819 1,498,093 1,554,163 97,085 Wind Wind
33 High Plains 2009 122.10 102.0 333,898,000 189,926,696 1,555,501 1,080,305 1,515,530 Wind Wind
34 Leaning
Juniper 1 2006 110.38 100.0 293,641,000 177,306,570 1,606,329 2,027,909 129,686 Wind Wind
35 Marengo 2007 156.00 153.0 484,854,000 213,076,616 1,365,876 1,225,524 1,466,300 Wind Wind
36 Marengo II 2008 78.00 77.0 247,430,000 110,589,245 1,417,811 762,934 780,372 Wind Wind
37 McFadden
Ridge I 2009 35.15 33.0 102,523,000 52,700,039 1,499,290 310,227 436,289 Wind Wind
38 Pryor
Mountain 2020 239.80 231.0 638,325,000 391,555,048 1,632,840 814,450 1,860,291 Wind Wind
39 Rolling Hills 2009 115.80 107.0 296,559,000 196,899,234 1,700,339 106,885 158,254 Wind Wind
40 Seven MileHill 2008 122.10 108.0 396,393,000 188,362,997 1,542,694 371,741 374,866 Wind Wind
41 Seven Mile
Hill II 2008 24.05 22.8 82,266,000 38,529,452 1,602,056 73,310 73,837 Wind Wind
42 TB Flats 2020 503.20 447.0 1,050,539,890 603,526,225 1,199,376 1,940,459 2,049,835 Wind Wind
43 (h)
Black Cap 2012 2.00 1.9 3,232,054 323,477 161,739 Solar Solar
FERC FORM NO. 1 (REV. 12-03)Page 410-411
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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
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.
(g) 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)(2.8)(4,527,000)
(h) Concept: PlantName
PacifiCorp has an agreement with Citizens Asset Finance, Inc. to lease the Black Cap Solar generating facility. The lease has a 16-year term from October 2012 to October 2028 and is accounted for as an operating lease.
(i) Concept: GenerationType
This footnote applies to all hydroelectric generating facilities with current generation. Common river system costs for the operation of these facilities are allocated to each plant based upon the unit’s name plate rating.All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities.
(j) Concept: GenerationType
This footnote applies to all wind-powered generating facilities with current generation.Common costs for the operation of these facilities are allocated to each plant based upon the unit’s name plate rating.All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities.FERC FORM NO. 1 (REV. 12-03)
Page 410-411
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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/provide5. 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 affiliatedfuel 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, compresspurpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property accounts listed.
LineNo.
Name
of theEnergyStorageProject
(a)
Functional
Classification
(b)
Locationof theProject(c)
MWHs(d)
MWHs
deliveredto the gridto supportProduction
(e)
MWHs
delivered tothe grid tosupportTransmission
(f)
MWHs
delivered tothe grid tosupportDistribution
(g)
MWHs Lost
During
Conversion,Storage andDischargeof Energy
Production
(h)
MWHs Lost
During
Conversion,Storage andDischarge ofEnergy
Transmission
(i)
MWHs Lost
During
Conversion,Storage andDischargeof Energy
Distribution
(j)
MWHs
Sold
(k)
Revenues
fromEnergyStorageOperations
(l)
Power
Purchased
forStorageOperations(555.1)
(Dollars)
(m)
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
FERC FORM NO. 1 ((NEW 12-12))Page 414
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 ofconstruction need not be distinguished 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 occupancy and 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 operationof, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company.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 reportcircuit 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 ACSR26/7
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 ACSR
26/7
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 3-1272ACSR 36/1
10 (h)
DIXONVILLE, 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 3-1272
ACSR 36/1
12 KLAMATH CO-GEN, OR SNOW GOOSE, OR 500.00 500.00 Steel Tower 2.00 1
3-1272
ACSR
54/19
13 MALIN, OR INDIAN SPRINGS, CA 500.00 500.00 Steel Tower 47.00 1
3-1852
ACSR
51/27
14 MERIDIAN, OR KLAMATH CO-GEN, OR 500.00 500.00 Steel Tower 58.00 1
3-1272
ACSR
54/19
15 (j)
MIDPOINT, ID HEMINGWAY, ID 500.00 500.00 Steel Tower 130.00 1 3-1272
ACSR 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 3-1272
ACSR 36/1
18 500kV Costs and Expenses 28,279,278 556,280,616 584,559,894 54,905 1,750,139 719,334 2,524,378
19 90TH SOUTH, UT CAMP WILLIAMS #3, UT 345.00 345 Steel - SP 11 0 1 1557.4ACSR/TW36/7
20 90TH SOUTH, UT CAMP WILLIAMS #4, UT 345.00 345.00 Steel - SP 0.00 11 1
From To Operating Designated Type of Supporting
Structure On Structure ofLine Designated
On
Structuresof AnotherLine
NumberofCircuits
Size ofConductor
and
Material
Land ConstructionCosts Total Costs OperationExpenses MaintenanceExpenses Rents TotalExpenses
1557.4
ACSR/TW
36/7
21 90TH SOUTH, UT CAMP WILLIAMS #1, UT 345.00 345.00 Steel - SP 11.00 0 1 1272
ACSR 45/7
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 1272ACSR 45/7
25 BEN LOMOND, UT POPULUS #2, ID 345.00 345.00 Steel - SP 86.00 0 1 1272
ACSR 45/7
26 BEN LOMOND, UT CAMP WILLIAMS, UT 345.00 345.00 Steel - SP 69.00 0 1 1272
ACSR 45/7
27 BEN LOMOND, UT TERMINAL #2, UT 345.00 345.00 Steel - SP 47.00 0 1 1272ACSR 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 1272ACSR 45/7
30 (l)
BORAH, ID MIDPOINT #2, ID 345.00 345.00 Wood - H 78.00 0 1 1272
ACSR 45/7
31 CAMP WILLIAMS, UT MONA #3, UT 345.00 345.00 Wood - H 47.00 0 1 954 ACSR
45/7
32 CAMP WILLIAMS, UT MONA #1, UT 345.00 345.00 Wood - H 47.00 0 1 1272ACSR 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 ACSR
54/7
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 ACSR45/7
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 ACSR
54/7
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 2156ACSR
8419
44 HUNTINGTON, UT HUNT PLANT 2, UT 345.00 345.00 Steel Tower 1.00 0 1 2156ACSR
8419
45 HUNTINGTON, UT PINTO, UT 345.00 345.00 Steel - SP 159.00 0 1 795 ACSR45/7
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 1272
ACSR 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 2-954ACSR 45/7
55 SIGURD, UT UT-NV STATE LINE 345.00 345.00 Steel Tower 190.00 0 1 954 ACSR
54/7
56 SPANISH FORK, UT CAMP WILLIAMS, UT 345.00 345.00 Steel - SP 0.00 35 1 1272
ACSR 45/7
57 TERMINAL, UT BORAH, ID 345.00 345.00 Wood - H 138.00 0 1 2-954ACSR 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 160,284,247 1,691,154,808 1,851,439,055 137,326 2,328,070 615,390 3,080,786
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 1272ACSR 45/7
64 AEOLUS, WY SHIRLEY BASIN #1, WY 230.00 230.00 Steel - H 17.00 0 1 1158.4
ACSS 25/7
65 AEOLUS, WY SHIRLEY BASIN #2, WY 230.00 230.00 Steel - H 17.00 0 1 1158.4
ACSS 25/7
66 ALVEY, OR DIXONVILLE, OR 230.00 230.00 Wood - H 59.00 0 1 1272ACSR 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 ACSR45/7
69 ARROWHEAD, WY FIREHOLE, WY 230.00 230.00 Wood - H 9.00 0 1 795 ACSR
26/7
70 ATLANTIC CITY, WY COLUMBIA GENEVA, WY 230.00 230.00 Wood - H 1.00 0 1 1272
ACSR 36/1
71 BEN LOMOND, UT NAUGHTON #1, WY 230.00 230.00 Wood - H 88.00 0 1 795 ACSR26/7
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 1272
ACSR 36/1
76 BUFFALO, WY CASPER, WY 230.00 230.00 Wood - H 107.00 0 1 1272
ACSR 36/1
77 (r)
CASPER, WY DAVE JOHNSTON, WY 230.00 230.00 Wood - H 36.00 0 1 1557.4ACSR/TW
45/7
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 ACSR54/7
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 1272
ACSR 45/7
82 CORRAL, OR OCHOCO #1, OR 230.00 230.00 Wood - H 9.00 0 1
1557.4
ACSR/TW
36/7
83 CORRAL, OR OCHOCO #2, OR 230.00 230.00 Wood - H 10.00 0 1 1557.4
ACSR/TW
36/7
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 1272ACSR 36/1
88 DIXONVILLE, OR RESTON (BPA), OR 230.00 230.00 Wood - H 17.00 0 1 795 ACSR
26/7
89 FAIRVIEW (BPA), OR ISTHMUS, OR 230.00 230.00 Wood - H 12.00 0 1 1272
ACSR 36/1
90 FIREHOLE, WY MONUMENT, WY 230.00 230.00 Wood - H 49.00 0 1 1272ACSR 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 1557.4ACSR/TW36/7
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 ACSR
45/7
96 GONDER (NV Energy), UT - NV STATE LINE PAVANT, UT 230.00 230.00 Wood - H 98.00 0 1 795 ACSR
45/7
97 DIXONVILLE, OR GRANTS PASS, OR 230.00 230.00 Wood - H 62.00 0 1 1272ACSR 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 1272
ACSR 36/1
102 KLAMATH FALLS, OR MALIN, OR 230.00 230.00 Wood - H 36.00 0 1 1272ACSR 36/1
103 LIMA, WY ROBERTSON CREEK METERING STATION, WY 230.00 230.00 Wood - H 2.00 0 1 1272ACSR 45/7
104 LONE PINE, OR KLAMATH FALLS, OR 230.00 230.00 Wood - H 76.00 0 1 795 ACSR26/7
105 LONE PINE, OR MERIDIAN #1, OR 230.00 230.00 Steel - SP 5.00 0 1
1272
ACSR54/19
106 LONE PINE, OR MERIDIAN #2, OR 230.00 230.00 Steel - SP 5.00 0 1 1272
ACSR 36/1
107 MCNARY (BPA), OR WALLA WALLA, WA 230.00 230.00 Wood - H 56.00 0 1 1272
ACSR 36/1
108 MCNARY (BPA), OR WALLULA, WA 230.00 230.00 Wood - H 29.00 0 1
1158.4
ACSS/TW
25/7
109 MERIDIAN, OR GRANTS PASS, OR 230.00 230.00 Wood - H 35.00 0 1 1272
ACSR 36/1
110 MONUMENT, WY EXXON, WY 230.00 230.00 Wood - H 13.00 0 1 1272ACSR 36/1
111 MONUMENT, WY CRAVEN CREEK, WY 230.00 230.00 Wood - H 20.00 0 1 1272ACSR 45/7
112 NAUGHTON, WY TREASURETON, ID 230.00 230.00 Wood - H 80.00 0 1 1272ACSR 45/7
113 NAUGHTON, WY MONUMENT, WY 230.00 230.00 Wood - H 30.00 0 1
1272ACSR 36/1
114 NAUGHTON, WY CRAVEN CREEK, WY 230.00 230.00 Wood - H 16.00 0 1 954 ACSR54/7
115 PALISADES SS, WY BLUE RIM, WY 230.00 230.00 Wood - H 4.00 0 1 1272ACSR 36/1
116 PAROWAN VALLEY, UT SIGURD, UT 230.00 230.00 Wood - H 94.00 0 1 795 ACSR45/7
117 PAROWAN VALLEY, UT WEST CEDAR, UT 230.00 230.00 Wood - H 26.00 0 1 795 ACSR
45/7
118 PAVANT, UT SIGURD, UT 230.00 230.00 Wood - H 43.00 0 1 795 ACSR
45/7
119 POINT OF ROCKS, WY DAVE JOHNSTON, WY 230.00 230.00 Wood - H 210.00 0 1 1272ACSR 36/1
120 POMONA, WA VANTAGE, WA 230.00 230.00 Wood - H 40.00 0 1 1272ACSR 45/7
121 POMONA, WA UNION GAP, WA 230.00 230.00 Wood - H 7.00 0 1 1272ACSR 36/1
122 RIVERTON, WY ROCK SPRINGS, WY 230.00 230.00 Wood - H 118.00 0 1 1272
ACSR 36/1
123 RIVERTON, WY THERMOPOLIS, WY 230.00 230.00 Wood - H 51.00 0 1 1272
ACSR 36/1
124 ROCK SPRINGS, WY FLAMING GORGE, UT 230.00 230.00 Wood - H 55.00 0 1 1272ACSR 36/1
125 ROCK SPRINGS, WY JIM BRIDGER, WY 230.00 230.00 Wood - H 35.00 0 1 1272ACSR 36/1
126 ROCK SPRINGS, WY MONUMENT, WY 230.00 230.00 Wood - H 41.00 0 1 1272ACSR 36/1
127 SHERIDAN (MDU), WY BUFFALO, WY 230.00 230.00 Wood - H 40.00 0 1 795 ACSR
26/7
128 SHERIDAN (MDU), WY YELLOWTAIL, MT 230.00 230.00 Wood - H 62.00 0 1 795 ACSR
26/7
129 SHIRLEY BASIN, WY DUNLAP RANCH, WY 230.00 230.00 Wood - H 12.00 0 1 795 ACSR26/7
130 SWIFT No. 1, WA SWIFT No. 2, WA 230.00 230.00 Wood - H 2.00 0 1 954 ACSR45/7
131 SWIFT No. 2, WA WOODLAND (BPA) SS, WA 230.00 230.00 Wood - H 23.00 0 1 954 ACSR45/7
132 TALBOT, WA MARENGO II, WA 230.00 230.00 Wood - H 7.00 0 1 795 ACSR
26/7
133 TAP TO HANNA, OR NICKEL MOUNTAIN, OR 230.00 230.00 Wood - H 9.00 0 1 795 ACSR
26/7
134 THERMOPOLIS, WY YELLOWTAIL, MT 230.00 230.00 Wood - H 176.00 0 1 1272ACSR 36/1
135 TREASURETON, ID BRADY, ID 230.00 230.00 Wood - H 66.00 0 1 795 ACSR26/7
136 TROUTDALE (BPA), OR GRESHAM (PGE), OR 230.00 230.00 Steel Tower 6.00 0 1 954 ACSR45/7
137 TROUTDALE (BPA), OR LINNEMAN (PGE), OR 230.00 230.00 Steel Tower 0.00 6 1 900 ACSR
54/7
138 UNION GAP, WA MIDWAY (BPA), WA 230.00 230.00 Wood - H 39.00 0 1 954 ACSR
45/7
139 WALLA WALLA, WA LEWISTON (AVISTA), ID 230.00 230.00 Wood - H 45.00 0 1 1272ACSR 36/1
140 WALLA WALLA, WA WANAPUM (GPUD), WA 230.00 230.00 Wood - H 33.00 0 1 1272ACSR 36/1
141 WANAPUM (GPUD), WA POMONA, WA 230.00 230.00 Wood - H 37.00 0 1 1272ACSR 36/1
142 WINDSTAR, WY GLENROCK, WY 230.00 230.00 Wood - H 13.00 0 1 1272ACSR 45/7
143 WYODAK, WY BUFFALO, WY 230.00 230.00 Wood - H 69.00 0 1 1272
ACSR 36/1
144 YAMSAY (BPA), OR KLAMATH FALLS, OR 230.00 230.00 Wood - H 63.00 0 1 795 ACSR
26/7
145 230kV Costs and Expenses 32,692,649 546,193,177 578,885,826 244,594 2,685,656 385,617 3,315,867
146 (t)
ANTELOPE, ID GOSHEN, ID 161.00 161.00 Wood - H 45.00 0 1 397.5ACSR 26/7
147 (u)
BIG GRASSY, ID JEFFERSON, ID 161.00 161.00 Wood - H 0.00 21 1 250HH CU/7
148 BONNEVILLE, ID EAGLEROCK, ID 161.00 161.00 Wood - SP 9.00 0 1 954 ACSR
45/7
149 EAGLEROCK, ID GOSHEN, ID 161.00 161.00 Wood - H 15.00 0 1 1272
ACSR 45/7
150 GOSHEN, ID GRACE, ID 161.00 161.00 Wood - H 57.00 0 1 250HH CU/7
151 (v)
GOSHEN, ID JEFFERSON, ID 161.00 161.00 Wood - H 0.00 29 1 250HH CU/7
152 GOSHEN, ID RIGBY, ID 161.00 161.00 Wood - H 31.00 0 1 397.5ACSR 26/7
153 GOSHEN, ID SUGARMILL, ID 161.00 161.00 Wood - SP 17.00 0 1 795 AAC
/37
154 GOSHEN, ID SUGARMILL, ID 161.00 161.00 Wood - SP 26.00 0 1
1557.4
ACSR/TW
36/7
155 RIGBY, ID REXBURG, ID 161.00 161.00 Wood - SP 12.00 0 1 1272
ACSR
156 RIGBY, ID JEFFERSON, ID 161.00 161.00 Wood - SP 18.00 0 1 397.5ACSR 26/7
157 SUGARMILL, ID RIGBY, ID 161.00 161.00 Wood - SP 17.00 0 1 397.5ACSR 26/7
158 YELLOWTAIL, MT RIMROCK, MT 161.00 161.00 Wood - H 46.00 0 1 556.5ACSR 26/7
159 161 kV Costs and Expenses 661,223 42,191,740 42,852,963 18,565 126,884 16,188 161,637
160 90TH SOUTH, UT DUMAS #1, UT 138.00 138.00 Wood - H 6.00 0 1 795 AAC/37
161 90TH SOUTH, UT DUMAS #2, UT 138.00 138.00 Wood - H 6.00 0 1 795 AAC/37
162 90TH SOUTH, UT OQUIRRH, UT 138.00 138.00 Wood - SP 13.00 0 1 795 ACSR26/7
163 90TH SOUTH, UT SANDY, UT 138.00 138.00 Steel - SP 1.00 0 1 795 AAC
/37
164 ABAJO, UT PINTO, UT 138.00 138.00 Wood - H 44.00 0 1 397.5
ACSR 26/7
165 ABAJO, UT SAN JUAN, UT 138.00 138.00 Wood - SP 10.00 0 1 795 ACSR26/7
166 AGRIUM, UT THREEMILE KNOLL, ID 138.00 138.00 Wood - H 4.00 0 1 397.5ACSR 26/7
167 ANSCHTZ CO-GEN, WY EVANSTON, WY 138.00 138.00 Wood - H 21.00 0 1 795 ACSR26/7
168 (w)
ANTELOPE, ID SCOVILLE #1, ID 138.00 138.00 Wood - H 1.00 0 1 397.5
ACSR 26/7
169 (x)
ANTELOPE, ID SCOVILLE #2, ID 138.00 138.00 Wood - H 1.00 0 1 397.5
ACSR 26/7
170 ASHGROVE, UT CLOVER, UT 138.00 138.00 Wood - H 26.00 0 1 397.5
ACSR 26/7
171 ASHLEY, UT CARBON, UT 138.00 138.00 Wood - H 101.00 0 1 397.5ACSR 26/7
172 ASHLEY, UT VERNAL, UT 138.00 138.00 Wood - H 12.00 0 1 397.5ACSR 26/7
173 BANGERTER, UT OQUIRRH, UT 138.00 138.00 Wood - H 0.00 6 1 1557.4ACSR/TW36/7
174 BARNEYS, UT GRINDING, UT 138.00 138.00 Wood - SP 1.00 0 1 1557.4ACSR/TW36/7
175 BDO, UT BDO TAP, UT 138.00 138.00 Wood - SP 1.00 0 1 397.5ACSR 26/7
176 BEN LOMOND, UT ANGEL, UT 138.00 138.00 Steel - SP 24.00 0 1 397.5
ACSR 26/7
177 BEN LOMOND, UT BRIGHAM CITY, UT 138.00 138.00 Wood - H 14.00 0 1 1272
ACSR 45/7
178 BEN LOMOND #1, UT EL MONTE, UT 138.00 138.00 Steel - SP 14.00 0 1 795 ACSR45/7
179 BEN LOMOND #2, UT EL MONTE, UT 138.00 138.00 Wood - H 0.00 13 1 795 ACSR45/7
180 BEN LOMOND, UT HONEYVILLE, UT 138.00 138.00 Steel Tower 22.00 0 1 250 CUHD/12
181 BEN LOMOND, UT SYRACUSE #1, UT 138.00 230.00 Steel Tower 7.00 13 1 795 AAC
/37
182 BEN LOMOND, UT SYRACUSE, UT 138.00 138.00 Steel Tower 58.00 0 1 1272
ACSR 45/7
183 BEN LOMOND, UT W ZIRCONIUM, UT 138.00 138.00 Wood - SP 14.00 0 1 795 AAC/37
184 BEN LOMOND, UT WHEELON, UT 138.00 138.00 Steel Tower 42.00 0 1 250 CUHD/12
185 BONANZA, UT CHAPITA, UT 138.00 138.00 Wood - H 9.00 0 1 795 ACSR26/7
186 BRIDGERLAND, UT GREEN CANYON, UT 138.00 138.00 Wood - SP 16.00 0 1 1272
ACSR 45/7
187 BRIGHAM CITY, UT WHEELON, UT 138.00 138.00 Wood - H 24.00 0 1 795 ACSR
26/7
188 BUTLERVILLE, UT 90TH SOUTH, UT 138.00 138.00 Steel - SP 9.00 0 1 795 AAC/37
189 CAMERON, UT MILFORD, UT 138.00 138.00 Wood - SP 25.00 0 1 397.5ACSR 26/7
190 CAMERON, UT PAROWAN, UT 138.00 138.00 Wood - H 35.00 0 1 397.5ACSR 26/7
191 CAMERON, UT SIGURD, UT 138.00 138.00 Wood - H 63.00 0 1 397.5
ACSR 26/7
192 CANYON COMP, WY STR 204, WY 138.00 138.00 Wood - H 12.00 0 1 795 ACSR
26/7
193 CARBON, UT HELPER #2, UT 138.00 138.00 Wood - H 2.00 0 1 556.5ACSR 26/7
194 CARBON, UT MOAB, UT 138.00 138.00 Wood - H 120.00 0 1 954 ACSR54/7
195 CARBON, UT SPANISH FORK #1, UT 138.00 138.00 Steel Tower 54.00 0 1 795 ACSR26/7
196 CARBON, UT SPANISH FORK #2, UT 138.00 138.00 Steel Tower 52.00 0 1 1272
ACSR 45/7
197 (y)
CENTRAL (UAMPS) #2, UT SAINT GEORGE, UT 138.00 138.00 Steel - SP 20.00 0 1 1272
ACSR 45/7
198 (z)
CENTRAL (UAMPS) #3, UT SAINT GEORGE, UT 138.00 138.00 Steel - SP 0.00 20 1 1272ACSR 45/7
199 CLEAR CREEK, WY PAINTER, UT 138.00 138.00 Wood - SP 5.00 0 1 795 ACSR26/7
200 CLOVER, UT BURRASTON PONDS METERING, UT 138.00 138.00 Wood - SP 2.00 0 1 397.5ACSR 26/7
201 CLOVER, UT NEBO, UT 138.00 138.00 Wood - SP 8.00 0 1 1272
ACSR 45/7
202 COLUMBIA, UT SUNNYSIDE, UT 138.00 138.00 Wood - H 2.00 0 1 397.5
ACSR 26/7
203 COTTONWOOD, UT HAMMER, UT 138.00 138.00 Wood - SP 5.00 0 1 795 AAC
/37
204 COTTONWOOD, UT MCCLELLAND, UT 138.00 138.00 Steel - SP 6.00 0 1 795 AAC/37
205 COTTONWOOD, UT SILVER CREEK, UT 138.00 138.00 Wood - SP 30.00 0 1 397.5ACSR 26/7
206 CUTLER, UT WHEELON, UT 138.00 138.00 Wood - SP 1.00 0 1 250 CUHD/12
207 DRY CREEK, UT SPANISH FORK, UT 138.00 138.00 Steel - SP 5.00 0 1 1272
ACSR 45/7
208 DUMAS, UT WESTFIELD, UT 138.00 138.00 Wood - SP 19.00 0 1 795 ACSR
26/7
209 DYNAMO, UT TRI-CITY #1, UT 138.00 138.00 Steel - SP 2.00 0 1 795 ACSR26/7
210 DYNAMO, UT TRI-CITY #2, UT 138.00 138.00 Steel - SP 0.00 3 1 795 ACSR26/7
211 EAGLE MOUNTAIN, UT PONY EXPRESS, UT 138.00 138.00 Wood - SP 10.00 0 1 795 ACSR26/7
212 EAST LAYTON, UT 105 TAP, UT 138.00 138.00 Steel - SP 15.00 0 1 795 ACSR26/7
213 EBAY TAP, UT OQUIRRH, UT 138.00 138.00 Wood - SP 1.00 0 1 795 ACSR
26/7
214 EL MONTE, UT PIONEER, UT 138.00 138.00 Steel - SP 1.00 0 1 1272
ACSR 45/7
215 EL MONTE, UT STR30B, UT 138.00 138.00 Steel - SP 9.00 0 1 1272ACSR 45/7
216 EMERY, UT CLAWSON, UT 138.00 138.00 Wood - SP 0.00 4 2 397.5ACSR 26/7
217 EVANSTON, WY RAILROAD, UT 138.00 138.00 Wood - SP 3.00 0 1 795 ACSR26/7
218 FORT DOUGLAS, UT MCCLELLAND, UT 138.00 138.00 Wood - SP 3.00 0 1
1557.4
ACSR/TW36/7
219 FRANKLIN, ID GREEN CANYON, UT 138.00 138.00 Wood - SP 25.00 0 1 397.5
ACSR 26/7
220 FRANKLIN, ID TREASURETON, ID 138.00 138.00 Wood - SP 10.00 0 1 795 ACSR
26/7
221 GADSBY, UT JORDAN, UT 138.00 138.00 Wood - SP 1.00 0 1 1272ACSR 45/7
222 GADSBY, UT TERMINAL, UT 138.00 138.00 Wood - SP 6.00 0 1 1272ACSR 45/7
223 GADSBY, UT THIRD WEST, UT 138.00 138.00 Wood - SP 1.00 0 1 1557.4ACSR/TW36/7
224 GRAPHITE, UT MOUNTAIN VIEW, UT 138.00 138.00 Wood - SP 1.00 0 1 397.5ACSR 26/7
225 GREEN CANYON, UT NIBLEY, UT 138.00 138.00 Wood - SP 7.00 0 1 1272
ACSR 45/7
226 GREEN CANYON, UT WHEELON, UT 138.00 138.00 Wood - SP 19.00 0 1 397.5
ACSR 26/7
227 GRINDING, UT OQUIRRH, UT 138.00 138.00 Wood - SP 3.00 0 1 795 ACSR45/7
228 GRINDING, UT TOOELE, UT 138.00 138.00 Wood - SP 14.00 0 1 795 ACSR45/7
229 HALE, UT MIDWAY, UT 138.00 138.00 Wood - H 19.00 0 1 397.5ACSR 26/7
230 HALE, UT SPANISH FORK, UT 138.00 138.00 Wood - H 18.00 0 1 1272
ACSR 45/7
231 HALE, UT TANNER, UT 138.00 138.00 Wood - H 7.00 0 1 1272
ACSR 45/7
232 HAMMER, UT BUTLERVILLE, UT 138.00 138.00 Wood - SP 0.00 2 1 795 ACSR26/7
233 HIGHLAND, UT BULL RIVER (LEHI #5), UT 138.00 138.00 Wood - SP 7.00 0 1 1272ACSR 45/7
234 HONEYVILLE, UT LAMPO, UT 138.00 138.00 Wood - H 25.00 0 1 397.5ACSR 26/7
235 HONEYVILLE, UT WHEELON, UT 138.00 138.00 Steel Tower 0.00 14 1 250 CUHD
/12
236 HUNTINGTON, UT MCFADDEN, UT 138.00 138.00 Wood - H 7.00 0 1 397.5
ACSR 26/7
237 JERUSALEM, UT NEBO, UT 138.00 138.00 Wood - H 26.00 0 1 397.5
ACSR 26/7
238 JORDAN, UT MCCLELLAND, UT 138.00 138.00 Wood - SP 5.00 0 1 795 AAC/37
239 JORDAN, UT TERMINAL, UT 138.00 138.00 Wood - SP 6.00 0 1 1272AAC/91
240 JORDAN, UT THIRD WEST, UT 138.00 138.00 Wood - SP 3.00 0 1
1557.4ACSR/TW
36/7
241 KEARNS, UT TAYLORSVILLE, UT 138.00 138.00 Wood - SP 3.00 0 1 795 ACSR
26/7
242 KEARNS, UT WEST VALLEY, UT 138.00 138.00 Wood - SP 2.00 0 1 1557.4ACSR/TW
36/7
243 LONE PEAK, UT CAMP WILLIAMS, UT 138.00 138.00 Steel - SP 0.00 8 1 1272ACSR 45/7
244 MCCLELLAND, UT MIDVALLEY, UT 138.00 138.00 Wood - SP 6.00 0 1 795 ACSR26/7
245 MCFADDEN, UT BLACKHAWK, UT 138.00 138.00 Wood - H 11.00 0 1 795 ACSR26/7
246 MID VALLEY, UT 90TH SOUTH, UT 138.00 138.00 Wood - H 9.00 0 1 1272
ACSR 45/7
247 MID VALLEY #2, UT COTTONWOOD, UT 138.00 138.00 Wood - SP 3.00 0 1
1557.4
ACSR/TW
36/7
248 MID VALLEY #1, UT COTTONWOOD, UT 138.00 138.00 Wood - SP 5.00 0 1
1557.4
ACSR/TW
36/7
249 MID VALLEY, UT TAYLORSVILLE, UT 138.00 138.00 Wood - SP 4.00 2 1
1557.4
ACSR/TW
36/7
250 MIDDLETON, UT ST. GEORGE, UT 138.00 138.00 Wood - H 1.00 0 1 397.5
ACSR 26/7
251 MOAB, UT PINTO, UT 138.00 138.00 Wood - H 68.00 0 1 397.5ACSR 26/7
252 NAUGHTON, WY CANYON COMP, WY 138.00 138.00 Wood - H 35.00 0 1 795 ACSR26/7
253 NAUGHTON, WY PAINTER, WY 138.00 138.00 Wood - H 44.00 0 1 795 ACSR26/7
254 NEBO, UT DRY CREEK, UT 138.00 138.00 Wood - H 33.00 0 1 795 ACSR
26/7
255 NUCOR STEEL, UT WHEELON, UT 138.00 138.00 Wood - H 13.00 0 1 397.5
ACSR 26/7
256 ONEIDA, ID OVID, UT 138.00 138.00 Wood - H 23.00 0 1 336.4ACSR 26/7
257 ONIEDA, ID GRACE, ID 138.00 138.00 Wood - H 19.00 0 1 250 CUHD/12
258 OQUIRRH, UT BARNEY, UT 138.00 138.00 Wood - H 5.00 0 1 795 ACSR26/7
259 OQUIRRH, UT BINGHAM CANYON (KCC), UT 138.00 138.00 Wood - H 8.00 0 1
1557.4
ACSR/TW36/7
260 OQUIRRH, UT TOOELE, UT 138.00 138.00 Steel - SP 44.00 0 1 1272
ACSR 45/7
261 OQUIRRH, UT WILDFLOWER TAP, UT 138.00 138.00 Wood - H 2 1
1557.4
ACSR/TW
36/7
262 WILDFLOWER TAP, UT WILDFLOWER, UT 138.00 138.00 Wood - H 1.00 1 397.5
ACSR 26/7
263 PAINTER, UT RAILROAD, UT 138.00 138.00 Wood - H 7.00 0 1 1272ACSR 45/7
264 PARRISH #105, UT TERMINAL, UT 138.00 138.00 Steel - SP 14.00 0 1 795 ACSR45/7
265 PAROWAN, UT WEST CEDAR, UT 138.00 138.00 Wood - H 21.00 0 1 397.5ACSR 26/7
266 PARRISH, UT TAP TO N. SALT LAKE, UT 138.00 138.00 Steel - SP 0.00 11 1 795 ACSR26/7
267 PARRISH, UT TERMINAL #1, UT 138.00 138.00 Steel - SP 16.00 0 1 795 ACSR
45/7
268 PARRISH, UT TERMINAL #2, UT 138.00 138.00 Steel - SP 0.00 14 1 795 ACSR
26/7
269 RAILROAD, UT CANYON COMP, WY 138.00 138.00 Wood - H 17.00 0 1 795 ACSR26/7
270 ST. GEORGE, UT PURGATORY FLAT, UT 138.00 138.00 Wood - SP 10.00 0 2 1272
ACSR 45/7
271 RED BUTTE, UT WEST CEDAR, UT 138.00 138.00 Wood - H 47.00 0 1 397.5ACSR 26/7
272 RIVERDALE, UT EAST LAYTON, UT 138.00 138.00 Steel - SP 0.00 6 1 795 ACSR26/7
273 SHICK, UT PARRISH, UT 138.00 138.00 Wood - H 0.00 10 1 250 CUHD/12
274 SILVER CREEK, UT JORDANELLE, UT 138.00 138.00 Wood - SP 9.00 0 1 795 ACSR
26/7
275 SILVER CREEK, UT RAILROAD, UT 138.00 138.00 Wood - SP 72.00 0 1 1272
ACSR 45/7
276 SPANISH FORK, UT TANNER, UT 138.00 138.00 Wood - H 10.00 0 1 1272ACSR 45/7
277 SUNRISE, UT OQUIRRH, UT 138.00 138.00 Wood - SP 0.00 2 1 1557.4ACSR/TW36/7
278 SYRACUSE, UT ANGEL #1, UT 138.00 138.00 Wood - SP 0.00 7 1 250 CUHD/12
279 SYRACUSE, UT CLEARFIELD SOUTH, UT 138.00 138.00 Steel - SP 5.00 0 1 1272ACSR 45/7
280 SYRACUSE, UT PARRISH, UT 138.00 138.00 Steel Tower 15.00 0 1 1272
ACSR 45/7
281 TAP TO ANGEL NORTH, UT TAP TO PARRISH, UT 138.00 138.00 Wood - H 13.00 0 1 795 AAC
/37
282 TAYLORSVILLE, UT 90TH SOUTH, UT 138.00 138.00 Wood - SP 6.00 2 1 795 AAC/37
283 TERMINAL, UT KENNECOTT, UT 138.00 138.00 Steel - SP 16.00 0 1 795 ACSR26/7
284 TERMINAL, UT MIDVALLEY #1, UT 138.00 138.00 Wood - H 7.00 0 1 1272ACSR 45/7
285 TERMINAL, UT MIDVALLEY #2, UT 138.00 138.00 Wood - H 7.00 0 1
1557.4
ACSR/TW36/7
286 TERMINAL, UT ROWLEY, UT 138.00 138.00 Wood - H 53.00 0 1 795 AAC
/37
287 TERMINAL, UT TOOELE, UT 138.00 138.00 Wood - H 24.00 6 1 397.5
ACSR 26/7
288 TERMINAL, UT WEST VALLEY, UT 138.00 138.00 Wood - SP 7.00 0 1 1557.4ACSR/TW
36/7
289 THREEMILE KNOLL, ID GRACE #1, ID 138.00 138.00 Wood - H 17.00 0 1 250 CUHD/12
290 THREEMILE KNOLL, ID GRACE #2, ID 138.00 138.00 Wood - H 17.00 0 1 1272ACSR 45/7
291 THREEMILE KNOLL, ID MONSANTO #1, ID 138.00 138.00 Wood - H 2.00 0 1 1557.4ACSR/TW36/7
292 THREEMILE KNOLL, ID MONSANTO #2, ID 138.00 138.00 Steel - SP 2.00 0 1 1272ACSR 45/7
293 TIMP #1, UT DYNAMO, UT 138.00 138.00 Steel - SP 2.00 0 1
1557.4
ACSR/TW36/7
294 TIMP #2, UT DYNAMO, UT 138.00 138.00 Steel - SP 0.00 2 1 1557.4ACSR/TW36/7
295 TIMP, UT HALE, UT 138.00 138.00 Steel - SP 4.00 0 1 1557.4ACSR/TW36/7
296 TIMP, UT SPANISH FORK, UT 138.00 138.00 Wood - H 23.00 0 1 1557.4ACSR/TW36/7
297 TIMP, UT VINEYARD, UT 138.00 138.00 Wood - SP 2.00 0 1 1272ACSR 45/7
298 TREASURETON, ID GRACE, ID 138.00 138.00 Steel Tower 25.00 0 1 250 CUHD
/12
299 TREASURETON, ID GRACE #2, ID 138.00 138.00 Steel Tower 0.00 25 1 250 CUHD
/12
300 TREASURETON, ID ONEIDA, ID 138.00 138.00 Wood - H 6.00 0 1 250 CUHD/12
301 TRI-CITY, UT OQUIRRH, UT 138.00 138.00 Wood - SP 3.00 19 1 1557.4ACSR/TW36/7
302 TRI-CITY, UT SUNRISE, ID 138.00 138.00 Wood - SP 19.00 0 1 1557.4ACSR/TW36/7
303 TRI-CITY, UT WESTFIELD, UT 138.00 138.00 Wood - H 15.00 0 1 1272ACSR 45/7
304 VERNAL (WAPA), UT NAPLES, UT 138.00 138.00 Wood - SP 1.00 0 1 1557.4ACSR/TW36/7
305 WEST CEDAR, UT THREE PEAKS, UT 138.00 138.00 Wood - SP 20.00 0 1 795 ACSR26/7
306 WEST VALLEY, UT OQUIRRH, UT 138.00 138.00 Wood - H 9.00 0 1
1557.4
ACSR/TW36/7
307 WESTFIELD, UT HALE, UT 138.00 138.00 Wood - H 13.00 0 1 795 ACSR
26/7
308 (aa)
WHEELON, UT AMERICAN FALLS, ID 138.00 138.00 Wood - H 82.00 0 1 250 CUHD
/12
309 WHEELON #1, UT TREASURETON, ID 138.00 138.00 Steel Tower 29.00 0 1 250 CUHD/12
310 WHEELON #2, UT TREASURETON, ID 138.00 138.00 Steel Tower 0.00 29 1 250 CUHD/12
311 WHEELON #3, UT TREASURETON, ID 138.00 138.00 Wood - H 29.00 0 1 250 CUHD/12
312 138 kV Costs and Expenses 34,668,696 432,203,879 466,872,575 287,930 1,098,874 168,379 1,555,183
313 All 115kV Lines 1,669.00 6,298,108 320,914,740 327,212,848 64,390 2,819,611 428,331 3,312,332
314 All 69kV Lines 2,914.00 9,038,595 384,590,594 393,629,189 201,167 4,692,065 309,110 5,202,342
315 All 57kV Lines 107.00 141,468 13,396,885 13,538,353 10,327 20,947 5,695 36,969
316 All 46kV Lines 2,531.00 11,842,000 303,588,401 315,430,401 227,520 1,689,063 40,949 1,957,532
36 TOTAL 17,354.00 666.00 310 283,906,264 4,290,514,840 4,574,421,104 1,246,724 17,211,309 2,688,993 21,147,026
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 ("BPA"), each with an undivided interest of 50.0%. Plant cost reported for this line
represents PacifiCorp's 50.0% share. Operations and maintenance costs are sharedbetween the two parties and responsibility is as follows: PacifiCorp 58.0% and the BPA 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 BPA,each with an undivided interest of 50.0%. Plant cost reported for this line represents PacifiCorp's 50.0% share.
Operations and maintenance costs are shared between the two parties and responsibility is as follows: PacifiCorp 58.0% and the BPA 42.0%.
(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
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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
LineNo.
(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)(l)(m)(n)(o)(p)(q)
1 OUTLOOK, WA PUNKIN CENTER #2, WA 6 Wood - SP 16 1 1 795 ACSR 26/7 Vertical 10'115 293,878 1,922,431 2,093,556 (a)4,309,865 Overground
2 OQUIRRH, UT WILDFLOWER TAP, UT 2 Wood - SP 16 2 2 1,557 ACSR/TW36/7 Vertical 10'138 (2,728)(2,239)(b)(c)(4,967)Overground
44 TOTAL 7 32 3 3 293,878 1,919,703 2,091,317 4,304,898
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 Configurationand Spacing
Voltage KV
(Operating)
Land
andLandRights
Poles,
TowersandFixtures
Conductorsand
Devices
AssetRetire.
Costs
Total Construction
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
FOOTNOTE DATA
(a) Concept: CostOfTransmissionLinesAdded
Costs are estimated between Poles, Towers and Fixtures in column (m) and Conductors and Devices in column (n).
(b) Concept: CostOfTransmissionLinesAdded
Negative balance due to customer overpayments exceeding costs.
(c) Concept: CostOfTransmissionLinesAdded
Costs are estimated between Poles, Towers and Fixtures in column (m) and Conductors and Devices in column (n).
FERC FORM NO. 1 (REV. 12-03)Page 424-425
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 LITTLE SHASTA, CA Distribution Unattended 69.00 7.20 2.40 2 3
16 LUCERNE, CA Distribution Unattended 115.00 12.47 9 1
17 MACDOEL, CA Distribution Unattended 69.00 20.80 37 2
18 MCCLOUD, CA Distribution Unattended 69.00 12.47 6 1
19 MILLER REDWOOD, CA Distribution Unattended 69.00 12.47 4 3
20 MONTAGUE, CA Distribution Unattended 69.00 12.47 6 1
21 MORRISON CREEK, CA Distribution Unattended 69.00 12.47 14 1
22 MOUNT SHASTA, CA Distribution Unattended 69.00 12.47 29 5
23 NEWELL, CA Distribution Unattended 69.00 12.47 13 1
24 NORTH DUNSMUIR, CA Distribution Unattended 69.00 12.47 6 6
25 NORTHCREST, CA Distribution Unattended 69.00 12.47 20 4
26 NUTGLADE, CA Distribution Unattended 69.00 2.40 2 3
27 PATRICKS CREEK, CA Distribution Unattended 115.00 7.20 1 1
28 PEREZ, CA Distribution Unattended 69.00 12.47 2 3
29 REDWOOD, CA Distribution Unattended 69.00 12.47 9 3
30 SCOTT BAR, CA Distribution Unattended 69.00 12.47 2 3
31 SEIAD, CA Distribution Unattended 69.00 12.47 2 3
32 SHASTINA, CA Distribution Unattended 69.00 20.80 18 3
33 SHOTGUN CREEK, CA Distribution Unattended 69.00 12.47 1 1
Name and Location of Substation Transmission or Distribution Attended or Unattended Primary Voltage (In MVa)Secondary Voltage (In
MVa)
TertiaryVoltage
(In
MVa)
CapacityofSubstation
(In
Service)(In MVa)
Number ofTransformersIn Service
Number ofSpareTransformers
Type of
Equipment
Number
of Units
TotalCapacity(In MVa)
34 SMITH RIVER, CA Distribution Unattended 69.00 12.47 6 3
35 SNOW BRUSH, CA Distribution Unattended 69.00 7.20 1 3
36 SOUTH DUNSMUIR, CA Distribution Unattended 69.00 4.16 2 3
37 TULELAKE, CA Distribution Unattended 69.00 12.47 20 1
38 TUNNEL, CA Distribution Unattended 69.00 12.47 2.40 6 6
39 WALKER BRYAN, CA Distribution Unattended 69.00 12.47 9 3
40 YUBA, CA Distribution Unattended 69.00 12.47 4 3
41 YUROK, CA Distribution Unattended 69.00 12.47 4 3
42 ALTURAS, CA (s)
Transmission Unattended 115.00 69.00 12.47 35 4
43 WEED, CA (t)
Transmission Unattended 115.00 69.00 75 2
44 YREKA, CA (u)
Transmission Unattended 115.00 69.00 12.47 95 2
45 COPCO #2, CA Transmission Attended 115.00 69.00 12.47 52 4
46 COPCO #2 230KV, CA Transmission Attended 230.00 115.00 12.47 500 2
47 AGER, CA Transmission Unattended 115.00 69.00 12.47 5 3
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 ASHTON, ID Distribution Attended 46.00 12.47 2.40 15 2
51 TANNER, ID Distribution Attended 46.00 12.47 4 1
52 ALEXANDER, ID Distribution Unattended 46.00 12.47 4 1
53 AMMON, ID Distribution Unattended 161.00 13.20 44 2
54 ANDERSON, ID Distribution Unattended 69.00 12.47 20 1
55 ARCO, ID Distribution Unattended 69.00 12.47 6 1
56 ARIMO, ID Distribution Unattended 46.00 12.47 8 1
57 BANCROFT, ID Distribution Unattended 46.00 12.47 4 1
58 BELSON, ID Distribution Unattended 69.00 12.47 14 1
59 BERENICE, ID Distribution Unattended 69.00 12.47 11 1
60 CAMAS, ID Distribution Unattended 69.00 12.47 14 1
61 CANYON CREEK, ID Distribution Unattended 69.00 24.90 20 1
62 CHESTERFIELD, ID Distribution Unattended 46.00 12.47 5 1
63 CINDER BUTTE, ID Distribution Unattended 161.00 12.47 30 1
64 CLEMENTS, ID Distribution Unattended 69.00 12.47 13 1
65 CLIFTON, ID Distribution Unattended 46.00 12.47 11 1
66 COVE, ID Distribution Unattended 46.00 12.47 6 1
67 DOWNEY, ID Distribution Unattended 46.00 12.47 5 1
68 DUBOIS, ID Distribution Unattended 69.00 12.47 13 1
69 EASTMONT, ID Distribution Unattended 69.00 12.47 14 1
70 EGIN, ID Distribution Unattended 69.00 12.47 14 1
71 EIGHT MILE, ID Distribution Unattended 46.00 12.47 4 1
72 GEORGETOWN, ID Distribution Unattended 69.00 12.47 6 1
73 GRACE CITY, ID Distribution Unattended 46.00 12.47 14 1
74 HAMER, ID Distribution Unattended 69.00 12.47 14 1
75 HAYES, ID Distribution Unattended 69.00 12.47 9 1
76 HENRY, ID Distribution Unattended 46.00 7.20 1 1
77 HOLBROOK, ID Distribution Unattended 69.00 12.47 6 1
78 HOOPES, ID Distribution Unattended 69.00 12.47 9 1
79 HORSLEY, ID Distribution Unattended 46.00 12.47 4 1
80 IDAHO FALLS, ID Distribution Unattended 46.00 12.47 20 1
81 INDIAN CREEK, ID Distribution Unattended 69.00 7.20 3 1
82 JEFFCO, ID Distribution Unattended 69.00 24.90 22 1
83 KETTLE, ID Distribution Unattended 69.00 24.90 14 1
84 LAVA, ID Distribution Unattended 46.00 12.47 6 1
85 LUND, ID Distribution Unattended 46.00 12.47 5 1
86 MCCAMMON, ID Distribution Unattended 46.00 12.47 4 1
87 MENAN, ID Distribution Unattended 69.00 12.47 11 1
88 MERRILL, ID Distribution Unattended 69.00 12.47 20 1
89 MILLER, ID Distribution Unattended 69.00 12.47 5 1
90 MONTPELIER, ID Distribution Unattended 69.00 12.47 11 1
91 MOODY, ID Distribution Unattended 69.00 24.90 14 1
92 MUD LAKE, ID Distribution Unattended 69.00 12.47 14 1
93 NEWDALE, ID Distribution Unattended 69.00 12.47 20 1
94 OSGOOD, ID Distribution Unattended 69.00 12.47 20 1
95 PRESTON, ID Distribution Unattended 46.00 12.47 13 1
96 RAYMOND, ID Distribution Unattended 69.00 12.47 6 1
97 RENO, ID Distribution Unattended 69.00 12.47 20 1
98 REXBURG, ID Distribution Unattended 161.00 12.47 210 3
99 ROBERTS, ID Distribution Unattended 69.00 12.47 8 1
100 RUBY, ID Distribution Unattended 69.00 12.47 7 1
101 SAND CREEK, ID Distribution Unattended 69.00 12.47 40 2
102 SANDUNE, ID Distribution Unattended 69.00 24.90 30 1
103 SHELLEY, ID Distribution Unattended 46.00 12.47 20 1
104 SMITH, ID Distribution Unattended 69.00 12.47 20 1
105 SOUTH FORK, ID Distribution Unattended 69.00 12.47 14 1
106 SPUD, ID Distribution Unattended 46.00 12.47 8 1
107 ST CHARLES, ID Distribution Unattended 69.00 12.47 5 1
108 SUGAR CITY, ID Distribution Unattended 69.00 12.47 13 1
109 SUNNYDELL, ID Distribution Unattended 69.00 12.47 13 1
110 TARGHEE, ID Distribution Unattended 46.00 12.47 4 1
111 THORNTON, ID Distribution Unattended 69.00 12.47 7 1
112 UCON, ID Distribution Unattended 69.00 12.47 7 1
113 WATKINS, ID Distribution Unattended 69.00 24.90 14 1
114 WEBSTER, ID Distribution Unattended 69.00 12.47 20 1
115 WESTON, ID Distribution Unattended 46.00 12.47 4 1
116 WESTWOOD, ID Distribution Unattended 161.00 13.20 30 1
117 WINSPER, ID Distribution Unattended 69.00 24.90 22 1
118 (a)
GOSHEN, ID
(v)
Transmission Unattended 345.00 161.00 13.80 955 5
119 MALAD, ID (w)
Transmission Unattended 138.00 69.00 6.60 39 4 1
120 RIGBY, ID (x)
Transmission Unattended 161.00 69.00 13.80 229 4 2
121 SAINT ANTHONY, ID (y)
Transmission Unattended 69.00 46.00 2.40 33 2
122 GRACE, ID Transmission Attended 161.00 138.00 12.47 217 2
123 AMPS, ID Transmission Unattended 230.00 69.00 12.47 75 1
124 (b)
ANTELOPE, ID Transmission Unattended 230.00 161.00 13.80 419 3
125 (c)
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 FRANKLIN, ID Transmission Unattended 138.00 69.00 13.80 75 1
130 (d)
JEFFERSON, ID Transmission Unattended 161.00 69.00 6.60 133 (bv)2
131 (e)
MIDPOINT, ID Transmission Unattended 500.00 345.00 34.50 1500 3 1
132 OVID, ID Transmission Unattended 138.00 69.00 105 2
133 SCOVILLE, ID Transmission Unattended 138.00 69.00 13.80 67 1
134 SUGARMILL, ID Transmission Unattended 161.00 69.00 12.47 268 4
135 (f)
THREEMILE KNOLL, ID Transmission Unattended 345.00 138.00 13.20 775 2
136 TREASURETON, ID Transmission Unattended 230.00 138.00 13.80 534 2
137 (g)
COLSTRIP, MT Transmission Attended 500.00 230.00 68 2
138 (h)
BROADVIEW, MT Transmission Unattended 500.00 230.00 32 2
139 YELLOWTAIL, MT Transmission Unattended 230.00 161.00 13.20 100 1
140 WESTSIDE, OR Distribution Attended 69.00 12.47 23 9
141 26TH STREET, OR Distribution Unattended 20.80 4.16 5 1
142 35TH STREET, OR Distribution Unattended 20.80 2.40 15 3
143 AGNESS AVE, OR Distribution Unattended 115.00 12.47 25 1
144 ALBINA, OR Distribution Unattended 115.00 12.47 120 2
145 ALCAN, OR Distribution Unattended 20.80 12.47 4 1
146 ALDERWOOD, OR Distribution Unattended 69.00 12.47 45 2
147 ARLINGTON, OR Distribution Unattended 69.00 12.47 5 1
148 ASHLAND, OR Distribution Unattended 115.00 12.47 20 1
149 ATHENA, OR Distribution Unattended 69.00 12.47 9 1
150 BANDON TIE, OR Distribution Unattended 20.80 12.47 8 3 1
151 BEACON, OR Distribution Unattended 69.00 12.47 11 3
152 BEALL LANE, OR Distribution Unattended 115.00 12.47 25 1
153 BEATTY, OR Distribution Unattended 69.00 12.47 6 1
154 BLALOCK, OR Distribution Unattended 69.00 12.47 2 3
155 BLOSS, OR Distribution Unattended 115.00 12.47 32 2
156 BLY, OR Distribution Unattended 69.00 12.47 8 3
157 BOISE CASCADE, OR Distribution Unattended 69.00 12.47 4.16 3 1
158 BONANZA, OR Distribution Unattended 69.00 12.47 9 3
159 BOND, OR Distribution Unattended 69.00 12.47 25 1
160 BROOKHURST, OR Distribution Unattended 115.00 12.47 50 2
161 BROWNSVILLE, OR Distribution Unattended 69.00 20.80 13 1
162 BRYANT, OR Distribution Unattended 69.00 12.47 40 2
163 BUCHANAN, OR Distribution Unattended 115.00 20.80 45 2
164 BUCKAROO, OR Distribution Unattended 69.00 12.47 34 2
165 CAMPBELL, OR Distribution Unattended 115.00 12.47 45 2
166 CANNON BEACH, OR Distribution Unattended 115.00 12.47 13 1
167 CANYONVILLE, OR Distribution Unattended 115.00 12.47 25 1
168 CARNES, OR Distribution Unattended 69.00 12.47 9 3
169 CASEBEER, OR Distribution Unattended 69.00 20.80 20 1
170 CAVEMAN, OR Distribution Unattended 115.00 12.47 45 2
171 CHERRY LANE, OR Distribution Unattended 69.00 12.47 25 1
172 CHILOQUIN MARKET, OR Distribution Unattended 69.00 12.47 9 3
173 CHINA HAT, OR Distribution Unattended 69.00 12.47 25 1
174 CIRCLE BLVD, OR Distribution Unattended 115.00 20.80 80 2
175 CLEVELAND AVE, OR Distribution Unattended 69.00 12.47 45 2
176 CLOAKE, OR Distribution Unattended 69.00 20.80 20 1
177 COBURG, OR Distribution Unattended 69.00 20.80 2.40 10 3
178 COLISEUM, OR Distribution Unattended 20.80 4.16 12 2
179 COLUMBIA, OR Distribution Unattended 115.00 69.00 7.20 128 3 1
180 COOS RIVER, OR Distribution Unattended 115.00 20.80 20 1
181 COQUILLE, OR Distribution Unattended 115.00 20.80 40 2
182 CREEK, OR Distribution Unattended 69.00 34.50 5 1
183 CROOKED RIVER RANCH, OR Distribution Unattended 69.00 20.80 25 2
184 CROWFOOT, OR Distribution Unattended 115.00 20.80 20 1
185 CULLY, OR Distribution Unattended 115.00 12.47 25 1
186 CULVER, OR Distribution Unattended 69.00 12.47 7.20 13 1
187 DAIRY, OR Distribution Unattended 69.00 12.47 25 1
188 DALLAS, OR Distribution Unattended 115.00 20.80 50 2
189 DALREED, OR Distribution Unattended 230.00 34.50 13.20 95 4 1
190 DEVILS LAKE, OR Distribution Unattended 115.00 20.80 50 2
191 DIXON, OR Distribution Unattended 115.00 4.16 7.20 7 1
192 DODGE BRIDGE, OR Distribution Unattended 69.00 20.80 25 2
193 DOWELL, OR Distribution Unattended 115.00 12.47 25 1
194 EASY VALLEY, OR Distribution Unattended 115.00 12.47 45 2
195 EMPIRE, OR Distribution Unattended 115.00 20.80 20 1
196 ENTERPRISE, OR Distribution Unattended 69.00 20.80 19 2
197 FERN HILL, OR Distribution Unattended 115.00 12.47 7.20 13 1
198 FIELDER CREEK, OR Distribution Unattended 115.00 20.80 20 1
199 FISH HOLE, OR Distribution Unattended 115.00 69.00 12.47 19 3
200 FOOTHILLS, OR Distribution Unattended 69.00 12.47 21 4
201 FORT KLAMATH, OR Distribution Unattended 20.80 12.47 3 1
202 FRALEY, OR Distribution Unattended 69.00 12.47 5 3
203 GARDEN VALLEY, OR Distribution Unattended 69.00 20.80 20 1
204 GLENDALE, OR Distribution Unattended 230.00 12.47 25 2
205 GLENEDEN, OR Distribution Unattended 20.80 4.16 6 1
206 GLIDE, OR Distribution Unattended 115.00 12.47 13 1
207 GOLD HILL, OR Distribution Unattended 69.00 12.47 11 3
208 GORDON HOLLOW, OR Distribution Unattended 69.00 20.80 6 1
209 GOSHEN, OR Distribution Unattended 115.00 20.80 20 1
210 GRANT STREET, OR Distribution Unattended 115.00 20.80 45 2
211 GREEN, OR Distribution Unattended 69.00 12.47 25 1
212 GRIFFIN CREEK, OR Distribution Unattended 115.00 12.47 20 1
213 HAMAKER, OR Distribution Unattended 69.00 12.47 8 3
214 HARRISBURG, OR Distribution Unattended 69.00 20.80 13 1
215 HENLEY, OR Distribution Unattended 69.00 12.47 6 3
216 HERMISTON, OR Distribution Unattended 69.00 12.47 20 1
217 HILLVIEW, OR Distribution Unattended 115.00 20.80 45 2
218 HINKLE, OR Distribution Unattended 69.00 12.47 20 1
219 HOLLADAY, OR Distribution Unattended 115.00 12.47 75 3
220 HOLLYWOOD, OR Distribution Unattended 115.00 12.47 50 2
221 HOOD RIVER, OR Distribution Unattended 69.00 12.47 40 2
222 HORNET, OR Distribution Unattended 69.00 12.47 20 1
223 HUMBUG, OR Distribution Unattended 69.00 12.47 9 1
224 HUNTERS CIRCLE, OR Distribution Unattended 69.00 12.47 13 1
225 ILLAHEE FLATS, OR Distribution Unattended 115.00 7.20 2 1
226 INDEPENDENCE, OR Distribution Unattended 69.00 20.80 25 1
227 JEFFERSON, OR Distribution Unattended 69.00 20.80 13 1
228 JEROME PRAIRIE, OR Distribution Unattended 115.00 12.47 25 1
229 JORDAN POINT, OR Distribution Unattended 115.00 12.47 20 1
230 JOSEPH, OR Distribution Unattended 20.80 12.47 6 1 1
231 JUNCTION CITY, OR Distribution Unattended 69.00 20.80 22 2
232 KENWOOD, OR Distribution Unattended 69.00 12.47 3 3
233 KILLINGSWORTH, OR Distribution Unattended 69.00 12.47 40 2
234 KNAPPA SVENSEN, OR Distribution Unattended 115.00 12.47 4.16 6 1
235 LAKEPORT, OR Distribution Unattended 69.00 12.47 50 2
236 LANCASTER, OR Distribution Unattended 69.00 20.80 13 3
237 LEBANON, OR Distribution Unattended 115.00 20.80 45 2
238 LINCOLN, OR Distribution Unattended 115.00 12.47 105 3
239 LOCKHART STREET, OR Distribution Unattended 115.00 20.80 40 2
240 LYONS, OR Distribution Unattended 69.00 20.80 25 2
241 MADRAS, OR Distribution Unattended 69.00 12.47 7.20 25 2
242 MALLORY, OR Distribution Unattended 115.00 12.47 25 1
243 MARYS RIVER, OR Distribution Unattended 115.00 20.80 20 1
244 MCKAY, OR Distribution Unattended 69.00 12.47 2.40 25 1
245 MEDCO, OR Distribution Unattended 115.00 12.47 20 1
246 MEDFORD, OR Distribution Unattended 115.00 12.47 67 8
247 MERLIN, OR Distribution Unattended 115.00 12.47 45 2
248 MERRILL, OR Distribution Unattended 69.00 12.47 17 6
249 MINAM, OR Distribution Unattended 69.00 12.47 0 1
250 MODOC, OR Distribution Unattended 69.00 12.47 6 3
251 MONPAC, OR Distribution Unattended 115.00 69.00 13.20 50 1
252 MURDER CREEK, OR Distribution Unattended 115.00 20.80 100 4
253 MYRTLE CREEK, OR Distribution Unattended 69.00 12.47 14 1
254 MYRTLE POINT, OR Distribution Unattended 115.00 20.80 9 1
255 NELSCOTT, OR Distribution Unattended 20.80 4.16 4 1
256 NEW DESCHUTES, OR Distribution Unattended 69.00 12.47 25 1
257 NEW O'BRIEN, OR Distribution Unattended 115.00 12.47 9 1
258 OAK KNOLL, OR Distribution Unattended 115.00 12.47 45 2
259 OAKLAND, OR Distribution Unattended 115.00 12.47 8 1
260 OREMET, OR Distribution Unattended 115.00 20.80 75 3
261 OREMET FORGE, OR Distribution Unattended 20.80 4.16 2 3
262 OVERPASS, OR Distribution Unattended 69.00 12.47 7.20 45 2
263 PACIFIC CAST, OR Distribution Unattended 20.80 4.16 3 3
264 PALLETTE, OR Distribution Unattended 69.00 20.80 1 1 1
265 PARK STREET, OR Distribution Unattended 115.00 12.47 40 2
266 PARKROSE, OR Distribution Unattended 115.00 12.47 37 2
267 PENDLETON, OR Distribution Unattended 69.00 12.47 43 6 1
268 PILOT ROCK, OR Distribution Unattended 69.00 12.47 22 2
269 POWELL BUTTE, OR Distribution Unattended 115.00 12.47 13 1
270 PRINEVILLE, OR Distribution Unattended 115.00 12.47 50 2
271 PROVOLT, OR Distribution Unattended 69.00 12.47 11 3
272 QUEEN AVE, OR Distribution Unattended 69.00 20.80 50 2
273 RED BLANKET, OR Distribution Unattended 69.00 4.16 2 3
274 REDMOND, OR Distribution Unattended 115.00 12.47 50 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
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 SCIO, OR Distribution Unattended 69.00 12.47 8 1
286 SEASIDE, OR Distribution Unattended 115.00 12.47 40 2
287 SELMA, OR Distribution Unattended 115.00 12.47 9 1
288 SHASTA VIEW, OR Distribution Unattended 20.80 4.16 3 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 25 1
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 SWAN LAKE, OR Distribution Unattended 20.80 12.47 5 2
301 SWEET HOME, OR Distribution Unattended 115.00 20.80 42 2
302 TAKELMA, OR Distribution Unattended 115.00 20.80 13 1
303 TALENT, OR Distribution Unattended 115.00 12.47 50 2
304 TEXUM, OR Distribution Unattended 69.00 12.47 25 1
305 TILLER, OR Distribution Unattended 115.00 12.47 1 1
306 TOLO, OR Distribution Unattended 69.00 12.47 11 1
307 TURKEY HILL, OR Distribution Unattended 69.00 12.47 13 3
308 UMAPINE, OR Distribution Unattended 69.00 12.47 20 1
309 UMATILLA, OR Distribution Unattended 69.00 12.47 25 2
310 USBR PUMP, OR Distribution Unattended 12.47 2.40 1 3
311 VERNON, OR Distribution Unattended 115.00 12.47 7.20 50 2
312 VILAS, OR Distribution Unattended 115.00 12.47 25 1
313 VILLAGE GREEN, OR Distribution Unattended 115.00 20.80 40 2
314 VINE STREET, OR Distribution Unattended 69.00 20.80 30 1
315 WALLOWA, OR Distribution Unattended 69.00 12.47 7 1
316 WARM SPRINGS, OR Distribution Unattended 69.00 20.80 13 3
317 WARRENTON, OR Distribution Unattended 115.00 12.47 38 2
318 WASCO, OR Distribution Unattended 20.80 4.16 2 3
319 WECOMA BEACH, OR Distribution Unattended 20.80 4.16 3 1
320 WESTON, OR Distribution Unattended 69.00 12.47 25 1
321 WEYERHAEUSER, OR Distribution Unattended 69.00 12.47 40 2
322 WHITE CITY, OR Distribution Unattended 115.00 12.47 65 3
323 WILLOW COVE, OR Distribution Unattended 34.50 4.16 28 3
324 WINSTON, OR Distribution Unattended 69.00 12.47 23 3
325 YEW AVENUE, OR Distribution Unattended 115.00 12.47 25 1
326 YOUNGS BAY, OR Distribution Unattended 115.00 12.47 37 2
327 BEND, OR (z)
Transmission Attended 69.00 12.47 31 3
328 APPLEGATE, OR (aa)
Transmission Unattended 115.00 69.00 12.47 65 2
329 BELKNAP, OR (ab)
Transmission Unattended 115.00 69.00 13.20 65 3
330 CALAPOOYA, OR (ac)
Transmission Unattended 230.00 20.80 12.47 88 2
331 CAVE JUNCTION, OR (ad)
Transmission Unattended 115.00 69.00 13.20 70 2
332 CHILOQUIN, OR (ae)
Transmission Unattended 230.00 115.00 12.47 131 5 1
333 COVE, OR (af)
Transmission Unattended 230.00 69.00 2.40 127 3
334 HAZELWOOD, OR (ag)
Transmission Unattended 115.00 69.00 12.47 106 3
335 (i)
HURRICANE, OR
(ah)
Transmission Unattended 230.00 69.00 29 2
336 JACKSONVILLE, OR (ai)
Transmission Unattended 115.00 69.00 13.20 75 2
337 KNOTT, OR (aj)
Transmission Unattended 115.00 57.00 12.47 172 5
338 MILE HI, OR (ak)
Transmission Unattended 115.00 69.00 12.47 39 4
339 PILOT BUTTE, OR (al)
Transmission Unattended 230.00 69.00 400 4
340 RIDDLE, OR (am)
Transmission Unattended 115.00 69.00 75 2
341 (j)
ROUNDUP, OR
(an)
Transmission Unattended 230.00 69.00 67 2
342 SCENIC, OR (ao)
Transmission Unattended 115.00 69.00 13.20 70 3
343 SNOW GOOSE, OR (ap)
Transmission Unattended 500.00 230.00 34.50 650 3 1
344 WINCHESTER, OR (aq)
Transmission Unattended 115.00 69.00 12.47 75 5
345 LEMOLO 1, OR Transmission Attended 12.47 7.20 2 3
346 PARRISH GAP, OR Transmission Attended 230.00 69.00 12.47 150 1
347 COLD SPRINGS, OR Transmission Unattended 230.00 69.00 66 2
348 DIAMOND HILL, OR Transmission Unattended 230.00 69.00 12.47 75 1
349 DIXONVILLE 230, OR Transmission Unattended 230.00 115.00 13.80 344 6
350 (k)
DIXONVILLE 500, OR Transmission Unattended 500.00 230.00 34.50 650 3 1
351 FRIEND, OR Transmission Unattended 230.00 115.00 12.47 500 2
352 FRY, OR Transmission Unattended 230.00 115.00 12.47 500 2 2
353 GRANTS PASS, OR Transmission Unattended 230.00 115.00 12.47 583 4 2
354 ISTHMUS, OR Transmission Unattended 230.00 115.00 13.80 250 1
355 KLAMATH FALLS, OR Transmission Unattended 230.00 69.00 13.80 251 6
356 LONE PINE, OR Transmission Unattended 230.00 115.00 13.80 733 10
357 (l)
MALIN, OR Transmission Unattended 500.00 230.00 13.80 775 4 1
358 (m)
MERIDIAN, OR Transmission Unattended 500.00 230.00 34.50 1300 6 1
359 NICKEL MOUNTAIN, OR Transmission Unattended 230.00 115.00 12.47 125 1
360 PONDEROSA, OR Transmission Unattended 230.00 115.00 12.47 500 2
361 PROSPECT CENTRAL, OR Transmission Unattended 115.00 69.00 12.47 45 3 1
362 (n)
SANTIAM TIE, OR Transmission Unattended 230.00 69.00 12.47 75 1
363 TROUTDALE, OR Transmission Unattended 230.00 115.00 13.20 500 3
364 TUCKER, OR Transmission Unattended 115.00 69.00 12.47 100 2
365 WHETSTONE, OR Transmission Unattended 230.00 115.00 12.47 250 1
366 PIONEER PLANT, UT Distribution Attended 138.00 12.47 30 1
367 WEST VALLEY, UT Distribution Attended 138.00 12.47 30 1
368 106TH SOUTH, UT Distribution Unattended 138.00 12.47 30 1
369 118TH SOUTH, UT Distribution Unattended 138.00 12.47 30 1
370 23RD STREET, UT Distribution Unattended 46.00 12.47 13 1
371 70TH SOUTH, UT Distribution Unattended 138.00 12.47 30 1
372 ALTAVIEW, UT Distribution Unattended 46.00 12.47 45 2
373 AMALGA, UT Distribution Unattended 46.00 12.47 11 1
374 AMERICAN FORK, UT Distribution Unattended 138.00 12.47 30 1
375 ANGEL, UT Distribution Unattended 138.00 46.00 12.47 135 3
376 ARAGONITE, UT Distribution Unattended 46.00 12.47 1 1
377 AURORA, UT Distribution Unattended 46.00 12.47 3 1
378 BANGERTER, UT Distribution Unattended 138.00 13.20 63 2
379 BDO, UT Distribution Unattended 138.00 12.47 30 1
380 BEAR RIVER, UT Distribution Unattended 46.00 12.47 17 2
381 BENJAMIN, UT Distribution Unattended 46.00 12.47 4 1
382 BINGHAM, UT Distribution Unattended 46.00 13.20 25 1
383 BLACK MOUNTAIN, UT Distribution Unattended 46.00 7.20 1 1
384 BLUE CREEK, UT Distribution Unattended 46.00 12.47 2 3
385 BLUFF, UT Distribution Unattended 69.00 12.47 2 3
386 BLUFFDALE, UT Distribution Unattended 46.00 12.47 14 1
387 BOTHWELL, UT Distribution Unattended 46.00 12.47 4 1
388 BRIAN HEAD, UT Distribution Unattended 34.50 12.47 14 1
389 BRIGHTON, UT Distribution Unattended 46.00 24.90 29 2
390 BROOKLAWN, UT Distribution Unattended 46.00 12.47 6 1
391 BRUNSWICK, UT Distribution Unattended 46.00 12.47 7.20 62 3
392 BURTON, UT Distribution Unattended 34.50 12.47 11 3
393 BUSH, UT Distribution Unattended 46.00 12.47 14 1
394 CANNON, UT Distribution Unattended 46.00 12.47 13 1
395 CANYONLANDS, UT Distribution Unattended 69.00 12.47 1 1
396 CAPITOL, UT Distribution Unattended 46.00 12.47 20 1
397 CARBIDE, UT Distribution Unattended 69.00 12.47 3 1
398 CARBONVILLE, UT Distribution Unattended 46.00 12.47 6 1
399 CARLISLE, UT Distribution Unattended 138.00 12.47 30 1
400 CASTO, UT Distribution Unattended 46.00 12.47 28 1
401 CENTENNIAL, UT Distribution Unattended 138.00 12.47 40 2
402 CENTERVILLE, UT Distribution Unattended 46.00 12.47 22 1
403 CENTRAL, UT Distribution Unattended 46.00 12.47 9 1
404 CHAPEL HILL, UT Distribution Unattended 138.00 12.47 30 1
405 CHERRYWOOD, UT Distribution Unattended 138.00 12.47 55 2
406 CIRCLEVILLE, UT Distribution Unattended 69.00 12.47 3 1
407 CLEAR CREEK, UT Distribution Unattended 46.00 12.47 4 1
408 CLEAR LAKE, UT Distribution Unattended 69.00 12.47 0 3
409 CLEARFIELD SOUTH, UT Distribution Unattended 138.00 12.47 60 2
410 CLINTON, UT Distribution Unattended 138.00 12.47 50 2
411 CLIVE, UT Distribution Unattended 46.00 12.47 4 1
412 COALVILLE, UT Distribution Unattended 138.00 12.47 22 1
413 COLD WATER CANYON, UT Distribution Unattended 138.00 12.47 30 1
414 COLEMAN, UT Distribution Unattended 138.00 69.00 6.60 106 4
415 COLTON WELL, UT Distribution Unattended 46.00 2.40 1 3
416 COMMERCE, UT Distribution Unattended 138.00 12.47 30 1
417 COPPER HILLS, UT Distribution Unattended 138.00 13.20 30 1
418 CORRINE, UT Distribution Unattended 46.00 12.47 3 1
419 COVE FORT, UT Distribution Unattended 46.00 12.47 2 3
420 COZYDALE, UT Distribution Unattended 138.00 12.47 30 1
421 CRANER FLAT, UT Distribution Unattended 138.00 7.20 40 2
422 CROSS HOLLOW, UT Distribution Unattended 138.00 12.47 20 1
423 CUDAHY, UT Distribution Unattended 138.00 12.47 30 1
424 DAMMERON VALLEY, UT Distribution Unattended 34.50 12.47 5 1
425 DECADE, UT Distribution Unattended 138.00 13.20 60 2
426 DECKER LAKE, UT Distribution Unattended 138.00 12.47 55 2
427 DELLE, UT Distribution Unattended 46.00 12.47 6 1
428 DELTA, UT Distribution Unattended 69.00 46.00 13.20 48 3
429 DEWEYVILLE, UT Distribution Unattended 46.00 12.47 4 1
430 DIMPLE DELL, UT Distribution Unattended 138.00 12.47 60 2
431 DRAPER, UT Distribution Unattended 138.00 13.20 60 2
432 DUMAS, UT Distribution Unattended 138.00 12.47 60 2
433 EAST BENCH, UT Distribution Unattended 138.00 12.47 30 1
434 EAST HYRUM, UT Distribution Unattended 46.00 12.47 6 1
435 EAST LAYTON, UT Distribution Unattended 138.00 12.47 60 2
436 EAST MILLCREEK, UT Distribution Unattended 46.00 12.47 20 1
437 EDEN, UT Distribution Unattended 46.00 12.47 19 2
438 ELBERTA, UT Distribution Unattended 46.00 12.47 5 1
439 ELK MEADOWS, UT Distribution Unattended 46.00 12.47 3 1
440 ELSINORE, UT Distribution Unattended 46.00 12.47 2 1
441 EMERY CITY, UT Distribution Unattended 69.00 12.47 3 3
442 EMIGRATION, UT Distribution Unattended 46.00 12.47 25 1
443 ENOCH, UT Distribution Unattended 138.00 12.47 14 1
444 ENTERPRISE VALLEY, UT Distribution Unattended 138.00 12.47 10 1
445 EUREKA, UT Distribution Unattended 46.00 12.47 3 1
446 FARMINGTON, UT Distribution Unattended 138.00 13.20 60 2
447 FAYETTE, UT Distribution Unattended 46.00 12.47 1 2
448 FERRON, UT Distribution Unattended 69.00 12.47 5 1
449 FIELDING, UT Distribution Unattended 46.00 12.47 6 1
450 FIFTH WEST, UT Distribution Unattended 138.00 13.20 60 2
451 FLUX, UT Distribution Unattended 46.00 12.47 4 1
452 FOOL CREEK, UT Distribution Unattended 46.00 12.47 2 1
453 FORT DOUGLAS, UT Distribution Unattended 138.00 13.20 40 1
454 FOUNTAIN GREEN, UT Distribution Unattended 46.00 12.47 7 1
455 FREEDOM, UT Distribution Unattended 46.00 7.20 0 1
456 FRUIT HEIGHTS, UT Distribution Unattended 46.00 12.47 22 1
457 GARDEN CITY, UT Distribution Unattended 69.00 12.47 13 1
458 GATEWAY, UT Distribution Unattended 69.00 34.50 14 1 2
459 GOLD RUSH, UT Distribution Unattended 138.00 13.20 30 1
460 GORDON AVENUE, UT Distribution Unattended 138.00 12.47 30 1
461 GOSHEN UTAH, UT Distribution Unattended 46.00 12.47 7 1
462 GRANGER, UT Distribution Unattended 46.00 12.47 50 2
463 GRANTSVILLE, UT Distribution Unattended 46.00 12.47 24 1
464 GRAVEL PIT, UT Distribution Unattended 46.00 12.47 3 1
465 GROW, UT Distribution Unattended 138.00 12.47 78 3
466 GUNNISON, UT Distribution Unattended 46.00 12.47 20 1
467 HAMMER, UT Distribution Unattended 138.00 12.47 60 2
468 HAVASU, UT Distribution Unattended 69.00 12.47 3 1
469 HELPER CITY, UT Distribution Unattended 46.00 4.16 3 3
470 HERRIMAN, UT Distribution Unattended 138.00 13.20 60 2
471 HIGHLAND DISTRIBUTION, UT Distribution Unattended 46.00 12.47 25 1
472 HOGGARD, UT Distribution Unattended 138.00 12.47 50 2
473 HOLDEN, UT Distribution Unattended 46.00 12.47 4 1
474 HOLLADAY, UT Distribution Unattended 46.00 12.47 32 2
475 HUNTER, UT Distribution Unattended 46.00 12.47 22 1
476 HUNTINGTON CITY, UT Distribution Unattended 69.00 12.47 7 1
477 IRON MOUNTAIN, UT Distribution Unattended 34.50 12.47 1 3
478 IRONTON, UT Distribution Unattended 46.00 12.47 2 1
479 IVINS, UT Distribution Unattended 69.00 12.47 30 1
480 JORDAN NARROWS, UT Distribution Unattended 46.00 2.40 14 2
481 JORDAN PARK, UT Distribution Unattended 138.00 12.47 30 1
482 JORDANELLE, UT Distribution Unattended 138.00 12.47 30 1
483 JUAB, UT Distribution Unattended 46.00 12.47 4 1
484 JUDGE, UT Distribution Unattended 46.00 12.47 22 1
485 JUNCTION, UT Distribution Unattended 69.00 12.47 3 1
486 KAIBAB, UT Distribution Unattended 69.00 12.47 5 1
487 KAMAS, UT Distribution Unattended 46.00 12.47 11 1
488 KEARNS, UT Distribution Unattended 138.00 12.47 60 2
489 KENSINGTON, UT Distribution Unattended 46.00 4.16 7 1
490 KYUNE, UT Distribution Unattended 46.00 7.20 0 1
491 LAKE PARK, UT Distribution Unattended 138.00 12.47 53 2
492 LAYTON, UT Distribution Unattended 46.00 12.47 40 2
493 LEE CREEK, UT Distribution Unattended 138.00 13.20 30 1
494 LEGRANDE, UT Distribution Unattended 46.00 12.47 2 1
495 LEWISTON, UT Distribution Unattended 46.00 7.20 22 1
496 LINCOLN, UT Distribution Unattended 46.00 12.47 20 1
497 LINDON, UT Distribution Unattended 46.00 12.47 25 1
498 LISBON, UT Distribution Unattended 69.00 12.47 3 1
499 LOAFER, UT Distribution Unattended 46.00 7.20 0 1
500 LOGAN CANYON, UT Distribution Unattended 46.00 7.20 1 1
501 LONE TREE, UT Distribution Unattended 34.50 12.47 20 1
502 LOWER BEAVER, UT Distribution Unattended 46.00 13.20 0 1
503 LYNNDYL, UT Distribution Unattended 46.00 12.47 4 1
504 MAESER, UT Distribution Unattended 69.00 12.47 20 1
505 MAGNA, UT Distribution Unattended 138.00 12.47 30 1
506 MANILA, UT Distribution Unattended 138.00 12.47 30 1
507 MANTUA, UT Distribution Unattended 46.00 12.47 3 1
508 MAPLETON, UT Distribution Unattended 46.00 12.47 25 1
509 MARRIOTT, UT Distribution Unattended 46.00 12.47 20 1
510 MARYSVALE, UT Distribution Unattended 46.00 12.47 3 1
511 MATHIS, UT Distribution Unattended 46.00 12.47 9 1
512 MCCORNICK, UT Distribution Unattended 46.00 12.47 6 1
513 MCKAY, UT Distribution Unattended 46.00 12.47 28 1
514 MEADOWBROOK, UT Distribution Unattended 138.00 12.47 46.00 42 2
515 MEDICAL, UT Distribution Unattended 46.00 12.47 51 3
516 MIDLAND, UT Distribution Unattended 138.00 12.47 30 1
517 MIDVALE, UT Distribution Unattended 46.00 12.47 25 1
518 MILFORD, UT Distribution Unattended 138.00 46.00 13.20 89 2
519 MILFORD TV, UT Distribution Unattended 46.00 13.20 0 1
520 MINERSVILLE, UT Distribution Unattended 46.00 12.47 2 1
521 MOAB CITY, UT Distribution Unattended 69.00 12.47 19 2
522 MOORE, UT Distribution Unattended 69.00 12.47 3 1
523 MORGAN, UT Distribution Unattended 46.00 12.47 5 1
524 MORONI, UT Distribution Unattended 46.00 12.47 6 1
525 MORTON COURT, UT Distribution Unattended 138.00 12.47 65 2
526 MOUNTAIN DELL, UT Distribution Unattended 46.00 12.47 5 1
527 MOUNTAIN GREEN, UT Distribution Unattended 46.00 12.47 9 1
528 MYTON, UT Distribution Unattended 69.00 12.47 6 1
529 NAPLES, UT Distribution Unattended 138.00 13.20 30 1
530 NEW HARMONY, UT Distribution Unattended 69.00 12.47 7 1
531 NEWGATE, UT Distribution Unattended 46.00 12.47 16 1
532 NEWTON, UT Distribution Unattended 46.00 12.47 5 1
533 NIBLEY, UT Distribution Unattended 138.00 24.90 54 2
534 NORTH BENCH, UT Distribution Unattended 46.00 12.47 25 1
535 NORTH FIELDS, UT Distribution Unattended 46.00 12.47 2 1
536 NORTH LOGAN, UT Distribution Unattended 46.00 12.47 25 1
537 NORTH OGDEN, UT Distribution Unattended 46.00 12.47 22 1
538 NORTH SALT LAKE, UT Distribution Unattended 46.00 13.20 25 1
539 NORTHEAST, UT Distribution Unattended 46.00 12.47 45 2
540 NORTHRIDGE, UT Distribution Unattended 46.00 12.47 14 1
541 OAKLAND AVENUE, UT Distribution Unattended 46.00 12.47 22 1
542 OAKLEY, UT Distribution Unattended 46.00 12.47 6 1
543 OLYMPUS, UT Distribution Unattended 46.00 12.47 22 1
544 OPHIR, UT Distribution Unattended 46.00 12.47 3 1
545 ORANGE, UT Distribution Unattended 46.00 12.47 20 1
546 ORANGEVILLE, UT Distribution Unattended 69.00 12.47 14 1
547 OREM, UT Distribution Unattended 46.00 12.47 48 2
548 PANGUITCH, UT Distribution Unattended 69.00 12.47 5 1
549 PARIETTE, UT Distribution Unattended 69.00 24.90 14 1
550 PARK CITY, UT Distribution Unattended 46.00 12.47 42 2
551 PARKSIDE, UT Distribution Unattended 138.00 12.47 60 2
552 PARKWAY, UT Distribution Unattended 138.00 12.47 50 2
553 PARLEYS, UT Distribution Unattended 46.00 12.47 16 2
554 PELICAN POINT, UT Distribution Unattended 46.00 12.47 6 1
555 PETERSON, UT Distribution Unattended 46.00 12.47 72 1
556 PINE CANYON, UT Distribution Unattended 138.00 12.47 55 2
557 PINE CREEK, UT Distribution Unattended 46.00 12.47 2 1
558 PINNACLE, UT Distribution Unattended 46.00 12.47 14 1
559 PLAIN CITY, UT Distribution Unattended 138.00 12.47 22 1
560 PLEASANT GROVE, UT Distribution Unattended 138.00 12.47 30 1
561 PLEASANT VIEW, UT Distribution Unattended 46.00 12.47 14 1
562 PONY EXPRESS, UT Distribution Unattended 138.00 12.47 60 2
563 PORTER ROCKWELL, UT Distribution Unattended 138.00 13.20 60 2
564 PROMONTORY, UT Distribution Unattended 46.00 12.47 2 1
565 QUAIL CREEK, UT Distribution Unattended 69.00 12.47 14 1
566 QUARRY, UT Distribution Unattended 138.00 12.47 60 2
567 QUICHAPA, UT Distribution Unattended 34.50 7.20 4 1
568 RAINS, UT Distribution Unattended 46.00 7.20 0 1
569 RANDOLPH, UT Distribution Unattended 46.00 12.47 2 1
570 RASMUSON, UT Distribution Unattended 46.00 12.47 1 3
571 RATTLESNAKE, UT Distribution Unattended 69.00 24.90 14 1
572 RED MOUNTAIN, UT Distribution Unattended 69.00 34.50 13 1
573 REDWOOD, UT Distribution Unattended 46.00 12.47 45 2
574 RESEARCH PARK, UT Distribution Unattended 46.00 12.47 45 2
575 RICH, UT Distribution Unattended 69.00 12.47 5 1
576 RICHFIELD, UT Distribution Unattended 46.00 12.47 35 2
577 RICHMOND, UT Distribution Unattended 46.00 12.47 11 1
578 RIDGELAND, UT Distribution Unattended 138.00 12.47 40 2
579 RITER, UT Distribution Unattended 46.00 12.47 20 1
580 ROCK CANYON, UT Distribution Unattended 69.00 12.47 5 1
581 ROCKVILLE, UT Distribution Unattended 34.50 12.47 4 1
582 ROCKY POINT, UT Distribution Unattended 138.00 12.47 30 1
583 ROSE PARK, UT Distribution Unattended 46.00 12.47 42 2
584 ROYAL, UT Distribution Unattended 46.00 4.16 0 3
585 SALINA, UT Distribution Unattended 46.00 12.47 11 1
586 SANDY, UT Distribution Unattended 138.00 12.47 60 2
587 SARATOGA, UT Distribution Unattended 138.00 13.20 60 2
588 SCHOO MINE, UT Distribution Unattended 46.00 12.47 9 1
589 SCIPIO, UT Distribution Unattended 46.00 12.47 2 3
590 SCOFIELD, UT Distribution Unattended 46.00 12.47 1 3
591 SCOFIELD RESERVOIR, UT Distribution Unattended 46.00 7.20 1 1
592 SEGO CANYON, UT Distribution Unattended 69.00 12.47 14 1
593 SEVEN MILE, UT Distribution Unattended 69.00 12.47 5 1 1
594 SHARON, UT Distribution Unattended 46.00 12.47 20 1
595 SHORELINE, UT Distribution Unattended 138.00 13.20 60 2
596 SIXTH SOUTH, UT Distribution Unattended 46.00 12.47 20 1
597 SKULL VALLEY, UT Distribution Unattended 46.00 12.47 2 1
598 SKYPARK, UT Distribution Unattended 138.00 13.20 40 1
599 SNARR, UT Distribution Unattended 46.00 12.47 40 2
600 SNOWVILLE, UT Distribution Unattended 69.00 12.47 5 1
601 SOLDIER SUMMIT, UT Distribution Unattended 46.00 12.47 2 1
602 SOUTH JORDAN, UT Distribution Unattended 138.00 12.47 60 2
603 SOUTH MILFORD, UT Distribution Unattended 46.00 24.90 28 2
604 SOUTH MOUNTAIN, UT Distribution Unattended 138.00 12.47 60 2
605 SOUTH OGDEN, UT Distribution Unattended 46.00 12.47 25 1
606 SOUTH PARK, UT Distribution Unattended 138.00 12.47 30 1
607 SOUTH WEBER, UT Distribution Unattended 138.00 12.47 22 1
608 SOUTHEAST, UT Distribution Unattended 138.00 12.47 60 2
609 SOUTHWEST, UT Distribution Unattended 46.00 12.47 22 2
610 SPANISH VALLEY, UT Distribution Unattended 69.00 12.47 14 1
611 SPRINGDALE, UT Distribution Unattended 34.50 12.47 14 1
612 ST JOHN, UT Distribution Unattended 46.00 12.47 4 1
613 STANSBURY, UT Distribution Unattended 46.00 12.47 20 1
614 SUMMIT CREEK, UT Distribution Unattended 138.00 13.80 30 1
615 SUMMIT PARK, UT Distribution Unattended 46.00 12.47 7 1
616 SUNRISE, UT Distribution Unattended 138.00 12.47 60 2
617 SUTHERLAND, UT Distribution Unattended 46.00 24.90 9 1
618 TAMARISK, UT Distribution Unattended 138.00 12.47 20 1
619 TAYLOR, UT Distribution Unattended 46.00 12.47 14 1
620 THIEF CREEK, UT Distribution Unattended 138.00 24.90 14 1
621 THIRD WEST, UT Distribution Unattended 138.00 13.20 100 2
622 THIRTEENTH SOUTH, UT Distribution Unattended 46.00 12.47 22 1
623 TOOELE DEPOT, UT Distribution Unattended 46.00 12.47 25 1
624 TOQUERVILLE, UT Distribution Unattended 69.00 34.50 34 2
625 TRI-CITY, UT Distribution Unattended 138.00 12.47 30 1 1
626 UINTAH, UT Distribution Unattended 46.00 12.47 39 2
627 UNION, UT Distribution Unattended 46.00 12.47 50 2
628 VALLEY CENTER, UT Distribution Unattended 46.00 12.47 22 1
629 VERMILLION, UT Distribution Unattended 46.00 12.47 3 1
630 VERNAL, UT Distribution Unattended 69.00 12.47 33 2
631 VICKERS, UT Distribution Unattended 46.00 12.47 4 1
632 VINEYARD, UT Distribution Unattended 138.00 13.20 30 1
633 WALLSBURG, UT Distribution Unattended 138.00 12.47 13 1
634 WALNUT GROVE, UT Distribution Unattended 138.00 12.47 30 1
635 WARREN, UT Distribution Unattended 138.00 12.47 30 1
636 WASATCH STATE PARK, UT Distribution Unattended 46.00 12.47 2 3
637 WASHAKIE, UT Distribution Unattended 138.00 4.16 14 1
638 WELBY, UT Distribution Unattended 46.00 12.47 42 2
639 WELFARE, UT Distribution Unattended 46.00 12.47 11 1
640 WEST COMMERCIAL, UT Distribution Unattended 46.00 12.47 22 1
641 WEST JORDAN, UT Distribution Unattended 138.00 12.47 28 1
642 WEST OGDEN, UT Distribution Unattended 138.00 12.47 60 2
643 WEST POINT, UT Distribution Unattended 138.00 13.20 40 1
644 WEST ROY, UT Distribution Unattended 46.00 12.47 25 1
645 WEST TEMPLE, UT Distribution Unattended 46.00 7.20 53 3
646 WESTFIELD, UT Distribution Unattended 138.00 12.47 20 1
647 WESTWATER, UT Distribution Unattended 69.00 12.47 5 1
648 WHITE ROCK, UT Distribution Unattended 138.00 13.20 30 1
649 WILLOWCREEK, UT Distribution Unattended 46.00 12.47 1 1
650 WILLOWRIDGE, UT Distribution Unattended 46.00 12.47 25 1
651 WINCHESTER HILLS, UT Distribution Unattended 34.50 12.47 4 1
652 WINKLEMAN, UT Distribution Unattended 46.00 7.20 0 1
653 WOLF CREEK, UT Distribution Unattended 69.00 12.47 6 1
654 WOODRUFF, UT Distribution Unattended 46.00 12.47 2 1
655 WOODS CROSS, UT Distribution Unattended 46.00 12.47 20 1
656 90TH SOUTH, UT (ar)
Transmission Unattended 345.00 138.00 12.47 1571 5
657 BUTLERVILLE, UT (as)
Transmission Unattended 138.00 46.00 13.80 205 4
658 CAMP WILLIAMS, UT (at)
Transmission Unattended 345.00 138.00 24.90 169 2
659 COTTONWOOD, UT (au)
Transmission Unattended 138.00 46.00 12.47 312 7
660 CROYDON, UT (av)
Transmission Unattended 138.00 46.00 12.47 81 2
661 EMMA PARK, UT (aw)
Transmission Unattended 138.00 12.47 8 1
662 HALE, UT (ax)
Transmission Unattended 138.00 46.00 12.47 114 2
663 HIGHLAND, UT (ay)
Transmission Unattended 138.00 46.00 12.47 97 2
664 HORSESHOE, UT (az)
Transmission Unattended 138.00 46.00 6.60 80 2
665 JORDAN, UT (ba)
Transmission Unattended 138.00 46.00 12.47 204 3
666 MCCLELLAND, UT (bb)
Transmission Unattended 138.00 46.00 13.80 340 3
667 OQUIRRH, UT (bc)
Transmission Unattended 345.00 138.00 13.80 835 4
668 PARRISH, UT (bd)
Transmission Unattended 138.00 46.00 13.80 97 2
669 RIVERDALE, UT (be)
Transmission Unattended 138.00 46.00 6.60 180 3
670 SEVIER, UT (bf)
Transmission Unattended 138.00 46.00 6.60 34 4
671 SILVER CREEK, UT (bg)
Transmission Unattended 138.00 46.00 13.80 100 2
672 SNYDERVILLE, UT (bh)
Transmission Unattended 138.00 46.00 13.80 127 3
673 SYRACUSE, UT (bi)
Transmission Unattended 345.00 138.00 13.80 1300 6
674 TAYLORSVILLE, UT (bj)
Transmission Unattended 138.00 46.00 12.47 358 4
675 TERMINAL, UT (bk)
Transmission Unattended 345.00 138.00 12.47 1610 5
676 TIMP, UT (bl)
Transmission Unattended 138.00 46.00 7.20 130 2
677 TOOELE, UT (bm)
Transmission Unattended 138.00 46.00 13.20 249 3
678 CUTLER, UT Transmission Attended 138.00 46.00 6.60 50 1
679 EMERY, UT Transmission Attended 345.00 138.00 12.47 411 3
680 GADSBY, UT Transmission Attended 138.00 46.00 13.80 318 2
681 ABAJO, UT Transmission Unattended 138.00 69.00 13.80 67 2
682 ASHLEY, UT Transmission Unattended 138.00 69.00 12.47 134 2
683 BEN LOMOND, UT Transmission Unattended 345.00 230.00 13.80 2202 6
684 BLACK ROCK, UT Transmission Unattended 230.00 69.00 13.20 75 1
685 BLACKHAWK, UT Transmission Unattended 138.00 69.00 7.20 100 2
686 CAMERON, UT Transmission Unattended 138.00 46.00 6.60 100 4
687 CLOVER, UT Transmission Unattended 345.00 138.00 24.90 400 1
688 COLUMBIA, UT Transmission Unattended 138.00 46.00 6.60 71 2
689 EL MONTE, UT Transmission Unattended 138.00 46.00 12.47 313 3
690 GARKANE, UT Transmission Unattended 69.00 46.00 2.40 33 1
691 GREEN CANYON, UT Transmission Unattended 138.00 46.00 6.60 67 2
692 HELPER, UT Transmission Unattended 138.00 46.00 12.47 77 2
693 HONEYVILLE, UT Transmission Unattended 138.00 46.00 6.60 35 1
694 HUNTINGTON, UT Transmission Unattended 345.00 138.00 12.47 270 4
695 JERUSALEM, UT Transmission Unattended 138.00 46.00 6.60 67 1
696 LAMPO, UT Transmission Unattended 138.00 46.00 12.47 75 1
697 MATHINGTON, UT Transmission Unattended 138.00 46.00 13.20 189 6
698 MCFADDEN, UT Transmission Unattended 138.00 69.00 13.80 45 1
699 MIDDLETON, UT Transmission Unattended 138.00 69.00 6.60 137 3
700 MIDVALLEY, UT Transmission Unattended 345.00 138.00 13.80 450 1
701 MIDWAY CITY, UT Transmission Unattended 138.00 46.00 12.47 67 1
702 MINERAL PRODUCTS, UT Transmission Unattended 69.00 46.00 6.60 13 1
703 MOAB, UT Transmission Unattended 138.00 69.00 6.60 67 1
704 NEBO, UT Transmission Unattended 138.00 46.00 6.60 67 1
705 PAROWAN VALLEY, UT Transmission Unattended 230.00 138.00 13.80 138 2
706 PAVANT, UT Transmission Unattended 230.00 46.00 13.80 133 2
707 PINTO, UT Transmission Unattended 345.00 138.00 13.80 257 (bw)3
708 PURGATORY FLAT, UT Transmission Unattended 138.00 69.00 12.47 300 2
709 RED BUTTE, UT Transmission Unattended 345.00 138.00 24.90 764 6 2
710 SIGURD, UT Transmission Unattended 345.00 230.00 13.80 1075 (bx)6
711 SMITHFIELD, UT Transmission Unattended 138.00 46.00 6.60 63 2
712 SPANISH FORK, UT Transmission Unattended 345.00 138.00 13.80 1100 2
713 THREE PEAKS, UT Transmission Unattended 345.00 138.00 12.47 450 1
714 WEST CEDAR, UT Transmission Unattended 230.00 138.00 12.47 147 2
715 ATTALIA, WA Distribution Unattended 69.00 12.47 25 1
716 BOWMAN, WA Distribution Unattended 69.00 12.47 45 2
717 CASCADE KRAFT, WA Distribution Unattended 69.00 12.47 151 7
718 CENTRAL, WA Distribution Unattended 69.00 12.47 14 1
719 CLINTON, WA Distribution Unattended 115.00 12.47 25 1
720 DAYTON, WA Distribution Unattended 69.00 12.47 23 2
721 DODD ROAD, WA Distribution Unattended 69.00 20.80 25 4
722 GROMORE, WA Distribution Unattended 115.00 12.47 25 1
723 HOPLAND, WA Distribution Unattended 115.00 12.47 50 2
724 LAYMAN LUMBER, WA Distribution Unattended 12.47 7.20 3 1
725 MILL CREEK, WA Distribution Unattended 69.00 12.47 45 2
726 NACHES, WA Distribution Unattended 115.00 12.47 25 1
727 NOB HILL, WA Distribution Unattended 115.00 12.47 42 2
728 NORTH PARK, WA Distribution Unattended 115.00 12.47 45 2
729 ORCHARD, WA Distribution Unattended 115.00 12.47 50 2
730 PACIFIC, WA Distribution Unattended 115.00 12.47 28 3
731 POMEROY, WA Distribution Unattended 69.00 12.47 9 1
732 POMONA HEIGHTS, WA Distribution Unattended 230.00 115.00 12.47 325 3
733 PROSPECT POINT, WA Distribution Unattended 69.00 12.47 40 2
734 PUNKIN CENTER, WA Distribution Unattended 115.00 13.20 44 3
735 RIVER ROAD, WA Distribution Unattended 115.00 12.47 76 5
736 SELAH, WA Distribution Unattended 115.00 12.47 45 2
737 SULPHUR CREEK, WA Distribution Unattended 115.00 12.47 25 1
738 SUNNYSIDE, WA Distribution Unattended 115.00 12.47 45 2
739 TIETON, WA Distribution Unattended 115.00 34.50 29 2 1
740 TOPPENISH, WA Distribution Unattended 115.00 12.47 50 2
741 TOUCHET, WA Distribution Unattended 69.00 12.47 13 1
742 VOELKER, WA Distribution Unattended 115.00 12.47 25 1
743 WAITSBURG, WA Distribution Unattended 69.00 12.47 9 1
744 WAPATO, WA Distribution Unattended 115.00 12.47 45 2
745 WENAS, WA Distribution Unattended 115.00 12.47 25 2
746 WHITE SWAN, WA Distribution Unattended 115.00 12.47 22 2
747 WILEY, WA Distribution Unattended 115.00 12.47 45 2
748 GRANDVIEW, WA (bn)
Transmission Unattended 115.00 69.00 12.47 58 2
749 PASCO, WA (bo)
Transmission Unattended 115.00 69.00 7.20 39 9
750 UNION GAP, WA (bp)
Transmission Unattended 230.00 115.00 13.20 595 5
751 (o)
DRY GULCH, WA Transmission Unattended 115.00 69.00 50 1
752 OUTLOOK, WA Transmission Unattended 230.00 115.00 12.47 250 1
753 (p)
WALLA WALLA, WA Transmission Unattended 230.00 69.00 300 3
754 WALLULA, WA Transmission Unattended 230.00 69.00 120 2 1
755 WINE COUNTRY, WA Transmission Unattended 230.00 115.00 250 1
756 ANTELOPE MINE, WY Distribution Unattended 230.00 34.50 13.20 25 1
757 ARROWHEAD, WY Distribution Unattended 230.00 34.50 13.20 150 2
758 ASTLE STREET, WY Distribution Unattended 34.50 13.20 13 1
759 BAILEY DOME, WY Distribution Unattended 57.00 4.16 2 1
760 BAR X, WY Distribution Unattended 230.00 34.50 13.20 25 1
761 BARR NUNN, WY Distribution Unattended 115.00 12.47 30 1
762 BATTLE SPRINGS, WY Distribution Unattended 34.50 13.80 2 1
763 BELLAMY 2, WY Distribution Unattended 69.00 4.16 5 1
764 BIG MUDDY, WY Distribution Unattended 69.00 12.47 7 1
765 BIG PINEY, WY Distribution Unattended 69.00 24.90 14 1
766 BLACKS FORK, WY Distribution Unattended 230.00 34.50 13.20 225 3 1
767 BRIDGER PUMP, WY Distribution Unattended 230.00 34.50 7.20 73 4
768 BRYAN, WY Distribution Unattended 115.00 12.47 25 1
769 BUFFALO, WY Distribution Unattended 230.00 20.80 20 1 1
770 BYRON, WY Distribution Unattended 34.50 4.16 2 3
771 CASSA, WY Distribution Unattended 57.00 20.80 2 6
772 CENTER STREET, WY Distribution Unattended 115.00 12.47 13 1
773 CHAPMAN, WY Distribution Unattended 46.00 12.47 4 1
774 CHUKAR, WY Distribution Unattended 12.47 4.16 1 3
775 COKEVILLE, WY Distribution Unattended 46.00 24.90 8 1
776 COLUMBIA GENEVA, WY Distribution Unattended 230.00 12.47 45 2
777 COMMUNITY PARK, WY Distribution Unattended 115.00 12.47 50 2
778 CROOKS GAP, WY Distribution Unattended 34.50 12.47 6 1
779 DEAVER, WY Distribution Unattended 34.50 4.16 0 3
780 DEER CREEK, WY Distribution Unattended 69.00 12.47 9 1
781 DJ COAL MINE, WY Distribution Unattended 69.00 34.50 13 1
782 DRY FORK, WY Distribution Unattended 69.00 4.16 9 1
783 ELK BASIN, WY Distribution Unattended 34.50 7.20 5 1
784 ELK HORN, WY Distribution Unattended 115.00 12.47 25 1
785 EMIGRANT, WY Distribution Unattended 115.00 12.47 13 1
786 EVANS, WY Distribution Unattended 115.00 12.47 9 1
787 EVANSTON, WY Distribution Unattended 138.00 12.47 40 2
788 FIREHOLE, WY Distribution Unattended 230.00 34.50 13.20 50 2
789 FORT CASPER, WY Distribution Unattended 69.00 12.47 28 1
790 FORT SANDERS, WY Distribution Unattended 115.00 13.20 20 1
791 FRANNIE, WY Distribution Unattended 230.00 34.50 2.40 50 2
792 FRONTIER, WY Distribution Unattended 69.00 4.16 6 1
793 GARLAND, WY Distribution Unattended 230.00 34.50 13.20 45 2
794 GLENDO, WY Distribution Unattended 57.00 4.16 1 3
795 GRASS CREEK, WY Distribution Unattended 230.00 34.50 25 1
796 GREAT DIVIDE, WY Distribution Unattended 115.00 34.50 20 1
797 GREEN MOUNTAIN, WY Distribution Unattended 34.50 4.16 5 1
798 GREYBULL, WY Distribution Unattended 34.50 4.16 3 1
799 HANNA, WY Distribution Unattended 34.50 13.20 6 1
800 HILLTOP, WY Distribution Unattended 115.00 34.50 13.20 45 2 1
801 HOLLY SUGAR, WY Distribution Unattended 34.50 4.16 5 1
802 JACKALOPE, WY Distribution Unattended 115.00 13.20 55 2
803 KEMMERER, WY Distribution Unattended 69.00 24.90 14 1
804 KIRBY CREEK, WY Distribution Unattended 34.50 4.16 2 3
805 KIRBY CREEK PUMPING, WY Distribution Unattended 34.50 2.40 2 3
806 LABARGE, WY Distribution Unattended 69.00 24.90 8 6
807 LANDER, WY Distribution Unattended 34.50 12.47 25 2
808 LARAMIE, WY Distribution Unattended 115.00 13.20 50 2
809 LATHAM, WY Distribution Unattended 230.00 46.00 575 3
810 LINCH, WY Distribution Unattended 69.00 13.80 12 1
811 LITTLE MOUNTAIN, WY Distribution Unattended 230.00 34.50 20 1
812 LOVELL, WY Distribution Unattended 34.50 4.16 4 1
813 MANSFACE, WY Distribution Unattended 230.00 34.50 2.40 20 1
814 MILL IRON, WY Distribution Unattended 34.50 13.80 12 1
815 MILLS, WY Distribution Unattended 12.47 4.16 2 3
816 MINERS, WY Distribution Unattended 230.00 34.50 7.20 20 1
817 MOUNTAIN GAS, WY Distribution Unattended 34.50 12.47 4.16 3 1
818 MURPHY DOME, WY Distribution Unattended 34.50 12.47 13 1
819 NAUGHTON CONSTRUCTION, WY Distribution Unattended 69.00 12.47 2 3
820 NUGGETT, WY Distribution Unattended 69.00 7.20 0 1
821 OPAL, WY Distribution Unattended 69.00 24.90 8 1
822 ORIN, WY Distribution Unattended 57.00 7.20 1 1 1
823 OWL CREEK PUMP #1, WY Distribution Unattended 34.50 4.16 2 3
824 PARADISE, WY Distribution Unattended 69.00 24.90 30 1
825 PARCO, WY Distribution Unattended 34.50 13.20 3 1
826 PHILLIPS GAS PLANT PIPELINE, WY Distribution Unattended 12.47 2.40 1 3
827 PINEDALE, WY Distribution Unattended 69.00 24.90 20 1
828 PITCHFORK, WY Distribution Unattended 69.00 24.90 14 3 1
829 PLATTE PIPE BYRON, WY Distribution Unattended 34.50 4.16 2 3
830 PLATTE PIPE OREGON BASIN, WY Distribution Unattended 34.50 4.16 2 3
831 PLATTE RIVER DJ, WY Distribution Unattended 69.00 12.47 2 3
832 POINT OF ROCKS, WY Distribution Unattended 230.00 34.50 13.20 25 1
833 POISON SPIDER, WY Distribution Unattended 69.00 2.40 3 1
834 RAINBOW, WY Distribution Unattended 34.50 13.20 13 1
835 RAVEN, WY Distribution Unattended 230.00 34.50 12.47 200 2
836 RED BUTTE, WY Distribution Unattended 115.00 13.20 30 1
837 REFINERY, WY Distribution Unattended 115.00 12.47 45 2
838 RIVERTON, WY Distribution Unattended 230.00 34.50 13.20 77 4
839 ROCK SPRINGS 230, WY Distribution Unattended 230.00 34.50 13.20 50 2 1
840 SAGE HILL, WY Distribution Unattended 34.50 13.20 9 1
841 SHOSHONI, WY Distribution Unattended 34.50 2.40 2 3
842 SINCLAIR PIPELINE, WY Distribution Unattended 34.50 4.16 5 1
843 SLATE CREEK, WY Distribution Unattended 69.00 13.80 1 1
844 SOUTH CODY, WY Distribution Unattended 69.00 24.90 14 3 1
845 SOUTH ELK BASIN, WY Distribution Unattended 34.50 4.16 2 6
846 SOUTH TRONA, WY Distribution Unattended 230.00 34.50 13.20 150 2
847 SPRING CREEK, WY Distribution Unattended 115.00 13.20 28 1
848 SVILAR, WY Distribution Unattended 34.50 4.16 2 3
849 TEN MILE, WY Distribution Unattended 69.00 12.47 5 1
850 THERMOPOLIS TOWN, WY Distribution Unattended 34.50 4.16 5 1
851 THERMOPOLIS(WAPA), WY Distribution Unattended 115.00 34.50 25 1
852 THUNDER CREEK, WY Distribution Unattended 69.00 12.47 14 1
853 VETERANS, WY Distribution Unattended 34.50 13.20 25 2
854 WAMSUTTER AMOCO, WY Distribution Unattended 34.50 4.16 2 3
855 WARM SPRINGS SPL, WY Distribution Unattended 115.00 4.16 9 1
856 WERTZ SINCLAIR, WY Distribution Unattended 57.00 4.16 3 6
857 WEST ADAMS, WY Distribution Unattended 34.50 4.16 3 1
858 WESTVACO, WY Distribution Unattended 230.00 34.50 25 1
859 WHISKEY GULCH, WY Distribution Unattended 57.00 12.47 9 1
860 WORLAND TOWN, WY Distribution Unattended 34.50 4.16 4 1
861 WYCO BEAR CREEK, WY Distribution Unattended 20.80 2.40 1 3
862 WYCO STROUD, WY Distribution Unattended 13.20 4.16 2 3
863 WYOPO, WY Distribution Unattended 230.00 34.50 20 1 1
864 YELLOWCAKE, WY Distribution Unattended 230.00 34.50 13.20 100 2
865 (q)
JIM BRIDGER, WY
(bq)
Transmission Attended 345.00 230.00 34.50 675 4
866 BAIROIL, WY (br)
Transmission Unattended 115.00 69.00 13.20 53 3
867 CASPER, WY (bs)
Transmission Unattended 230.00 115.00 13.80 575 4
868 MIDWEST, WY (bt)
Transmission Unattended 230.00 69.00 13.20 158 3
869 OREGON BASIN, WY (bu)
Transmission Unattended 230.00 69.00 13.20 100 2
870 (r)
DAVE JOHNSTON, WY Transmission Attended 230.00 115.00 13.20 283 2 2
871 NAUGHTON, WY Transmission Attended 230.00 138.00 13.80 661 4
872 AEOLUS, WY Transmission Unattended 500.00 230.00 34.50 1600 3 1
873 ANTICLINE, WY Transmission Unattended 500.00 345.00 1600 3 1
874 CHAPPEL CREEK, WY Transmission Unattended 230.00 69.00 12.47 75 1
875 CHIMNEY BUTTE, WY Transmission Unattended 230.00 69.00 12.47 75 1
876 FOOTE CREEK, WY Transmission Unattended 230.00 34.50 12.47 196 2
877 GLENDO AUTO, WY Transmission Unattended 69.00 57.00 8 1 1
878 MUSTANG, WY Transmission Unattended 230.00 115.00 13.20 100 1
879 PLATTE, WY Transmission Unattended 230.00 115.00 13.20 140 3
880 RAILROAD, WY Transmission Unattended 230.00 138.00 24.90 448 1
881 SAGE, WY Transmission Unattended 69.00 46.00 2.40 22 1
882 STANDPIPE, WY Transmission Unattended 230.00 12.47 75 2
883 THERMOPOLIS, WY Transmission Unattended 230.00 115.00 12.47 84 1 1
884 TotalDistributionSubstationAttendedMember 102
885 TotalDistributionSubstationUnttendedMember 17,385
886 TotalTransmissionSubstationAttendedMember 3,418
887 TotalTransmissionSubstationUnattendedMember 40,590
888 Total 61,495 0
FERC FORM NO. 1 (ED. 12-96)Page 426-427
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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.
(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.
(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.
(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.
(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.
(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.
(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.
(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.
(i) 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.
(j) Concept: SubstationNameAndLocation
Substation property is owned by PacifiCorp and Bonneville Power Administration ("BPA") as defined in the facility sharing agreement where operations and maintenance costs vary by type of asset and performance responsibility.
(k) Concept: SubstationNameAndLocation
Substation is jointly owned by PacifiCorp and Bonneville Power Administration, 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%.
(l) Concept: SubstationNameAndLocation
Substation is jointly owned by PacifiCorp, BPA and Portland General Electric Company. Ownership and operations and maintenance costs vary by type of asset as defined in the operations and maintenance agreement.
(m) Concept: SubstationNameAndLocation
Substation is jointly owned by PacifiCorp and Bonneville Power Administration, 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%.
(n) Concept: SubstationNameAndLocation
Substation property is owned by PacifiCorp and Bonneville Power Administration ("BPA") as defined in the facility sharing agreement where operations and maintenance costs vary by type of asset and performance responsibility.
(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.
(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.
(q) 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.
(r) 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.
(s) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(t) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(u) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(v) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(w) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(x) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(y) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(z) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(aa) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(ab) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(ac) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(ad) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(ae) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(af) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(ag) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(ah) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(ai) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(aj) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(ak) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(al) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(am) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(an) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(ao) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(ap) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(aq) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(ar) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(as) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(at) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(au) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(av) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(aw) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(ax) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(ay) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(az) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(ba) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bb) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bc) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bd) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(be) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bf) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bg) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bh) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bi) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bj) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bk) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bl) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bm) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bn) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bo) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bp) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bq) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(br) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bs) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bt) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bu) Concept: SubstationCharacterDescription
The substation contains both transmission and distribution transformers.
(bv) Concept: NumberOfTransformersInService
Includes one 3-phase transformer
(bw) Concept: NumberOfTransformersInService
Represents three phase shifters at the substation, which does not change the voltage and reports a 3-phase bank as three transformers.
(bx) Concept: NumberOfTransformersInService
Includes one 3-phase transformer
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ Q4
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to an associated/affiliated company for non-
power goods and services. The good or service must be specific in nature. Respondents should not attempt to include or aggregate amounts in a nonspecific category such as "general".3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Line
No.
Description of the Good or Service
(a)
Name of Associated/Affiliated Company
(b)
Account(s) Chargedor Credited(c)
Amount Charged or Credited
(d)
1 Non-power Goods or Services Provided by Affiliated
2 Coal purchases Bridger Coal Company 151, 501 152,809,917
3 Coal purchases Trapper Mining Inc.151, 501 16,184,479
4 (a)
Administrative services under the IASA Berkshire Hathaway Energy Company 107, 426.4, 426.5,923 8,749,122
5 Administrative services under the IASA MidAmerican Energy Company 107, 146, 426.4,
426.5, 923 8,354,366
6 Operational support services MidAmerican Energy Company 234 238,130
7 Administrative services under the IASA Kern River Gas Transmission Company 923 3,131
8 Gas transportation services Kern River Gas Transmission Company 547 3,106,928
9 Operational support services Kern River Gas Transmission Company 107 194,897
10 Administrative services under the IASA Nevada Power Company 923 347,087
11 Materials Nevada Power Company 567.1 2,445
12 Rail services and right-of-way fees BNSF Railway Company 151, 501, 507, 567,589 (b)19,321,838
13 Banking services Bank of America Corporation 427, 431 80,532
14 Underwriting services BofA Securities, Inc.181 (c)487,500
15 Banking services The Bank of New York Mellon Corporation 426.5, 427, 431, 928,930.2 (d)232,536
16 Underwriting services BNY Mellon Capital Markets, LLC 181 (e)262,500
17 Banking services U.S. Bancorp
419, 427, 431, 537,
557, 903, 920, 928,930.2 422,061
18 Underwriting services U.S. Bancorp Investments, Inc.181 (f)487,500
19 Operational support services Marmon Utility LLC 571, 593 1,917,972
20 Rating agency fees Moody's Investors Service, Inc.181 657,224
19
20 Non-power Goods or Services Provided for Affiliated
21 Information technology and administrative support
services Bridger Coal Company 557, 501, 931 1,163,993
22 Administrative services under the IASA Berkshire Hathaway Energy Company 557, 580, 901, 903,
920, 921 4,081,647
23 Administrative services under the IASA MidAmerican Energy Company 539, 556, 557, 580,
903, 920, 921 671,846
24 Administrative services under the IASA BHE GT&S, LLC 557, 580, 903, 920,921 1,581,023
25 Administrative services under the IASA NV Energy, Inc.557, 580, 903, 920,921, 930.2 283,189
26 Operational support services BHE Wind, LLC 107 (g)6,313,358
27 Administrative services under the IASA Kern River Gas Transmission Company 557, 580, 903, 920,
921, 930 89,862
28 Operational support services Kern River Gas Transmission Company 101 208,000
42
FERC FORM NO. 1 ((NEW))Page 429
Name of Respondent:PacifiCorp
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:04/13/2022 Year/Period of ReportEnd of: 2021/ 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 allocations, as described below:Labor and Assets: An equal weighting of each company's labor and assets expressed as a percentage of the whole ((labor % + assets %) ÷ 2) determines the portion assigned to each company. Labor is 12-months ended through December of the prior year. Assets are total assets at December 31 of the prior year. Eight combinations of this allocator are used for allocating services that benefit different companies within the BHE organization.Information Technology Infrastructure: Allocates costs related to shared information technology infrastructure owned by the affiliate to other benefited affiliates based on an aggregation of various measures of usage of such infrastructure including storage capacityutilized, 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.
(b) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies
Non-power goods or services provided by BNSF Railway Company are as follows: $ 19,211,385 Rail services 110,453 Right-of-way (1) $ 19,321,838(1) Includes right-of-way fees
related to jointly owned utility facilities that are paid either directly or indirectly to BNSF Railway Company.
(c) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies
Represents a percentage of underwriting discount costs, excluding any expenses incurred by PacifiCorp in connection with a debt offering.
(d) 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, 2021. 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, 2021, the plans paid $234,843 for these trustee and custodial services.
(e) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies
Represents a percentage of underwriting discount costs, excluding any expenses incurred by PacifiCorp in connection with a debt offering.
(f) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies
Represents a percentage of underwriting discount costs, excluding any expenses incurred by PacifiCorp in connection with a debt offering.
(g) Concept: DueFromOrCreditedByTheTransactionsWithAssociatedAffiliatedCompanies
In 2021, PacifiCorp sold wind turbines previously acquired from a third party to BHE Wind, LLC, an indirect wholly owned subsidiary of BHE, for $6 million.
FERC FORM NO. 1 ((NEW))
Page 429
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