FERC Form

THIS FILING IS

Item 1:

☑ An Initial (Original) Submission

OR

☐ Resubmission No.




FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and 18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and other sanctions as provided by law. The Federal Energy Regulatory Commission does not consider these reports to be of confidential nature

Exact Legal Name of Respondent (Company)

Tucson Electric Power Company

Year/Period of Report

End of:

2022

/

Q1

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

Purpose
FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q) is a quarterly regulatory requirement which supplements the annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be non-confidential public use forms.
Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities, Licensees, and Others Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).
Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:
1. one million megawatt hours of total annual sales,
2. 100 megawatt hours of annual sales for resale,
3. 500 megawatt hours of annual power exchanges delivered, or
4. 500 megawatt hours of annual wheeling for others (deliveries plus losses).

What and Where to Submit

Submit FERC Form Nos. 1 and 3-Q electronically through the eCollection portal at https://eCollection.ferc.gov, and according to the specifications in the Form 1 and 3-Q taxonomies.
The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of the Commission at:
Secretary
Federal Energy Regulatory Commission 888 First Street, NE
Washington, DC 20426

For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to the Secretary of the Commission at the address above.

The CPA Certification Statement should:

Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting releases), and

Be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18 C.F.R. §§ 41.10-41.12 for specific qualifications.)

Schedules	Pages
Comparative Balance Sheet	110-113
Statement of Income	114-117
Statement of Retained Earnings	118-119
Statement of Cash Flows	120-121
Notes to Financial Statements	122-123

The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported.
“In connection with our regular examination of the financial statements of [COMPANY NAME] for the year ended on which we have reported separately under date of [DATE], we have also reviewed schedules [NAME OF SCHEDULES] of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below) conform in all material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist.
Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. Further instructions are found on the Commission’s website at https://www.ferc.gov/ferc-online/ferc-online/frequently-asked-questions-faqs-efilingferc-online.
Federal, State, and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-Q free of charge from https://www.ferc.gov/general-information-0/electric-industry-forms.

When to Submit
FERC Forms 1 and 3-Q must be filed by the following schedule:
1. FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and
2. FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400).
Where to Send Comments on Public Reporting Burden.
The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,168 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated to average 168 hours per response.
Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information does not display a valid control number (44 U.S.C. § 3512 (a)).

GENERAL INSTRUCTIONS

Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words and phrases in accordance with the USofA.
Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the current year's year to date amounts.
Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and completely states the fact.
For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) on the List of Schedules, pages 2 and 3.
Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to be completed only for resubmissions (see VII. below).
Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.
For any resubmissions, please explain the reason for the resubmission in a footnote to the data field.
Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different figures were used.
Schedule specific instructions are found in the applicable taxonomy and on the applicable blank rendered form.

Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:

FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff. "Self" means the respondent.

FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.

LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and” firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.

OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and “firm” means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally get out of the contract.

SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations, where the duration of each period of reservation is less than one-year.

NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions.

OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentioned classifications, such as all other service regardless of the length of the contract and service FERC Form. Describe the type of service in a footnote for each entry.

AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment.

DEFINITIONS

Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any other Commission. Name the commission whose authorization was obtained and give date of the authorization.
Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report is made.

EXCERPTS FROM THE LAW

Federal Power Act, 16 U.S.C. § 791a-825r

Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:

’Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafter defined;
'Person' means an individual or a corporation;
'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successor in interest thereof;

'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or distributing power; ......

"project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power there from to the point of junction with the distribution system or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary or appropriate in the maintenance and operation of such unit;

"Sec. 4. The Commission is hereby authorized and empowered

'To make investigations and to collect and record data concerning the utilization of the water 'resources of any region to be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity, development costs, and relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for the purposes of this Act."

"Sec. 304.

Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the Commission may by rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the proper administration of this Act. The Commission may prescribe the manner and FERC Form in which such reports shall be made, and require from such persons specific answers to all questions upon which the Commission may need information. The Commission may require that such reports shall include, among other things, full information as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other facilities, depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless the Commission otherwise specifies*.10

"Sec. 309.

The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may prescribe the FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and the time within which they shall be field..."

GENERAL PENALTIES

The Commission may assess up to $1 million per day per violation of its rules and regulations. See FPA § 316(a) (2005), 16 U.S.C. § 825o(a).

FERC FORM NO.

1/3-Q

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

Identification

01 Exact Legal Name of Respondent

Tucson Electric Power Company

02 Year/ Period of Report

End of:

2022

/

Q1

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)

88 E. Broadway Blvd., Tucson, AZ 85701

05 Name of Contact Person

Frank P. Marino

06 Title of Contact Person

Sr. VP & CFO

07 Address of Contact Person (Street, City, State, Zip Code)

88 E. Broadway Blvd., Tucson, AZ 85701

08 Telephone of Contact Person, Including Area Code

(520) 571-4000

09 This Report is An Original / A Resubmission

(1)

☑ An Original

(2)

☐ A Resubmission

10 Date of Report (Mo, Da, Yr)

05/10/2022

Quarterly Corporate Officer Certification

The undersigned officer certifies that:

I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material respects to the Uniform System of Accounts.

01 Name

Frank P. Marino

02 Title

Sr. VP & CFO

03 Signature

Frank P. Marino

04 Date Signed (Mo, Da, Yr)

05/10/2022

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.

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

List of Schedules
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)
	ScheduleIdentificationAbstract Identification	1
	ScheduleListOfSchedulesAbstract List of Schedules (Electric Utility)	2
1	ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Quarter	108
2	ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet	110
3	ScheduleStatementOfIncomeAbstract Statement of Income for the Quarter	114
4	ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Quarter	118
5	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120
6	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122
7	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Comp Income, Comp Income, and Hedging Activities	122a
8	ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep	200
9	ScheduleElectricPlantInServiceAndAccumulatedProvisionForDepreciationByFunctionAbstract Electric Plant In Service and Accum Provision For Depr by Function	208
10	ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract Transmission Service and Generation Interconnection Study Costs	231
11	ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets	232
12	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278
13	ScheduleElectricOperatingRevenuesAbstract Elec Operating Revenues (Individual Schedule Lines 300-301)	300
14	ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1)	302	NA
15	ScheduleElectricProductionOtherPowerTransmissionRegionalExpensesAbstract Electric Prod, Other Power Supply Exp, Trans and Distrib Exp	324
16	ScheduleElectricCustomerAccountServiceSalesAdministrativeAndGeneralExpensesAbstract Electric Customer Accts, Service, Sales, Admin and General Expenses	325
17	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
18	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331	NA
19	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
20	ScheduleDepreciationDepletionAndAmortizationsAbstract Deprec, Depl and Amort of Elec Plant (403,403.1,404,and 405) (except Amortization of Acquisition Adjustments)	338
21	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts Included in ISO/RTO Settlement Statements	397	NA
22	ScheduleMonthlyPeaksAndOutputAbstract Monthly Peak Loads and Energy Output	399
23	ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load	400
24	ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load	400a	NA

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

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. 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. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to Commission authorization. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were submitted to the Commission. 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. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments. State the estimated annual effect and nature of any important wage scale changes during the year. 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. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder reported on Pages 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest. (Reserved.) 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. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.

1. None
2. None
3. None
4. None
5. None
6. See the Debt and Credit Agreements in Notes to Financial Statements on pages 122 and 123, for any obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance for short-term debt and commercial paper having a maturity of one year or less. All debt issued under finance authority as approved by ACC Decision 77851, December 9, 2020, docket number E-01933A-20-0026.
7. None
8. International Brotherhood of Electric Workers Local 1116 received a wage increase of 2.75% effective January 1, 2022. TEP Unclassified (non-bargaining unit) employees received an average 3.00% wage increase that became effective March 7, 2022.
9. See Regulatory Matters and Commitments and Contingencies footnotes in Notes to Financial Statements on pages 122 and 123, for the status of materially important legal proceedings pending, and the results of any such proceedings culminated during the year.
10. None
12. See Notes to Financial Statements on pages 122 and 123.
13. Morgan C. Stoll resigned as Vice President and Chief Information Officer, effective February 21, 2022. Mary Jo Smith retired as Vice President and Policy Advisor, effective March 31, 2022. Christopher W. Norman was named Vice President, Public Policy and Corporate Strategy, effective March 07, 2022. Michael E. Sheehan was named Vice President of Resource Planning, Fuels and Wholesale Marketing, effective March 07, 2022.
14. N/A

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlant Utility Plant (101-106, 114)	200	8,127,783,352	8,129,334,186
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	271,141,024	244,240,802
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		8,398,924,376	8,373,574,988
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	3,087,132,082	3,098,767,799
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		5,311,792,294	5,274,807,189
7	NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)	202
8	NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
9	NuclearFuelAssembliesInReactorMajorOnly Nuclear Fuel Assemblies in Reactor (120.3)
10	SpentNuclearFuelMajorOnly Spent Nuclear Fuel (120.4)
11	NuclearFuelUnderCapitalLeases Nuclear Fuel Under Capital Leases (120.6)
12	AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)	202
13	NuclearFuelNet Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
14	UtilityPlantAndNuclearFuelNet Net Utility Plant (Enter Total of lines 6 and 13)		5,311,792,294	5,274,807,189
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		6,836,960	6,756,960
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		1,893,116	1,892,100
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	1,756,759	1,773,826
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228
24	OtherInvestments Other Investments (124)		55,505,618	55,874,755
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)		23,096,426	23,733,097
29	SpecialFunds Special Funds (Non Major Only) (129)
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)		61,793,842	14,391,783
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		147,096,489	100,638,321
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		145,843,616	9,365,127
36	SpecialDeposits Special Deposits (132-134)
37	WorkingFunds Working Fund (135)		1,047,377	1,124,126
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		109,265,868	134,851,865
41	OtherAccountsReceivable Other Accounts Receivable (143)		11,240,833	11,019,369
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		9,432,903	10,043,760
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		23,819,174	16,531,074
45	FuelStock Fuel Stock (151)	227	27,887,198	26,586,026
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227	425,451	385,251
47	Residuals Residuals (Elec) and Extracted Products (153)	227
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	127,312,731	127,136,100
49	Merchandise Merchandise (155)	227
50	OtherMaterialsAndSupplies Other Materials and Supplies (156)	227
51	NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157)	202/227
52	AllowanceInventoryAndWithheld Allowances (158.1 and 158.2)	228
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227	14,288,300	14,540,719
55	GasStoredCurrent Gas Stored Underground - Current (164.1)
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57	Prepayments Prepayments (165)		18,617,041	17,600,148
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		33,854,817	44,351,910
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		2,571,472	5,142,944
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		119,991,720	33,797,654
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)		61,793,842	14,391,783
65	DerivativeInstrumentAssetsHedges Derivative Instrument Assets - Hedges (176)
66	DerivativeInstrumentAssetsHedgesLongTerm (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
67	CurrentAndAccruedAssets Total Current and Accrued Assets (Lines 34 through 66)		564,938,853	417,996,770
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		18,437,634	17,140,935
70	ExtraordinaryPropertyLosses Extraordinary Property Losses (182.1)	230a
71	UnrecoveredPlantAndRegulatoryStudyCosts Unrecovered Plant and Regulatory Study Costs (182.2)	230b	2,802,511	2,898,051
72	OtherRegulatoryAssets Other Regulatory Assets (182.3)	232	455,876,801	445,598,648
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		933,419	917,738
74	PreliminaryNaturalGasSurveyAndInvestigationChargesAndOtherPreliminarySurveyAndInvestigationCharges Preliminary Natural Gas Survey and Investigation Charges 183.1)
75	OtherPreliminarySurveyAndInvestigationCharges Other Preliminary Survey and Investigation Charges (183.2)
76	ClearingAccounts Clearing Accounts (184)		1,306,045
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	699,341	296,702
79	DeferredLossesFromDispositionOfUtilityPlant Def. Losses from Disposition of Utility Plt. (187)
80	ResearchDevelopmentAndDemonstrationExpenditures Research, Devel. and Demonstration Expend. (188)	352
81	UnamortizedLossOnReacquiredDebt Unamortized Loss on Reaquired Debt (189)		5,746,844	5,189,448
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	221,159,006	219,181,924
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		704,349,511	691,223,446
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		6,728,177,147	6,484,665,726

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	ProprietaryCapitalAbstract PROPRIETARY CAPITAL
2	CommonStockIssued Common Stock Issued (201)	250	840,740,694	840,740,694
3	PreferredStockIssued Preferred Stock Issued (204)	250
4	CapitalStockSubscribed Capital Stock Subscribed (202, 205)
5	StockLiabilityForConversion Stock Liability for Conversion (203, 206)
6	PremiumOnCapitalStock Premium on Capital Stock (207)
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	855,797,894	855,797,894
8	InstallmentsReceivedOnCapitalStock Installments Received on Capital Stock (212)	252
9	DiscountOnCapitalStock (Less) Discount on Capital Stock (213)	254
10	CapitalStockExpense (Less) Capital Stock Expense (214)	254b	6,357,039	6,357,039
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	870,890,607	851,453,921
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	528,587	511,520
13	ReacquiredCapitalStock (Less) Reaquired Capital Stock (217)	250
14	NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218)
15	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	122(a)(b)	9,718,154	9,915,092
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		2,550,825,415	2,531,208,858
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	107,210,000	284,210,000
19	ReacquiredBonds (Less) Reaquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256	2,200,000,000	1,875,000,000
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		9,636,497	8,590,891
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		2,297,573,503	2,150,619,109
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		5,534,387	5,699,798
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		1,574,196	1,617,720
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		128,119,413	129,083,177
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities		1,051,862	3,848,215
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		139,718,291	138,617,662
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		275,998,149	278,866,572
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)			15,000,000
38	AccountsPayable Accounts Payable (232)		128,140,502	142,238,504
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		3,754,206	1,900,138
41	CustomerDeposits Customer Deposits (235)		13,883,648	12,995,725
42	TaxesAccrued Taxes Accrued (236)	262	48,378,043	33,424,863
43	InterestAccrued Interest Accrued (237)		17,148,130	16,264,623
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		21,226,787	20,385,377
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		38,235,281	44,140,173
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		833,074	822,017
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		11,425,167	19,702,367
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities		1,051,862	3,848,215
52	DerivativeInstrumentLiabilitiesHedges Derivative Instrument Liabilities - Hedges (245)
53	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54	CurrentAndAccruedLiabilities Total Current and Accrued Liabilities (lines 37 through 53)		281,972,976	303,025,572
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)		18,405,888	15,077,376
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	5,987,760	5,261,239
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	49,462,891	43,926,339
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	476,504,225	389,771,691
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		695,106,089	689,726,465
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		76,340,251	77,182,505
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		1,321,807,104	1,220,945,615
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		6,728,177,147	6,484,665,726

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

STATEMENT OF INCOME
Quarterly Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only. 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. 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. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l) the quarter to date amounts for other utility function for the prior year quarter. If additional columns are needed, place them in a footnote. Annual or Quarterly if applicable Do not report fourth quarter data in columns (e) and (f) Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility column in a similar manner to a utility department. Spread the amount(s) over Lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above. Use page 122 for important notes regarding the statement of income for any account thereof. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases. Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases, and a summary of the adjustments made to balance sheet, income, and expense accounts. If any notes appearing in the report to stockholders are applicable to the Statement of Income, such notes may be included at page 122. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line No.	Title of Account (a)	(Ref.) Page No. (b)	Total Current Year to Date Balance for Quarter/Year (c)	Total Prior Year to Date Balance for Quarter/Year (d)	Current 3 Months Ended - Quarterly Only - No 4th Quarter (e)	Prior 3 Months Ended - Quarterly Only - No 4th Quarter (f)	Electric Utility Current Year to Date (in dollars) (g)	Electric Utility Previous Year to Date (in dollars) (h)	Gas Utiity Current Year to Date (in dollars) (i)	Gas Utility Previous Year to Date (in dollars) (j)	Other Utility Current Year to Date (in dollars) (k)	Other Utility Previous Year to Date (in dollars) (l)
1	UtilityOperatingIncomeAbstract UTILITY OPERATING INCOME
2	OperatingRevenues Operating Revenues (400)	300	329,145,438	337,214,722	329,145,438	337,214,722	329,145,438	337,214,722
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	185,520,300	188,320,732	185,520,300	188,320,732	185,520,300	188,320,732
5	MaintenanceExpense Maintenance Expenses (402)	320	26,967,378	42,487,247	26,967,378	42,487,247	26,967,378	42,487,247
6	DepreciationExpense Depreciation Expense (403)	336	53,597,641	47,758,242	53,597,641	47,758,242	53,597,641	47,758,242
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	7,535,891	8,314,256	7,535,891	8,314,256	7,535,891	8,314,256
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336	187,917	187,838	187,917	187,838	187,917	187,838
10	AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)		95,540		95,540		95,540
11	AmortizationOfConversionExpenses Amort. of Conversion Expenses (407.2)
12	RegulatoryDebits Regulatory Debits (407.3)		2,148,865	2,148,865	2,148,865	2,148,865	2,148,865	2,148,865
13	RegulatoryCredits (Less) Regulatory Credits (407.4)
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	16,699,027	15,556,609	16,699,027	15,556,609	16,699,027	15,556,609
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	15,463	5,370,600	15,463	5,370,600	15,463	5,370,600
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	68,115	851,452	68,115	851,452	68,115	851,452
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	8,699,760	27,274,871	8,699,760	27,274,871	8,699,760	27,274,871
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	6,599,006	21,994,702	6,599,006	21,994,702	6,599,006	21,994,702
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		294,800,661	303,831,906	294,800,661	303,831,906	294,800,661	303,831,906
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		34,344,777	33,382,816	34,344,777	33,382,816	34,344,777	33,382,816
28	OtherIncomeAndDeductionsAbstract Other Income and Deductions
29	OtherIncomeAbstract Other Income
30	NonutilityOperatingIncomeAbstract Nonutilty Operating Income
31	RevenuesFromMerchandisingJobbingAndContractWork Revenues From Merchandising, Jobbing and Contract Work (415)
32	CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
33	RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417)		71,140	196,117	71,140	196,117
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		156,448	229,559	156,448	229,559
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		211,485	225,627	211,485	225,627
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	17,067	16,668	17,067	16,668
37	InterestAndDividendIncome Interest and Dividend Income (419)		170,423	102,944	170,423	102,944
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		1,671,157	7,094,000	1,671,157	7,094,000
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		7,808,868	1,216,418	7,808,868	1,216,418
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)			12,018		12,018
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		9,759,558	8,600,897	9,759,558	8,600,897
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)
44	MiscellaneousAmortization Miscellaneous Amortization (425)		5,865	5,865	5,865	5,865
45	Donations Donations (426.1)		741,771	686,447	741,771	686,447
46	LifeInsurance Life Insurance (426.2)		2,784,113	1,863,712	2,784,113	1,863,712
47	Penalties Penalties (426.3)		42,000	146,850	42,000	146,850
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		28,097	113,931	28,097	113,931
49	OtherDeductions Other Deductions (426.5)		11,143	1,714	11,143	1,714
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		3,528,989	1,206,033	3,528,989	1,206,033
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	50,190	38,640	50,190	38,640
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	367,984	2,346,054	367,984	2,346,054
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	91,275	582,768	91,275	582,768
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	50,720	50,114	50,720	50,114
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	21,628	23,558	21,628	23,558
57	InvestmentTaxCreditAdjustmentsNonutilityOperations Investment Tax Credit Adj.-Net (411.5)
58	InvestmentTaxCredits (Less) Investment Tax Credits (420)		262,712	708,190	262,712	708,190
59	TaxesOnOtherIncomeAndDeductions TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)		275,829	2,285,828	275,829	2,285,828
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		5,954,740	7,521,102	5,954,740	7,521,102
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		20,449,473	20,167,802	20,449,473	20,167,802
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		503,005	470,132	503,005	470,132
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		155,589	151,201	155,589	151,201
65	AmortizationOfPremiumOnDebtCredit (Less) Amort. of Premium on Debt-Credit (429)
66	AmortizationOfGainOnReacquiredDebtCredit (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67	InterestOnDebtToAssociatedCompanies Interest on Debt to Assoc. Companies (430)
68	OtherInterestExpense Other Interest Expense (431)		382,173	273,233	382,173	273,233
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		610,341	2,702,221	610,341	2,702,221
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		20,879,899	18,360,147	20,879,899	18,360,147
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		19,419,618	22,543,771	19,419,618	22,543,771
72	ExtraordinaryItemsAbstract Extraordinary Items
73	ExtraordinaryIncome Extraordinary Income (434)
74	ExtraordinaryDeductions (Less) Extraordinary Deductions (435)
75	NetExtraordinaryItems Net Extraordinary Items (Total of line 73 less line 74)
76	IncomeTaxesExtraordinaryItems Income Taxes-Federal and Other (409.3)	262
77	ExtraordinaryItemsAfterTaxes Extraordinary Items After Taxes (line 75 less line 76)
78	NetIncomeLoss Net Income (Total of line 71 and 77)		19,419,618	22,543,771	19,419,618	22,543,771

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

STATEMENT OF RETAINED EARNINGS
Do not report Lines 49-53 on the quarterly report. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436-439 inclusive). Show the contra primary account affected in column (b). State the purpose and amount for each reservation or appropriation of retained earnings. 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. Show dividends for each class and series of capital stock. Show separately the State and Federal income tax effect of items shown for Account 439, Adjustments to Retained Earnings. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated. If any notes appearing in the report to stockholders are applicable to this statement, attach them at page 122.
Line No.	Item (a)	Contra Primary Account Affected (b)	Current Quarter/Year Year to Date Balance (c)	Previous Quarter/Year Year to Date Balance (d)
	UnappropriatedRetainedEarningsAbstract UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1	UnappropriatedRetainedEarnings Balance-Beginning of Period		851,453,921	712,679,353
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		19,436,686	22,560,440
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)
23	DividendsDeclaredPreferredStockAbstract Dividends Declared-Preferred Stock (Account 437)
29	DividendsDeclaredPreferredStock TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30	DividendsDeclaredCommonStockAbstract Dividends Declared-Common Stock (Account 438)
30.1	DividendsDeclaredCommonStock Dividends Declared
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)
37	TransfersFromUnappropriatedUndistributedSubsidiaryEarnings Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38	UnappropriatedRetainedEarnings Balance - End of Period (Total 1,9,15,16,22,29,36,37)		870,890,607	735,239,793
39	AppropriatedRetainedEarningsAbstract APPROPRIATED RETAINED EARNINGS (Account 215)
45	AppropriatedRetainedEarnings TOTAL Appropriated Retained Earnings (Account 215)
	AppropriatedRetainedEarningsAmortizationReserveFederalAbstract APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46	AppropriatedRetainedEarningsAmortizationReserveFederal TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		870,890,607	735,239,793
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)
51	DividendsReceived (Less) Dividends Received (Debit)
52	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

STATEMENT OF CASH FLOWS
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. Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost.
Line No.	Description (See Instructions No.1 for explanation of codes) (a)	Current Year to Date Quarter/Year (b)	Previous Year to Date Quarter/Year (c)
1	NetCashFlowFromOperatingActivitiesAbstract Net Cash Flow from Operating Activities
2	NetIncomeLoss Net Income (Line 78(c) on page 117)	19,419,618	22,543,771
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	63,515,443	58,389,443
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Debt Issuance Costs	721,543	685,752
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	1,988,373	5,125,784
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	25,832,104	13,504,164
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	1,305,416	17,184,534
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	6,724,914	19,365,005
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	11,958,635	12,753,172
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	592,609	8,571,452
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	1,671,157	7,094,000
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies	17,067	16,668
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Use of Renewable Energy Credits for Compliance	11,907,595	12,217,068
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Pension and Postretirement Expense	2,911,753	3,835,398
18.3	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Pension and Postretirement Funding	1,924,004	1,324,308
18.4	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Share-Based Compensation Expense	1,165,843	1,100,865
18.5	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Change in Income Taxes Receivable/Payable	276,392	829,050
18.6	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Collateral Call Deposit		7,190,000
18.7	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Change in Cash Surrender Value of Company-Owned Life Insurance	2,784,113	1,863,712
18.8	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other	2,780,592	1,398,437
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	120,275,611	78,575,253
24	CashFlowsFromInvestmentActivitiesAbstract Cash Flows from Investment Activities:
25	ConstructionAndAcquisitionOfPlantIncludingLandAbstract Construction and Acquisition of Plant (including land):
26	GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities Gross Additions to Utility Plant (less nuclear fuel)	109,423,664	111,495,590
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	1,671,157	7,094,000
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	107,752,507	104,401,590
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)
39	InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Investments in and Advances to Assoc. and Subsidiary Companies
40	ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies Contributions and Advances from Assoc. and Subsidiary Companies
41	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract Disposition of Investments in (and Advances to)
42	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
44	PurchaseOfInvestmentSecurities Purchase of Investment Securities (a)
45	ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a)
46	LoansMadeOrPurchased Loans Made or Purchased
47	CollectionsOnLoans Collections on Loans
49	NetIncreaseDecreaseInReceivablesInvestingActivities Net (Increase) Decrease in Receivables
50	NetIncreaseDecreaseInInventoryInvestingActivities Net (Increase) Decrease in Inventory
51	NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities Net (Increase) Decrease in Allowances Held for Speculation
52	NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities Net Increase (Decrease) in Payables and Accrued Expenses
53	OtherAdjustmentsToCashFlowsFromInvestmentActivities Other (provide details in footnote):
53.1	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Proceeds from Sale of Interest in Springerville Common Facilities
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Purchase of Renewable Energy Credits	12,701,637	11,407,725
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Contributions in Aid of Construction	3,857,491	1,449,153
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	116,596,653	114,360,162
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	323,804,000
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
64.1	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription (a) Other (provide details in footnote):	3,414,845	374,040
64.2	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Deferred Financing Costs	2,419,313
64.3	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Contribution from Parent
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceeds from Borrowing under Revolving Credit Facility	5,000,000	20,000,000
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceeds from Borrowing Under Term Loan
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	329,799,532	20,374,040
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	177,000,000
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Repayments of Borrowing Under Revolving Credit Facility	20,000,000	20,000,000
76.2	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Repayments of Borrowing Under Term Loan
76.3	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Payment of Capital Lease Obligations
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	(b) 132,799,532	374,040
85	NetIncreaseDecreaseInCashAndCashEquivalentsAbstract Net Increase (Decrease) in Cash and Cash Equivalents
86	NetIncreaseDecreaseInCashAndCashEquivalents Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83)	136,478,490	35,410,869
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	9,365,126	60,397,647
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	145,843,616	24,986,778

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription

No amounts are individually material.

(b) Concept: CashFlowsProvidedFromUsedInFinancingActivities

See information about noncash investing and/or financing activities in the Notes to the Financial Statements (pages 122-123)

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

NOTES TO FINANCIAL STATEMENTS

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.
Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock.
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.
Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
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.
For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred.
Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.

Page 120, Instruction 2:

Tucson Electric Power Company (TEP) defines Cash and Cash Equivalents as cash (unrestricted demand deposits) and all highly liquid investments purchased with an original maturity date of three months or less.

The Cash and Cash Equivalents at End of Period on page 121 agrees to the Comparative Balance Sheet on page 110:


Cash (Acct 131)	$	145,843,616
Temporary Cash Investments (Acct 136)		—
Total Cash and Cash Equivalents at End of Period	$	145,843,616

Page 120, Instruction 3:
Interest Paid (Net of Amounts Capitalized)	$	19,079,063
Income Taxes Paid (Refund)	$	683,000

Page 122, Instruction 2:

See Note 7, Commitments and Contingencies in the Notes to Financial Statements below.

Page 122, Instruction 1:

BASIS OF PRESENTATION

These financial statements include all the accounts of San Carlos Resources, Inc. (San Carlos) and Tucsonel, Inc. (Tucsonel), utility related wholly-owned subsidiaries of TEP, consolidated with the accounts of TEP. San Carlos holds title to Springerville Unit 2, and Tucsonel holds an equity interest in the Springerville Coal Handling Facility.

The accompanying footnotes are prepared on the same basis as TEP's footnotes as submitted to the Securities and Exchange Commission (SEC) on its quarterly Form 10-Q.

These financial statements are prepared in accordance with the accounting requirements of the Federal Energy Regulatory Commission (FERC) as stated in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than Generally Accepted Accounting Principles in the United States of America (GAAP). The FERC basis of accounting presentation differs from financial statements prepared under GAAP in significant respects and include specific information required by the FERC. The following are the significant differences between the FERC accounting and reporting standards and GAAP.

EQUITY INVESTMENT

As required by the FERC, TEP accounts for its investments in majority-owned subsidiaries, except for San Carlos and Tucsonel, using the equity method rather than consolidating the assets, liabilities, revenues, and expenses of the subsidiaries as required by GAAP. In general, the accounting for investments in majority-owned subsidiaries using the equity method rather than the consolidated method in accordance with GAAP has no effect on net income or retained earnings.

INCOME TAXES

There are certain presentational differences between the FERC basis of accounting and GAAP for amounts related to unrecognized tax benefits associated with temporary differences. 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.

NET COST OF REMOVAL

The accumulated net removal costs for TEP's regulated plant assets that do not meet the definition of an Asset Retirement Obligation (ARO) under Accounting Standards Codification 410-20 are classified as a regulatory

liability under GAAP and as a component of accumulated depreciation under the FERC accounting and reporting standards.

OTHER DIFFERENCES

The FERC requires current maturities of long-term debt to be classified as long-term debt, while GAAP requires such maturities to be classified as a current liability. Regulatory assets and regulatory liabilities are classified as current and non-current for GAAP, while the FERC classifies all regulatory assets and regulatory liabilities as non-current.

The FERC requires debt issuance costs to be presented as assets on the balance sheet, while GAAP requires debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the associated debt liability.

The FERC requires both the service and non-service components of pension and other postretirement benefit net periodic benefit costs to be reflected in operating expense Account 926, Employee Pensions and Benefits, while GAAP requires service and non-service components of the net periodic benefit costs to be presented separately in operating and non-operating expense, respectively. In addition, the FERC allows for utilities to follow GAAP guidance to not capitalize the non-service cost component of the net periodic benefit costs.

LEASES

TEP adopted accounting guidance issued by the Financial Accounting Standards Board (FASB) that requires lessees to recognize a lease liability, initially measured at the present value of future lease payments, and a right-of-use asset for all leases with a lease term greater than 12 months. The new lease standard also requires additional quantitative and qualitative disclosures for both lessees and lessors. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. The new lease guidance will be applied on a prospective basis to all new or modified land easements after January 1, 2019. Adoption of the standard had no impact on net income or cash flows. Adoption of the accounting guidance had no impact on TEP's existing ratemaking treatment or FERC jurisdiction cost-of-service rates. Amounts included in the capital lease balance sheet accounts that relate to operating leases are as follows:


		March 31,		December 31,
($ in millions)	FERC Account	2022		2021
Property Under Capital Lease	101.1	$	7	$	7
Obligations Under Capital Leases - Noncurrent	227	6		6
Obligations Under Capital Leases - Current	243	1		1

SUBSEQUENT EVENTS

Management has evaluated the impact of events occurring after March 31, 2022, up to May 4, 2022, the date that TEP's GAAP financial statements were issued, and has updated such evaluation for disclosure purposes as of May 10, 2022. The financial statements include all necessary adjustments and disclosures resulting from these evaluations.

DEFINITIONS

The abbreviations and acronyms used in this Form 10-Q are defined below:

INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS


2019 FERC Rate Case						In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings


2020 Rate Order						A rate order issued by the ACC resulting in a new rate structure for TEP, effective on January 1, 2021

2021 Credit Agreement						The 2021 Credit Agreement provides for a $250 million revolving credit and letter of credit facility with a letter of credit sublimit of $50 million; the 2021 Credit Agreement matures in October 2026
ACC						Arizona Corporation Commission


ADEQ						Arizona Department of Environmental Quality








DG						Distributed Generation
DSM						Demand Side Management
EDIT						Excess Deferred Income Taxes
EE Standards						Energy Efficiency Standards


FERC						Federal Energy Regulatory Commission
GAAP						Generally Accepted Accounting Principles in the United States of America

LFCR						Lost Fixed Cost Recovery

LOC						Letter(s) of Credit
OATT						Open Access Transmission Tariff
Phase 2						Second phase of TEP's 2020 Rate Case proceedings originally filed in April 2019

PPFAC						Purchased Power and Fuel Adjustment Clause
PRP						Potentially Responsible Parties
PTC						Production Tax Credit
RES						Renewable Energy Standard
Retail Rates						Rates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment

SEC						Securities and Exchange Commission
TCA						Transmission Cost Adjustor


TEAM						Tax Expense Adjustor Mechanism

ENTITIES AND GENERATING STATIONS



Fortis						Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada, whose principal executive offices are located at Fortis Place, Suite 1100, 5 Springdale Street, St. John's, NL A1E 0E4
Four Corners						Four Corners Generating Station


Navajo						Navajo Generating Station
Oso Grande						A 250 MW nominal capacity wind-powered electric generation facility, located in southeastern New Mexico
San Juan						San Juan Generating Station

Springerville						Springerville Generating Station


TEP						Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation


UNS Electric						UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation
UNS Energy						UNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701
UNS Energy Affiliates						Subsidiaries of UNS Energy Corporation including UniSource Energy Services, Inc., UNS Electric, Inc., UNS Gas, Inc., and Southwest Energy Solutions, Inc.
UNS Gas						UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation

UNITS OF MEASURE


BBtu						Billion British thermal unit(s), a measure of the quantity of heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit at the temperature at which water has its greatest density, in billions
GWh						Gigawatt-hour(s), a measure of electricity that represents one billion watts of power expended over one hour
kWh						Kilowatt-hour(s), a measure of electricity that represents one thousand watts of power expended over one hour

TEP's Notes to Financial Statements on a GAAP basis as follows:

NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 441,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis.

BASIS OF PRESENTATION

TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the SEC's interim reporting requirements.

The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. TEP records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Condensed Consolidated Statements of Income. These Condensed Consolidated Financial Statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2021 Annual Report on Form 10-K.

The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation.

Variable Interest Entities

TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (VIE), and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE.

TEP has entered into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis.

As of March 31, 2022, the carrying amounts of assets and liabilities on the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as TEP would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.

Restricted Cash

Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement:


	March 31,
(in millions)	2022		2021
Cash and Cash Equivalents	$	146	$	26
Restricted Cash included in:
Investments and Other Property	19		18
Current Assets—Other	4		2
Total Cash, Cash Equivalents, and Restricted Cash	$	169	$	46

Restricted cash included in Investments and Other Property on the Condensed Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs.

Income Tax Expense

TEP realized PTC benefits of $2 million in Income Tax Expense on the Condensed Consolidated Statements of Income for the three months ended March 31, 2022, as a result of Oso Grande being placed in service in May 2021.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

New authoritative accounting guidance issued by the Financial Accounting Standards Board was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

NOTE 2. REGULATORY MATTERS

The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect the Company's business decisions and accounting practices. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce.

RATE CASE MATTERS

2020 Rate Order

In 2020, the ACC issued a rate order for new rates that took effect January 1, 2021.

Provisions of the 2020 Rate Order include, but are not limited to:

•a non-fuel retail revenue increase of $58 million over test year retail revenues;

•a 7.04% return on original cost rate base of $2.7 billion, which includes a cost of equity of 9.15% and an average cost of debt of 4.65%; and

•a capital structure for rate making purposes of approximately 53% common equity and 47% long-term debt.

In addition, the 2020 Rate Order established a second phase of TEP’s rate case to address the impact on certain communities due to the closures of fossil-based generation facilities (Phase 2). In 2021, the ACC staff opened a generic docket related to this matter and will consider additional evidence or recommendations in Phase 2. On January 19, 2022, the ACC issued an order delaying Phase 2 until after the completion of the generic docket. TEP cannot predict the timing or outcome of these proceedings.

2019 FERC Rate Order

In 2019, TEP filed a proposal with the FERC requesting a forward-looking formula rate intended to allow for a more timely recovery of transmission-related costs. The FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. As part of the order, the FERC established hearing and settlement procedures. In December 2021, the settlement agreement was filed with the FERC. In March 2022, the FERC approved the settlement agreement.

Provisions of the settlement agreement include, but are not limited to:

•replacing TEP's stated transmission rates with a single forward-looking formula rate;

•a 9.79% return on equity; and

•elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor.

Increased rates charged under the 2019 FERC Rate Order were subject to refund and deferred as a regulatory liability. Amounts deferred as a regulatory liability in excess of the rates approved in the settlement agreement will be returned to customers. TEP had $17 million as of March 31, 2022, and $15 million as of December 31, 2021, of wholesale revenues reserved in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets.

OTHER FERC MATTERS

In January 2021, the FERC notified TEP that it was commencing an audit that intends to evaluate TEP's compliance with: (i) the accounting requirements of the Uniform System of Accounts; and (ii) the reporting requirements of the FERC Form 1 Annual Report and Supplemental Form 3-Q Quarterly Financial Reports. The audit covers the period of January 1, 2018 to the present. The audit is ongoing and TEP cannot predict the outcome or findings, if any, of the FERC audit at this time.

COST RECOVERY MECHANISMS

TEP has received regulatory decisions that allow for timely recovery of certain costs through recovery mechanisms. Cost recovery mechanisms that have a material impact on TEP's operations or financial results are described below.

Purchased Power and Fuel Adjustment Clause

TEP's PPFAC rate is typically adjusted annually on April 1st and goes into effect for the subsequent 12-month period unless the schedule is modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that allows for reconciliation of differences between actual costs and those recovered in the preceding period. On April 13, 2022, the ACC approved a rate adjustment for the PPFAC, which became effective on April 29, 2022. The rate adjustment sets the true-up component of the PPFAC rate to recover the existing uncollected true-up balance over 18 months. The ACC also set the forward-looking component of the PPFAC rate to zero, which may result in future under-collection of PPFAC costs.

The table below summarizes the PPFAC regulatory asset (liability) balance:


	Three Months Ended March 31,
(in millions)		2022		2021
Beginning of Period		$	91	$	23
Deferred Fuel and Purchased Power Costs (1)		65		67
PPFAC and Base Power Recoveries (2)		(54)		(50)
End of Period		$	102	$	40

(1)Includes costs eligible for recovery through the PPFAC and base power rates.

(2)In March 2021, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request, which went into effect on June 1, 2021.

Tax Expense Adjustor Mechanism

The TEAM allows for the timely recovery of future significant income tax changes and provides the Company the ability to pass through as a kWh surcharge: (i) the change in EDIT compared to the test year; and (ii) the income tax effects of tax

legislation that materially impacts TEP's 2018 test year revenue requirements. The TEAM went into effect January 1, 2021, as approved in the 2020 Rate Order.

Transmission Cost Adjustor

The TCA went into effect January 1, 2021, as approved in the 2020 Rate Order. The TCA allows for timely recovery of actual costs required to provide transmission services to retail customers. The TCA is limited to the recovery, or refund, of costs associated with future changes in TEP's OATT rate. The Company files a notice with the ACC in December each year presenting a revised tariff that reflects the changes in the formula OATT rate which goes into effect in the first billing cycle in January of each year.

In February 2022, the ACC approved TEP's motion to modify the TCA plan of administration to reflect the terms of the 2019 FERC Rate Order settlement agreement.

Renewable Energy Standard

The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy sales by 2025, with DG accounting for 30%. The renewable energy requirement in 2022 is 12% of retail electric sales. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC. TEP recovers approved costs of carrying out this plan from retail customers through a RES surcharge.

In 2021, the ACC approved TEP's 2021 RES implementation plan for the years 2021 and 2022 with a budget of $66 million. The approved amounts fund: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. Additionally, the ACC directed TEP to collaborate with the ACC to develop and file a proposal by July 1, 2022, to phase out the RES tariff. TEP expects to file a general rate application with the ACC in June 2022, which will include a proposal to transition away from the current RES and DSM surcharges and to recover those costs in a different manner.

Energy Efficiency Standards

TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year.

In 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of $23 million, which is collected through the DSM surcharge, and approved a waiver of the 2018 EE Standards. In addition, the ACC ordered that TEP's 2018 energy efficiency implementation plan be considered as its 2019 and 2020 energy efficiency implementation plans. In 2021, TEP filed its 2022 energy efficiency implementation plan with a budget of $23 million. In March 2022, TEP filed an application with the ACC requesting the 2022 energy efficiency implementation plan be considered as its 2023 energy efficiency implementation plan. TEP cannot predict the outcome of the proceeding.

Lost Fixed Cost Recovery Mechanism

The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. TEP records a regulatory asset and recognizes LFCR revenues when amounts are verifiable regardless of when the lost retail kWh sales occurred. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues.

REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities recorded on the Condensed Consolidated Balance Sheets are summarized in the table below:


($ in millions)	Remaining Recovery Period (years)	March 31, 2022		December 31, 2021
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	127	$	128
Under Recovered Purchased Energy Costs	2	102		91
Early Generation Retirement Costs	Various	38		38
Lost Fixed Cost Recovery	1	35		37
Property Tax Deferrals (1)	1	28		27
Final Mine Reclamation and Retiree Healthcare Costs (2)	7	17		17
Income Taxes Recoverable through Future Rates (3)	Various	16		17
Derivatives (Note 9)	8	8		8
Unamortized Loss on Reacquired Debt	Various	6		5
Springerville Unit 1 Leasehold Improvements (4)	2	4		4

Other Regulatory Assets	Various	12		12
Total Regulatory Assets		393		384
Less Current Portion	1	126		116
Total Non-Current Regulatory Assets		$	267	$	268


Regulatory Liabilities
Income Taxes Payable through Future Rates (3)	Various	$	265	$	268
Derivatives (Note 9)	8	108		19
Renewable Energy Standard	Various	66		66
Net Cost of Removal (5)	Various	58		73
Transmission Revenue Subject to Refund—FERC	1	17		15
Demand Side Management	1	13		12
Transmission Cost Adjustor	1	7		9

Other Regulatory Liabilities	Various	2		1



Total Regulatory Liabilities		536		463
Less Current Portion	1	152		111
Total Non-Current Regulatory Liabilities		$	384	$	352

(1)Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months.

(2)Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2028.

(3)Amortized over five years, 10 years, or the lives of the assets.

(4)Represents investments TEP made, which were previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year period.

(5)Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation, and general and intangible plant which are not yet expended. As a result of the 2020 Rate Order, TEP transferred costs from Net Cost of Removal to Accumulated Depreciation and Amortization.

Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs, Income Taxes Recoverable through Future Rates, and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. TEP pays a return on the majority of its regulatory liability balances.

NOTE 3. REVENUE

DISAGGREGATION OF REVENUES

TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service:


	Three Months Ended March 31,
(in millions)		2022		2021
Retail		$	218	$	215
Wholesale (1)		56		56
Other Services		24		36
Revenues from Contracts with Customers		298		307
Alternative Revenues		11		8
Other		28		21
Total Operating Revenues		$	337	$	336

(1)Pursuant to a FERC order, all rates charged under TEP's revised OATT were subject to refund until the 2019 FERC Rate Order proceedings concluded. Wholesale Revenues exclude an estimate of revenues probable of refund. See Note 2 for more information regarding the 2019 FERC Rate Order.

NOTE 4. ACCOUNTS RECEIVABLE

The following table presents the components of Accounts Receivable on the Condensed Consolidated Balance Sheets:


(in millions)	March 31, 2022		December 31, 2021
Retail	$	67	$	78
Retail, Unbilled	34		44
Retail, Allowance for Credit Losses	(9)		(10)
Wholesale (1)	33		47
Due from Affiliates (Note 5)	24		17
Other	18		17
Accounts Receivable	$	167	$	193

(1)Includes $13 million as of March 31, 2022, and $16 million as of December 31, 2021, of receivables related to revenue from derivative instruments.

ALLOWANCE FOR CREDIT LOSSES

TEP separately evaluates retail, wholesale, and other accounts receivable for credit losses and has not recorded an allowance for credit losses for non-retail accounts receivable. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Condensed Consolidated Balance Sheets:


	Three Months Ended March 31,
(in millions)	2022		2021
Beginning of Period	$	(10)	$	(13)
Credit Loss Expense	—		(1)
Write-offs	1		1

End of Period (1)	$	(9)	$	(13)

(1)In 2021, the ACC adopted rules that suspended service disconnections and late fees for electric residential customers who otherwise are eligible for service disconnection during the period from June 1 through October 15.

TEP continuously monitors collection activity and adjusts its allowance for credit losses as needed.

Customer Payment Assistance

In 2022, TEP received funds for customer payment assistance from the Arizona Department of Economic Security (DES) to provide emergency payment assistance to renters. Customer payment assistance is dependent on qualifying customers applying. TEP received $7 million in DES payment assistance funds in the first three months of 2022.

NOTE 5. RELATED PARTY TRANSACTIONS

TEP engages in various transactions with Fortis, UNS Energy, and UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor-related services.

The following table presents the components of related party balances included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets:


(in millions)	March 31, 2022		December 31, 2021
Receivables from Related Parties
UNS Energy	$	14	$	7
UNS Electric	8		8
UNS Gas	2		2








Total Due from Related Parties	$	24	$	17

Payables to Related Parties
UNS Energy	$	3	$	1
UNS Electric	1		—



UNS Gas	—		1

Total Due to Related Parties	$	4	$	2

The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income:


	Three Months Ended March 31,
(in millions)		2022		2021
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric (1)		$	2	$	3
Wholesale Revenues, UNS Electric (1)		1		1
Control Area Services, UNS Electric (2)		1		2
Common Costs, UNS Energy Affiliates (3)		5		5


Goods and Services Provided by Affiliates to TEP


Corporate Services, UNS Energy (4)		3		2
Corporate Services, UNS Energy Affiliates (5)		—		1

(1)TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable OATT.

(2)TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement.

(3)Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.

(4)Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry-accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 85% of UNS Energy's allocated costs. The Corporate Services, UNS Energy line includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $2 million for the three months ended March 31, 2022 and 2021.

(5)Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.

NOTE 6. DEBT AND CREDIT AGREEMENTS

There have been no significant changes to TEP's debt or credit agreements from those reported in its 2021 Annual Report on Form 10-K, except as noted below.

DEBT

Issuance and Redemption

In February 2022, TEP issued and sold $325 million aggregate principal amount of 3.25% senior unsecured notes due May 2032. TEP may redeem the notes prior to February 15, 2032, with a make-whole premium plus accrued interest. On or after February 15, 2032, TEP may redeem the notes at par plus accrued interest. TEP used the net proceeds to redeem debt and for general corporate purposes.

In March 2022, TEP redeemed at par $177 million aggregate principal amount of 4.50% tax-exempt bonds, prior to maturity.

CREDIT AGREEMENT

2021 Credit Agreement

As of March 31, 2022, there was $240 million available under the 2021 Credit Agreement, which reflects no outstanding borrowings and a $10 million LOC issued with fees accruing at a rate of 1.00% per annum.

NOTE 7. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

There have been no significant changes to TEP's long-term commitments from those reported in its 2021 Annual Report on Form 10-K.

CONTINGENCIES

Legal Matters

TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results.

Mine Reclamation at Generation Facilities Not Operated by TEP

TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, timing of when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP prospectively adjusts the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP’s PPFAC allows the Company to pass through to retail customers final mine reclamation costs, as a component of fuel costs. Therefore, TEP defers these expenses until recovered from customers by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded.

TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. TEP’s estimated share of final mine reclamation costs at both mines is $44 million upon expiration of the related coal supply agreements, which expire in 2022 and 2031, respectively. An aggregate liability balance related to San Juan and Four Corners final mine reclamation of $40 million as of March 31, 2022 and December 31, 2021, was recorded in Other on the Condensed Consolidated Balance Sheets. TEP established a trust to fund its share of estimated final mine reclamation costs at San Juan, which will remain in effect through the completion of final mine reclamation activities currently projected to be 2039. See Note 1 and Note 2 for additional information related to final mine reclamation costs.

Performance Guarantees

TEP has joint generation participation agreements with participants at San Juan, Four Corners, and Luna Generating Station, which expire in 2022, 2041, and 2046, respectively. The Navajo participation agreement expired in 2019, but certain performance obligations continue through the decommissioning of the generation facility. The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. Relative to Navajo performance obligations, in the case of a default, the non-defaulting participants would seek financial recovery directly from the defaulting party. With the exception of Four Corners, there is no maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments by the non-defaulting parties is $250 million at Four Corners. As of March 31, 2022, there have been no such payment defaults under any of the participation agreements.

Environmental Matters

TEP is subject to federal, state, and local environmental laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance from its customers. TEP believes it is in compliance with applicable environmental laws and regulations in all material respects.

Broadway-Pantano Site

The Water Quality Assurance Revolving Fund (WQARF) imposes liability on parties responsible for, in whole or in part, the presence of hazardous substances at a site. Those who released, generated, or disposed of hazardous substances at a

contaminated site, or transported to or owned such contaminated site, are among the Potentially Responsible Parties (PRP). PRPs may be strictly liable for clean-up. The ADEQ is administering a remediation plan to delineate and then apportion costs among anticipated adverse parties in the Broadway-Pantano WQARF site, a hazardous waste site in Tucson, Arizona, which includes the Broadway North and South Landfills. Collectively, these landfills were in operation from 1953 and 1973. TEP's Eastloop Substation and a portion of a related transmission line are located on two parcels adjacent to these landfills. In November 2019, the ADEQ notified TEP that it considers TEP to be a PRP with respect to the Broadway-Pantano WQARF site. TEP does not expect this matter to have a material impact on its financial statements; however, the overall investigation and remediation plan have not been finalized.

NOTE 8. EMPLOYEE BENEFIT PLANS

Net periodic benefit cost includes the following components:


	Pension Benefits				Other Postretirement Benefits
	Three Months Ended March 31,
(in millions)	2022		2021		2022		2021
Service Cost	$	5	$	5	$	1	$	2
Non-Service Cost (1)
Interest Cost	4		3		—		—
Expected Return on Plan Assets	(9)		(8)		—		—
Amortization of Net Loss	2		2		—		—
Net Periodic Benefit Cost	$	2	$	2	$	1	$	2

(1)The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income.

NOTE 9. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. TEP has no financial instruments categorized as Level 3.

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement:


	Level 1		Level 2		Total
(in millions)	March 31, 2022
Assets
Cash Equivalents (1)	$	50	$	—	$	50
Restricted Cash (1)	23		—		23
Energy Derivative Contracts, Regulatory Recovery (2)	—		110		110
Energy Derivative Contracts, No Regulatory Recovery (2)	—		10		10
Total Assets	73		120		193
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(11)		(11)

Total Liabilities	—		(11)		(11)
Total Assets (Liabilities), Net	$	73	$	109	$	182


(in millions)	December 31, 2021
Assets

Restricted Cash (1)	$	23	$	—	$	23
Energy Derivative Contracts, Regulatory Recovery (2)	—		30		30
Energy Derivative Contracts, No Regulatory Recovery (2)	—		4		4
Total Assets	23		34		57
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(20)		(20)


Total Liabilities	—		(20)		(20)
Total Assets (Liabilities), Net	$	23	$	14	$	37

(1)Cash Equivalents and Restricted Cash represent amounts held in money market funds, which approximate fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets.

(2)Energy Derivative Contracts include gas swap agreements and forward power purchase and sale contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets.

All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis on the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral:


	Gross Amount Recognized in the Balance Sheets		Gross Amount Not Offset in the Balance Sheets				Net Amount
			Counterparty Netting of Energy Contracts		Cash Collateral Received/Posted
(in millions)	March 31, 2022
Derivative Assets
Energy Derivative Contracts	$	120	$	9	$	—	$	111
Derivative Liabilities
Energy Derivative Contracts	(11)		(9)		—		(2)


(in millions)	December 31, 2021
Derivative Assets
Energy Derivative Contracts	$	34	$	14	$	—	$	20
Derivative Liabilities
Energy Derivative Contracts	(20)		(14)		—		(6)

DERIVATIVE INSTRUMENTS

TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of TEP's retail customers.

TEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.

For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated.

Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and line losses.

TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.

The inputs and the Company's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly.

Energy Derivative Contracts, Regulatory Recovery

TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or a regulatory liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet:


	Three Months Ended March 31,
(in millions)		2022		2021
Unrealized Net Gain (Loss) (1)		$	89	$	(4)

(1)Increase in unrealized net gain on regulatory recoverable derivative contracts is primarily due to increases in forward market prices of natural gas.

Energy Derivative Contracts, No Regulatory Recovery

TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as defined in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism. The table below presents amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income:


	Three Months Ended March 31,
(in millions)		2022		2021
Operating Revenues		$	8	$	1

Derivative Volumes

As of March 31, 2022, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:


	March 31, 2022	December 31, 2021
Power Contracts GWh	5,358	2,617
Gas Contracts BBtu	111,261	112,316

CREDIT RISK

The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of power and natural gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurements at fair value.

TEP has contractual agreements for energy procurement and hedging activities that contain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits due to the volume of trading activity; (ii) changes in natural gas or power prices; (iii) credit rating downgrades; or (iv) unfavorable changes in parties' assessments of each other's credit strength. In the event that such credit events were to occur, TEP, or its counterparties, would have to provide certain credit enhancements in the form of cash, LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts.

TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to the individual contracts.

The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $15 million as of March 31, 2022, compared with $26 million as of December 31, 2021. As of March 31, 2022, TEP had no cash posted as collateral to provide credit enhancement. If the credit risk contingent features were triggered on March 31, 2022, TEP would have been required to post $15 million of collateral. As of March 31, 2022, TEP had $20 million in outstanding net payable balances for settled positions.

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. Due to the short-term nature of borrowings under revolving credit facilities approximating fair value, they have been excluded from the table below.

The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the net carrying value and estimated fair value of TEP's long-term debt:


	Fair Value Hierarchy	Net Carrying Value				Fair Value
(in millions)		March 31, 2022		December 31, 2021		March 31, 2022		December 31, 2021
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	2,280	$	2,135	$	2,283	$	2,357

NOTE 10. SUPPLEMENTAL CASH FLOW INFORMATION

NON-CASH TRANSACTIONS

Other significant non-cash investing and financing activities that resulted in recognition of assets and liabilities but did not result in cash receipts or payments were as follows:


	Three Months Ended March 31,
(in millions)	2022		2021
Accrued Capital Expenditures	$	29	$	40

Renewable Energy Credits	6		5

Net Cost of Removal Decrease (1)	(1)		(34)
Asset Retirement Cost Decrease (2)	(14)		—

(1)Represents an accrual for future cost of retirement net of salvage values that does not impact earnings.

(2)Primarily represents a reduction in the net value of asset retirement cost of San Juan for deferred depreciation, which does not impact earnings.

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. 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. Report data on a year-to-date basis.
Line No.	Item (a)	Unrealized Gains and Losses on Available-For-Sale Securities (b)	Minimum Pension Liability Adjustment (net amount) (c)	Foreign Currency Hedges (d)	Other Adjustments (e)	Other Cash Flow Hedges Interest Rate Swaps (f)	Other Cash Flow Hedges [Specify] (g)	Totals for each category of items recorded in Account 219 (h)	Net Income (Carried Forward from Page 116, Line 78) (i)	Total Comprehensive Income (j)
1	Balance of Account 219 at Beginning of Preceding Year		10,941,900					10,941,900
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income		219,088					219,088
3	Preceding Quarter/Year to Date Changes in Fair Value
4	Total (lines 2 and 3)		219,088					219,088	22,543,771	22,762,859
5	Balance of Account 219 at End of Preceding Quarter/Year		10,722,812					10,722,812
6	Balance of Account 219 at Beginning of Current Year		9,915,092					9,915,092
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income		196,938					196,938
8	Current Quarter/Year to Date Changes in Fair Value
9	Total (lines 7 and 8)		196,938					196,938	19,419,618	19,616,556
10	Balance of Account 219 at End of Current Quarter/Year		9,718,154					9,718,154

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

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	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlantInServiceAbstract In Service
3	UtilityPlantInServiceClassified Plant in Service (Classified)	7,637,181,370	7,637,181,370
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	6,796,516	6,796,516
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	440,053,971	440,053,971
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	8,084,031,857	8,084,031,857
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	11,240,261	11,240,261
11	ConstructionWorkInProgress Construction Work in Progress	271,141,024	271,141,024
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	32,511,234	32,511,234
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	8,398,924,376	8,398,924,376
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	3,087,132,082	3,087,132,082
15	UtilityPlantNet Net Utility Plant (13 less 14)	5,311,792,294	5,311,792,294
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	2,917,560,314	2,917,560,314
19	AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService Amortization and Depletion of Producing Natural Gas Land and Land Rights
20	AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService Amortization of Underground Storage Land and Land Rights
21	AmortizationOfOtherUtilityPlantUtilityPlantInService Amortization of Other Utility Plant	165,491,880	165,491,880
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	3,083,052,194	3,083,052,194
23	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract Leased to Others
24	DepreciationUtilityPlantLeasedToOthers Depreciation
25	AmortizationAndDepletionUtilityPlantLeasedToOthers Amortization and Depletion
26	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers Total Leased to Others (24 & 25)
27	DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract Held for Future Use
28	DepreciationUtilityPlantHeldForFutureUse Depreciation
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	4,079,888	4,079,888
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	3,087,132,082	3,087,132,082

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

Electric Plant In Service and Accum Provision For Depr by Function
Report below the original cost of plant in service by function. In addition to Account 101, include Account 102, and Account 106. Report in column (b) the original cost of plant in service and in column(c) the accumulated provision for depreciation and amortization by function.
Line No.	Item (a)	Plant in Service Balance at End of Quarter (b)	Accumulated Depreciation And Amortization Balance at End of Quarter (c)
1	Intangible Plant	227,602,171	136,114,225
2	Steam Production Plant	2,394,557,112	1,361,207,844
3	Nuclear Production Plant
4	Hydraulic Production - Conventional
5	Hydraulic Production - Pumped Storage
6	Other Production	1,553,408,618	440,442,720
7	Transmission	1,218,414,236	445,005,424
8	Distribution	2,046,656,829	558,492,086
9	Regional Transmission and Market Operation
10	General	636,596,375	183,513,864
11	TOTAL (Total of lines 1 through 10)	8,077,235,341	(a) 3,124,776,163

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: AccumulatedProvisionForDepreciationOfElectricUtilityPlant


Per Comparative Balance Sheet (Page: 110, Line: 5, Column: c)			3,087,132,082
FERC 0115 Accumulated Provision for Amortization of Electric Plant Acquisition Premium - Pinal West, acquired in 2012			(319,570)
FERC 0115 Accumulated Provision for Amortization of Electric Plant Acquisition Premium - Springerville Coal Handling Facilities, acquired in 2015			(2,987,511)
FERC 0115 Accumulated Provision for Amortization of Electric Plant Acquisition Premium - 86% of Springerville Common Facilities, acquired in 2017 and 2020			(772,808)
Regulatory accounting treatment of asset retirement obligations			41,723,970
Per Plant in Service and Accumulated Provision for Depreciation by Function (Schedule Page: 208, Line: 11, Column: c)			3,124,776,163

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

Transmission Service and Generation Interconnection Study Costs
Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. List each study separately. In column (a) provide the name of the study. In column (b) report the cost incurred to perform the study at the end of period. In column (c) report the account charged with the cost of the study. In column (d) report the amounts received for reimbursement of the study costs at end of period. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.	DescriptionOfStudyPerformed Description (a)	StudyCostsIncurred Costs Incurred During Period (b)	StudyCostsAccountCharged Account Charged (c)	StudyCostsReimbursements Reimbursements Received During the Period (d)	StudyCostsAccountReimbursed Account Credited With Reimbursement (e)
1	Transmission Studies
2	Transmission Service Request #33 System Impact Study	39	253
3	Transmission Service Request #46 Facility Study	(a) 2,737	253
20	Total	2,776
21	Generation Studies
22	OASIS Queue Rank #72 Facility Study	570	253
23	OASIS Queue Rank #77 Facility Study	86	253
24	OASIS Queue Rank #78 Facility Study	86	253
25	OASIS Queue Rank #80 Facility Study	5,418	253
26	OASIS Queue Rank #83 Feasibility Study	201	253
27	OASIS Queue Rank #83 System Impact Study	57	253
28	OASIS Queue Rank #84 Feasibility Study			10,614	253
29	OASIS Queue Rank #84 System Impact Study			7,259	253
30	OASIS Queue Rank #84 Facility Study	8,221	253	100,000	253
31	OASIS Queue Rank #85 Feasibility Study			(d) 3,219	253
32	OASIS Queue Rank #86 System Impact Study	31,791	253
33	OASIS Queue Rank #87 System Impact Study	3,317	253
34	OASIS Queue Rank #88 System Impact Study			20,000	253
35	OASIS Queue Rank #88 Facility Study	18,149	253
36	OASIS Queue Rank #89 Feasibility Study			(e) 10,000	253
37	OASIS Queue Rank #90 Feasibility Study			4,548	253
38	OASIS Queue Rank #90 System Impact Study	47,265	253
39	OASIS Queue Rank #91 Feasibility Study	(b) 58	253	14,162	253
40	OASIS Queue Rank #92 Feasibility Study	(c) 58	253	14,269	253
41	OASIS Queue Rank #93 System Impact Study	887	253
42	OASIS Queue Rank #94 System Impact Study	779	253
43	OASIS Queue Rank #95 Feasibility Study	4,603	253
44	OASIS Queue Rank #96 System Impact Study	15,035	253
45	OASIS Queue Rank #97 Feasibility Study	15,361	253
46	OASIS Queue Rank #98 Feasibility Study	15,132	253
47	OASIS Queue Rank #99 Feasibility Study	15,073	253
48	OASIS Queue Rank #100 Feasibility Study	112	253
49	OASIS Queue Rank #101 Feasibility Study	112	253
50	OASIS Queue Rank #102 Feasibility Study	112	253
51	OASIS Queue Rank #103 System Impact Study	31,444	253	60,000	253
52	OASIS Queue Rank #104 System Impact Study	112	253
53	OASIS Queue Rank #105 System Impact Study	343	253	60,000	253
54	OASIS Queue Rank #106 Feasibility Study	12,001	253	30,000	253
55	OASIS Queue Rank #107 Feasibility Study	12,192	253	30,000	253
56	OASIS Queue Rank #111 Feasibility Study	452	253
39	Total	239,027		255,929
40	Grand Total	241,803		255,929

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: StudyCostsIncurred

Transmission Service Request #46 was withdrawn.

(b) Concept: StudyCostsIncurred

Queue #91 was withdrawn.

(c) Concept: StudyCostsIncurred

Queue #92 was withdrawn.

(d) Concept: StudyCostsReimbursements

Queue #85 was withdrawn.

(e) Concept: StudyCostsReimbursements

Queue #89 was withdrawn.

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

OTHER REGULATORY ASSETS (Account 182.3)
Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. 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. For Regulatory Assets being amortized, show period of amortization.
				CREDITS
Line No.	DescriptionAndPurposeOfOtherRegulatoryAssets Description and Purpose of Other Regulatory Assets (a)	OtherRegulatoryAssets Balance at Beginning of Current Quarter/Year (b)	IncreaseDecreaseInOtherRegulatoryAssets Debits (c)	OtherRegulatoryAssetsWrittenOffAccountCharged Written off During Quarter/Year Account Charged (d)	OtherRegulatoryAssetsWrittenOffRecovered Written off During the Period Amount (e)	OtherRegulatoryAssets Balance at end of Current Quarter/Year (f)
1	Income Taxes Recoverable through Future Revenues - ACC Decision #58497 - Issued January 1994	16,758,353	9,907	282, 410.1, 411.1	1,017,163	15,751,097
2	Pension Regulatory Assets - ACC Decision #73912 - Issued June 2013	126,284,048		926	1,558,405	124,725,643
3	Rate Case Cost - 2018 - ACC Decision #77856 - Issued December 2020 - Amortization Period 2021 through 2023	848,667		928	106,084	742,583
4	Final Mine Reclamation - Decision #75975 - Issued Febraury 2017 - Amortization Period 2008 through 2038	16,615,040	962,492	501	160,875	17,416,657
5	Power and Gas Derivatives - ACC Decision #77856 - Issued December 2020	8,342,767	4,061,963	175, 244	4,820,083	7,584,647
6	Other Postretirement Benefits - ACC Decision #73912 - Issued June 2013	2,264,236	40,461			2,304,697
7	Renewable Energy Credits - ACC Decison #75975 - Issued Febraury 2017 - Rate reset annually	69,351,312	13,914,886	555	11,907,595	71,358,603
8	Lost Fixed Cost Revenue Adjustor - ACC Decision #77856 - Issued December 2020 - Rate reset annually	36,729,719	7,250,431	142	8,863,820	35,116,330
9	Purchased Power and Fuel Adjustment Clause - ACC Decision #75975 - Issued Febraury 2017 - Rate reset annually	90,579,360	65,348,143	501, 502, 547, 555, 557, 565, 589	54,166,317	101,761,186
10	Springerville Unit 1 Leasehold Improvement Costs - ACC Decision #73912 - Issued June 2013 - Amortization Period 2013 through 2023	4,151,362		407.3	597,163	3,554,199
11	Navajo Retirement - ACC Decision #77856 - Issued December 2020	36,816,750	1,384,065	407.3	1,119,466	37,081,349
12	Sundt Units 1 & 2 Retirement - ACC Decision #77856 - Issued December 2020	1,359,157	15,357			1,374,514
13	San Juan Fuel and Environmental Costs - ACC Decision #77856 - Issued December 2020	2,209,981		407.3	276,248	1,933,733
14	Energy Imbalance Market Deferral - ACC Decision #77746 - Issued October 2020	1,214,104	980,297	408.1, 556, 925, 926	67,242	2,127,159
15	Customer Bill Credits - ACC Decision #77849 - Issued December 2020	557,056				557,056
16	Environmental Cost Adjustor - ACC Decision #77856 - Issued December 2020	32,464	3,604	456	1,569	34,499
17	Tax Expense Adjustor Mechanism - ACC Decision #77856 - Issued December 2020	2,547,862	172,027	142	491,488	2,228,401
18	Self-Insured Medical and Short-Term Disablility	1,412,733	190,839			1,603,572
19	Property Taxes	26,929,356	814,831	236	4,961	27,739,226
20	Electric Vehicle Infrastructure Investments	594,321	355,811	232	76,312	873,820
21	Operating Lease Cost Deferral		11,623	589	3,793	7,830
44	TOTAL	445,598,648	95,516,737		85,238,584	455,876,801

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

OTHER REGULATORY LIABILITIES (Account 254)
Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. 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. For Regulatory Liabilities being amortized, show period of amortization.
			DEBITS
Line No.	Description and Purpose of Other Regulatory Liabilities (a)	Balance at Beginning of Current Quarter/Year (b)	Account Credited (c)	Amount (d)	Credits (e)	Balance at End of Current Quarter/Year (f)
1	Renewable Energy Surcharge - ACC Decision #75975 - Issued February 2017 - Rate reset annually	65,993,069	456	15,495,989	15,484,508	65,981,588
2	Power and Gas Derivatives - ACC Decision #77856 - Issued December 2020	19,248,009	175, 244	5,280,809	93,565,931	107,533,131
3	Income Taxes Payable through Future Rates - ACC Decision #58497 - Issued January 1994	267,596,844	190, 410.1, 411.1	2,363,368		265,233,476
4	Demand Side Management Adjustor - ACC Decision #75975 - Issued February 2017 - Rate reset annually	12,404,471	456	4,240,379	4,895,851	13,059,943
5	Transmission Revenue Reserve - FERC Order on Docket #ER19-2019-000 - Issued July 2019	14,929,052			1,710,687	16,639,739
6	Transmission Cost Adjustor - ACC Decision #77856 - Issued December 2020	9,325,224	456	4,212,408	2,214,175	7,326,991
7	Sundt U1 and U2 Cost of Removal - ACC Decision #77856 - Issued December 2020	257,299			235,894	493,193
8	OATT Balancing Account - FERC Order on Docket #ER19-2019-002 - Issued March 2022		456	809,191	1,045,355	236,164
9	Operating Lease Cost Deferral	17,723	589	17,723
41	TOTAL	389,771,691		32,419,867	119,152,401	476,504,225

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

Electric Operating Revenues
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. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The average number of customers means the average of twelve figures at the close of each month. 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. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.	Title of Account (a)	Operating Revenues Year to Date Quarterly/Annual (b)	Operating Revenues Previous year (no Quarterly) (c)	MEGAWATT HOURS SOLD Year to Date Quarterly/Annual (d)	MEGAWATT HOURS SOLD Amount Previous year (no Quarterly) (e)	AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly) (f)	AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly) (g)
1	SalesOfElectricityHeadingAbstract Sales of Electricity
2	ResidentialSalesAbstract (440) Residential Sales	95,210,026		701,288
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	49,272,858		388,745
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	54,420,479		694,770
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	533,414		4,136
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	199,436,777		1,788,939
11	SalesForResaleAbstract (447) Sales for Resale	55,803,543		1,417,203
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	255,240,320		3,206,142
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	255,240,320		3,206,142
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	738,087
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(a) 1,290,316
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	18,895,381
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(b) 39,980,811
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	13,000,523
23	RegionalTransmissionServiceRevenues (457.1) Regional Control Service Revenues
24	MiscellaneousRevenue (457.2) Miscellaneous Revenues
25	OtherMiscellaneousOperatingRevenues Other Miscellaneous Operating Revenues
26	OtherOperatingRevenues TOTAL Other Operating Revenues	73,905,118
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	329,145,438
Line12, column (b) includes $ of unbilled revenues.
Line12, column (d) includes MWH relating to unbilled revenues

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: MiscellaneousServiceRevenues

FERC 451 Miscellaneous Service Revenues:


Primarily Service Transfer and Connect Fees			1,290,316

(b) Concept: OtherElectricRevenue

FERC 456 Other Electric Revenues:


Renewable Energy Surcharge			15,495,989
Lost Fixed Cost Recovery			7,250,431
Fees for Operating Springerville Unit 4 on Behalf of Salt River Project Agricultural Improvement and Power District			4,515,649
Demand Side Management Revenue			4,240,375
Fees for Operating Springerville Unit 3 on Behalf of Tri-State Generation and Transmission Association			3,102,712
Transmission Cost Adjustor Mechanism			2,156,748
Control Area Service Fees			1,701,629
Twin Eagle Asset Management Agreement Revenue			1,105,114
Tax Expense Adjustor Mechanism			370,449
Items < $250,000			41,715
			39,980,811

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
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

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

ELECTRIC PRODUCTION, OTHER POWER SUPPLY EXPENSES, TRANSMISSION AND DISTRIBUTION EXPENSES

Report Electric production, other power supply expenses, transmission, regional market, and distribution expenses through the reporting period.
Line No.	Account (a)	Year to Date Quarter (b)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION AND OTHER SUPPLY EXPENSES
2	SteamPowerGenerationOperationsExpense Steam Power Generation - Operation (500-509)	54,016,787
3	SteamPowerGenerationMaintenanceExpense Steam Power Generation – Maintenance (510-515)	18,044,173
4	PowerProductionExpensesSteamPower Total Power Production Expenses - Steam Power	72,060,960
5	NuclearPowerGenerationOperationsExpense Nuclear Power Generation – Operation (517-525)
6	NuclearPowerGenerationMaintenanceExpense Nuclear Power Generation – Maintenance (528-532)
7	PowerProductionExpensesNuclearPower Total Power Production Expenses - Nuclear Power
8	HydraulicPowerGenerationOperationsExpense Hydraulic Power Generation – Operation (535-540.1)
9	HydraulicPowerGenerationMaintenanceExpense Hydraulic Power Generation – Maintenance (541-545.1)
10	PowerProductionExpensesHydraulicPower Total Power Production Expenses - Hydraulic Power
11	RentsOtherPowerGeneration Other Power Generation – Operation (546-550.1)	44,109,625
12	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration Other Power Generation – Maintenance (551-554.1)	5,136,642
13	MaintenanceOfMiscellaneousOtherPowerGenerationPlant Total Power Production Expenses - Other Power	49,246,267
14	OtherPowerSuplyExpensesAbstract Other Power Supply Expenses
15	PurchasedPower (555) Purchased Power	28,299,654
15.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations
16	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	1,005,755
17	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	1,567,608
18	OtherPowerSupplyExpense Total Other Power Supply Expenses (line 15-17)	30,873,017
19	PowerProductionExpenses Total Power Production Expenses (Total of lines 4, 7, 10, 13 and 18)	152,180,244
20	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
21	TransmissionExpensesOperationAbstract Transmission Operation Expenses
22	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	382,385
24	LoadDispatchReliability (561.1) Load Dispatch-Reliability	245,557
25	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	314,412
26	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	268,851
27	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	9,481
28	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	6,691
29	TransmissionServiceStudies (561.6) Transmission Service Studies	4
30	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies	322
31	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services
32	StationExpensesTransmissionExpense (562) Station Expenses	52,049
32.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
33	OverheadLineExpense (563) Overhead Lines Expenses	54,738
34	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses
35	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	8,620,198
36	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	181,497
37	RentsTransmissionElectricExpense (567) Rents	7,674
38	OperationSuppliesAndExpensesTransmissionExpense (567.1) Operation Supplies and Expenses (Non-Major)
39	TransmissionOperationExpense TOTAL Transmission Operation Expenses (Lines 22 - 38)	10,143,859
40	TransmissionMaintenanceAbstract Transmission Maintenance Expenses
41	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	68,245
42	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	2,158
43	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	59,762
44	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software
45	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment
46	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
47	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	1,080,251
47.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
48	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	195,035
49	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines
50	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	888
51	MaintenanceOfTransmissionPlant (574) Maintenance of Transmission Plant
52	TransmissionMaintenanceExpenseElectric TOTAL Transmission Maintenance Expenses (Lines 41 – 51)	1,406,339
53	TransmissionExpenses Total Transmission Expenses (Lines 39 and 52)	11,550,198
54	RegionalMarketExpensesAbstract 3. REGIONAL MARKET EXPENSES
55	RegionalMarketExpensesOperationAbstract Regional Market Operation Expenses
56	OperationSupervision (575.1) Operation Supervision
57	DayAheadAndRealTimeMarketAdministration (575.2) Day-Ahead and Real-Time Market Facilitation
58	TransmissionRightsMarketAdministration (575.3) Transmission Rights Market Facilitation
59	CapacityMarketAdministration (575.4) Capacity Market Facilitation
60	AncillaryServicesMarketAdministration (575.5) Ancillary Services Market Facilitation
61	MarketMonitoringAndCompliance (575.6) Market Monitoring and Compliance
62	MarketFacilitationMonitoringAndComplianceServices (575.7) Market Facilitation, Monitoring and Compliance Services
63	RegionalMarketOperationExpense Regional Market Operation Expenses (Lines 55 - 62)
64	RegionalMarketExpensesMaintenanceAbstract Regional Market Maintenance Expenses
65	MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses (576.1) Maintenance of Structures and Improvements
66	MaintenanceOfComputerHardware (576.2) Maintenance of Computer Hardware
67	MaintenanceOfComputerSoftware (576.3) Maintenance of Computer Software
68	MaintenanceOfCommunicationEquipmentRegionalMarketExpenses (576.4) Maintenance of Communication Equipment
69	MaintenanceOfMiscellaneousMarketOperationPlant (576.5) Maintenance of Miscellaneous Market Operation Plant
70	RegionalMarketMaintenanceExpense Regional Market Maintenance Expenses (Lines 65-69)
71	RegionalMarketExpenses TOTAL Regional Control and Market Operation Expenses (Lines 63,70)
72	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
73	DistributionOperationExpensesElectric Distribution Operation Expenses (580-589)	5,392,546
74	DistributionMaintenanceExpenseElectric Distribution Maintenance Expenses (590-598)	2,346,666
75	DistributionExpenses Total Distribution Expenses (Lines 73 and 74)	7,739,212

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

Electric Customer Accts, Service, Sales, Admin and General Expenses
Report the amount of expenses for customer accounts, service, sales, and administrative and general expenses year to date.
Line No.	Account (a)	Year to Date Quarter (b)
-	CustomerAccountsExpensesOperationsAbstract Operation
1	CustomerAccountExpenses (901-905) Customer Accounts Expenses	5,773,343
2	CustomerServiceAndInformationExpenses (907-910) Customer Service and Information Expenses	2,580,139
3	SalesExpenses (911-917) Sales Expenses
4	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
5	AdministrativeAndGeneralExpensesOperationAbstract Operation
6	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	16,515,069
7	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	4,779,686
8	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	5,199,670
9	OutsideServicesEmployed (923) Outside Services Employed	5,640,598
10	PropertyInsurance (924) Property Insurance	1,496,959
11	InjuriesAndDamages (925) Injuries and Damages	878,251
12	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	5,800,062
13	FranchiseRequirements (927) Franchise Requirements
14	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	408,223
15	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.	175,913
16	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	420,344
17	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	1,680,664
18	RentsAdministrativeAndGeneralExpense (931) Rents	386,711
19	AdministrativeAndGeneralOperationExpense TOTAL Operation (Total of lines 6 thru 18)	32,630,984
20	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
21	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	33,559
22	AdministrativeAndGeneralExpenses TOTAL Administrative and General Expenses (Total of lines 19 and 21)	32,664,543

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
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. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c). Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c). 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. 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. 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. 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. Report in column (i) and (j) the total megawatthours received and delivered. 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. 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. Footnote entries and provide explanations following all required data.
									TRANSFER OF ENERGY		REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Line No.	PaymentByCompanyOrPublicAuthority Payment By (Company of Public Authority) (Footnote Affiliation) (a)	TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName Energy Received From (Company of Public Authority) (Footnote Affiliation) (b)	TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c)	StatisticalClassificationCode Statistical Classification (d)	RateScheduleTariffNumber Ferc Rate Schedule of Tariff Number (e)	TransmissionPointOfReceipt Point of Receipt (Substation or Other Designation) (f)	TransmissionPointOfDelivery Point of Delivery (Substation or Other Designation) (g)	BillingDemand Billing Demand (MW) (h)	TransmissionOfElectricityForOthersEnergyReceived Megawatt Hours Received (i)	TransmissionOfElectricityForOthersEnergyDelivered Megawatt Hours Delivered (j)	Demand Charges ($) (k)	Energy Charges ($) (l)	Other Charges ($) (m)	RevenuesFromTransmissionOfElectricityForOthers Total Revenues ($) (k+l+m) (n)
1	Arizona Electric Power Cooperative	Not Available	Not Available	LFP	OATT	Paloverde, AZ	Four Corners, NM	36	77,760	77,760	260,100		21,816	281,916
2	Arizona Electric Power Cooperative	Not Available	Not Available	SFP	OATT	Various	Various		26,611	26,611		60	13,106	13,046
3	Arizona Electric Power Cooperative	Not Available	Not Available	NF	OATT	Various	Various		1	1			875	875
4	Broadview Energy JN LLC	Not Available	Not Available	SFP	OATT	Various	Various		3,869	3,869		20,018	5,061	25,079
5	Broadview Energy JN LLC	Not Available	Not Available	NF	OATT	Various	Various		8,661	8,661		36,249	11,882	48,131
6	Broadview Energy KW LLC	Not Available	Not Available	SFP	OATT	Various	Various		6,321	6,321		27,674	9,105	36,779
7	Broadview Energy KW LLC	Not Available	Not Available	NF	OATT	Various	Various		2,410	2,410		12,906	1,590	14,496
8	Clines Corners Wind Farm	Not Available	Not Available	LFP	OATT	San Juan, NM	Palo Verde, AZ	119	257,040	257,040	699,113		420,795	1,119,908
9	Clines Corners Wind Farm	Not Available	Not Available	SFP	OATT	Various	Various		50,747	50,747		273,131	81,255	354,386
10	Clines Corners Wind Farm	Not Available	Not Available	NF	OATT	Various	Various		1,702	1,702		7,519	1,990	9,509
11	Cortaro Marana Irrigation District	Arizona Power Authority	Salt River Project Agricultural Improvement and Power District	OS	102	Saguaro Substation	Cortaro Marana Irrigation Dist		1,012	1,012			16,211	16,211
12	Duran Mesa LLC	Not Available	Not Available	SFP	OATT	Various	Various		6,799	6,799		44,324	10,884	55,208
13	Dynasty Power Inc	Not Available	Not Available	SFP	OATT	Various	Various		153	153		888	294	1,182
14	Dynasty Power Inc	Not Available	Not Available	NF	OATT	Various	Various		101	101		589	168	757
15	El Paso Electric Company	Not Available	Not Available	SFP	OATT	Various	Various		232	232		1,168	505	1,673
16	El Paso Electric Company	Not Available	Not Available	NF	OATT	Various	Various		6,105	6,105		22,944	10,642	33,586
17	FreePort-McMoRan Copper & Gold Energy Service, LLC	Not Available	Not Available	LFP	OATT	Four Corners, NM	Greenlee, AZ	139	300,240	300,240	1,004,275		461,841	1,466,116
18	Macquarie Energy	Not Available	Not Available	SFP	OATT	Various	Various						4,503	4,503
19	Macquarie Energy	Not Available	Not Available	NF	OATT	Various	Various		4,785	4,785		20,324	3,668	23,992
20	(a) Navopache Electric Cooperative	Tucson Electric Power Company	Navopache Electric Cooperative	OS	OATT	Springerville, AZ	Springerville, AZ						3,075	3,075
21	Navajo Tribal Utility Authority	Public Service Company of New Mexico	Navajo Tribal Utility Authority	FNO	OATT	San Juan, NM	Shiprock, NM	(j) 33	70,493	70,493		185,531	178,711	364,242
22	Open Access Technology International Inc.	Not Available	Not Available	NF	OATT	Various	Various					77,611		77,611
23	Pacificorp	Not Available	Not Available	NF	OATT	Various	Various		125	125		729	383	1,112
24	Powerex	Not Available	Not Available	NF	OATT	Various	Various		1,204	1,204		6,275	2,332	8,607
25	Public Service Company of New Mexico	Not Available	Not Available	LFP	OATT	San Juan, NM	Greenlee, AZ	14	30,240	30,240	101,150		26,753	127,903
26	Public Service Company of New Mexico	Not Available	Not Available	SFP	OATT	Various	Various		11,969	11,969		47,189	12,786	59,975
27	Public Service Company of New Mexico	Not Available	Not Available	NF	OATT	Various	Various		11,720	11,720		49,080	31,673	80,753
28	Rainbow Energy	Not Available	Not Available	SFP	OATT	Various	Various		20	20		117	41	158
29	Salt River Project Agricultural Improvement and Power District	Not Available	Not Available	SFP	OATT	Various	Various		5,705	5,705		23,596	26,534	2,938
30	Salt River Project Agricultural Improvement and Power District	Not Available	Not Available	NF	OATT	Various	Various		4,194	4,194		17,780	294,177	311,957
31	Shell Energy North America	Not Available	Not Available	NF	OATT	Various	Various		225	225		1,313	445	1,758
32	Tecolote Wind LLC	Not Available	Not Available	SFP	OATT	Various	Various		27,198	27,198		282,554	41,305	323,859
33	Tecolote Wind LLC	Not Available	Not Available	NF	OATT	Various	Various		770	770		4,216	892	5,108
34	Tenaska Power Services Co.	Not Available	Not Available	SFP	OATT	Various	Various		122,323	122,323		534,020	239,294	773,314
35	Tenaska Power Services Co.	Not Available	Not Available	NF	OATT	Various	Various		141,763	141,763		601,773	270,918	872,691
36	Tohono O'odham Utility	Tucson Electric Power Company	Tohono O'odham Utility	(g) OLF	OATT	Palo Verde, AZ	San Xavier		8,315	8,315		23,990	29,675	53,665
37	TransAlta Energy Marketing (US) Inc	Not Available	Not Available	SFP	OATT	Various	Various		991	991		4,646	1,975	6,621
38	TransAlta Energy Marketing (US) Inc	Not Available	Not Available	NF	OATT	Various	Various		1,787	1,787		10,076	3,350	13,426
39	Tri-State Generation and Transmission Association, Inc.	Not Available	Not Available	LFP	OATT	Springerville, AZ	San Juan, NM	167	360,720	360,720	1,206,575		101,202	1,307,777
40	Tri-State Generation and Transmission Association, Inc.	Not Available	Not Available	LFP	OATT	Greenlee, AZ	San Juan, NM	40	86,400	86,400	289,000		24,240	313,240
41	Tri-State Generation and Transmission Association, Inc.	Not Available	Not Available	LFP	OATT	Springerville, AZ	San Juan, NM	93	200,880	200,880	671,925		258,482	930,407
42	Tri-State Generation and Transmission Association, Inc.	Not Available	Not Available	SFP	OATT	Various	Various		2,705	2,705		13,029	4,725	17,754
43	Tri-State Generation and Transmission Association, Inc.	Not Available	Not Available	NF	OATT	Various	Various		612	612		2,967	1,852	4,819
44	Tri-State Generation and Transmission Association, Inc.	Not Available	Not Available	FNO	OATT	Springerville, AZ	Catron, AZ						3,344	3,344
45	(b) Tri-State Generation and Transmission Association, Inc. - SOCORRO	Tri-State Generation and Transmission Association, Inc.	Soccorro Electric Cooperative, Inc	OS	OATT	Springerville, AZ	Springerville, AZ						984	984
46	Uniper Global Commodities North America LLC	Not Available	Not Available	SFP	OATT	Various	Various		185	185		1,004	363	1,367
47	Uniper Global Commodities North America LLC	Not Available	Not Available	NF	OATT	Various	Various		445	445		1,783	884	2,667
48	(c) UNS Electric, Inc.	Not Available	Not Available	LFP	OATT	Jojoba, AZ	Westwing, AZ	147	317,520	317,520	1,062,075		430,497	1,492,572
49	(d) UNS Electric, Inc.	Not Available	Not Available	SFP	OATT	Various	Various		2,000	2,000		9,300	4,238	13,538
50	(e) UNS Electric, Inc.	Not Available	Not Available	NF	OATT	Various	Various		5,215	5,215		27,769	10,941	38,710
51	(f) UNS Electric, Inc.	UNS Electric, Inc.	UNS Electric, Inc.	FNO	OATT	Various	Vail, AZ	(k) 57	123,212	123,212		382,381	177,313	559,694
52	Trico Electric Cooperative	Not Available	Not Available	LFP	OATT	San Juan, NM	Vail, AZ	85	183,600	183,600	614,125		90,294	704,419
53	Trico Electric Cooperative	Not Available	Not Available	SFP	OATT	Various	Various						119,548	119,548
54	Trico Electric Cooperative	Not Avialable	Not Available	NF	OATT	Various	Various						334	334
55	Trico Electric Cooperative	Trico Electric Cooperative	Trico Electric Cooperative	FNO	OATT	Vail, AZ	North Loop, AZ	(l) 17	36,260	36,260		148,467	10,209	158,676
56	Pattern New Mexico Wind			OS								(o) 179,421		179,421
57	Red Cloud Wind LLC	Not Available	Not Available	LFP	OATT	San Juan, NM	Navajo, AZ	143	523,272	523,272	1,394,425		924,406	2,318,831
58	Red Cload Wind LLC	Not Available	Not Available	SFP	OATT	Various	Various		6,967	6,967		10	21,297	21,287
59	Red Cloud Wind LLC	Not Available	Not Available	NF	OATT	Various	Various		54	54		180	57	237
60	Potential FERC Refund			OS								(p) 1,707,766	(q) 2,921	1,710,687
61	El Paso Electric Company Transmission Rights	Not Available	Not Available	(h) OS	RS 49	Various	Various		138,066	138,066
62	Arizona Electric Power Cooperative Transmission Rights	Not Available	Not Available	(i) OS	RS 124	Various	Various		(m) 8,603	(n) 8,603
35	TOTAL							1,090	3,123,149	3,123,149	7,302,763	1,396,835	4,300,925	13,000,523

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: PaymentByCompanyOrPublicAuthority

Docket #ER15-1860-000 has details on the Interconnection and TSA 218 reported herein.

(b) Concept: PaymentByCompanyOrPublicAuthority

Docket #ER16-1920-001 has details on the Interconnection and TSA 267 reported herein.

(c) Concept: PaymentByCompanyOrPublicAuthority

UNS Electric, Inc. and Tucson Electric Power Company are affiliated, wholly-owned subsidiaries of UNS Energy Corporation.

(d) Concept: PaymentByCompanyOrPublicAuthority

UNS Electric, Inc. and Tucson Electric Power Company are affiliated, wholly-owned subsidiaries of UNS Energy Corporation.

(e) Concept: PaymentByCompanyOrPublicAuthority

UNS Electric, Inc. and Tucson Electric Power Company are affiliated, wholly-owned subsidiaries of UNS Energy Corporation.

(f) Concept: PaymentByCompanyOrPublicAuthority

UNS Electric, Inc. and Tucson Electric Power Company are affiliated, wholly-owned subsidiaries of UNS Energy Corporation.

(g) Concept: StatisticalClassificationCode

Tohono O'odham Utility purchases bundled power and transmission from TEP. The transmission revenue reported here is extrapolated using OATT rates.

(h) Concept: StatisticalClassificationCode

The grandfathered agreement executed between Tucson Electric Power Company and El Paso Electric Company includes the exchange of transmission services over agreed-upon facilities. The contract terminates 40 years from commercial operation of the Springerville-Luna 345kV circuit.

(i) Concept: StatisticalClassificationCode

Rate Schedule No. 124 includes the assignment of certain transmission rights to Arizona Electric Power Cooperative. The contract terminates December 31, 2040 and continues to renew for three year periods for an ongoing basis.

(j) Concept: BillingDemand

Monthly average coincident peak.

(k) Concept: BillingDemand

Monthly average coincident peak.

(l) Concept: BillingDemand

Monthly average coincident peak.

(m) Concept: TransmissionOfElectricityForOthersEnergyReceived

The amounts listed in column (i) above reflect energy reserved. MWh received equals MWh delivered because losses are accounted for financially and included in column (m).

(n) Concept: TransmissionOfElectricityForOthersEnergyDelivered

The amounts listed in column (j) above reflect energy reserved. MWh received equals MWh delivered because losses are accounted for financially and included in column (m).

(o) Concept: EnergyChargesRevenueTransmissionOfElectricityForOthers

Pattern New Mexico Wind deferred long-term Firm Point-to-Point Transmission Service to January 1, 2021.

(p) Concept: EnergyChargesRevenueTransmissionOfElectricityForOthers

Potential FERC refund for transmission customers pursuant to Docket No. ER19-2019-000. The amount reported is the difference between the standard rates and formula rates which became effective on 1/1/2021.

(q) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

The amounts listed as Other Charges in column (m) above include ancillary charges, losses, and adjustments related to the prior period.

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

TRANSMISSION OF ELECTRICITY BY ISO/RTOs
Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. 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. In column (d) report the revenue amounts as shown on bills or vouchers. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line No.	Payment Received by (Transmission Owner Name) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Total Revenue by Rate Schedule or Tariff (d)	Total Revenue (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
40	TOTAL

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
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. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. 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. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. Enter ""TOTAL"" in column (a) as the last line. Footnote entries and provide explanations following all required data.
			TRANSFER OF ENERGY		EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.	NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	TransmissionOfElectricityByOthersEnergyReceived MegaWatt Hours Received (c)	TransmissionOfElectricityByOthersEnergyDelivered MegaWatt Hours Delivered (d)	DemandChargesTransmissionOfElectricityByOthers Demand Charges ($) (e)	EnergyChargesTransmissionOfElectricityByOthers Energy Charges ($) (f)	OtherChargesTransmissionOfElectricityByOthers Other Charges ($) (g)	ChargesForTransmissionOfElectricityByOthers Total Cost of Transmission ($) (h)
1	Arizona Electric Power Cooperative	NF	7,635	7,635		39,257	4,505	43,762
2	Arizona Public Service Company	LFP	474,880	474,880	1,011,874		117,733	1,129,607
3	Arizona Public Service Company	SFP	22,651	22,651		107,117	182,720	289,837
4	Arizona Public Service Company	NF	429	429		1,560	2,334	3,894
5	Arizona Public Service Company	OLF					(b) 25,459	25,459
6	El Paso Electric Power Company	LFP	804,993	804,993		3,610,170	369,717	3,979,887
7	El Paso Electric Power Company	SFP	97,502	97,502		438,326	692,154	1,130,480
8	El Paso Electric Power Company	NF	53,041	53,041		246,749	24,218	270,967
9	Public Service Company of New Mexico	NF	4,928	4,928		60,974	7,766	68,740
10	Salt River Project Agricultural Improvement and Power District	LFP	1,297,063	1,297,063		3,832,651	1,388,626	5,221,277
11	Salt River Project Agricultural Improvement and Power District	NF	664,197	664,197		869,759	300,682	1,170,441
12	Western Area Power Administration	NF	2,997	2,997		7,126	6,140	13,266
13	Western Area Power Administration	SFP	1,600	1,600		3,536	(c) 2,680	6,216
14	PPFAC Ratemaking Treatment	OS	0				(d) 4,733,635	4,733,635
15	El Paso Electric Power Company Transmission Rights	(a) OLF	216,228	216,228
	TOTAL		3,648,144	3,648,144	1,011,874	9,217,225	1,608,901	8,620,198

FOOTNOTE DATA

(a) Concept: StatisticalClassificationCode

The grandfathered agreement executed between Tucson Electric Power Company and El Paso Electric Company includes the exchange of transmission services over agreed-upon facilities. The contract terminates 40 years from commercial operation of the Springerville-Luna 345kV circuit.

(b) Concept: OtherChargesTransmissionOfElectricityByOthers

"Other Charges" in column (g) include amounts charged by Arizona Public Service Company (APS) for non-conforming transmission service under APS Service Agreement Nos. 336, 337, and 378. The contracts terminate in 2052.

(c) Concept: OtherChargesTransmissionOfElectricityByOthers

Amounts listed as "Other Charges" in column (g) above include prior period adjustments, ancillary charges, and losses.

(d) Concept: OtherChargesTransmissionOfElectricityByOthers

Purchased Power and Fuel Adjustment Clause (PPFAC) ratemaking treatment.

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

Deprec, Depl and Amort of Elec Plant (403,403.1,404,and 405) (except Amortization of Acquisition Adjustments)
Report the year to date amounts of depreciation expense, asset retirement cost depreciation, depletion and amortization, except amortization of acquisition adjustments for the accounts indicated and classified according to the plant functional groups described.
Line No.	FunctionalClassificationAxis Functional Classification (a)	DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments Depreciation Expense (Account 403) (b)	DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	AmortizationOfLimitedTermPlantOrProperty Amortization of Limited Term Electric Plant (Account 404) (d)	AmortizationOfOtherElectricPlant Amortization of Other Electric Plant (Acc 405) (e)	DepreciationAndAmortization Total (f)
1	Intangible Plant			7,535,891		7,535,891
2	Steam Production Plant	20,118,421				20,118,421
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant	9,663,576				9,663,576
7	Transmission Plant	5,067,823				5,067,823
8	Distribution Plant	10,083,546				10,083,546
9	General Plant	8,664,275				8,664,275
10	Common Plant-Electric
11	TOTAL	53,597,641		7,535,891		61,133,532

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line No.	Description of Item(s) (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1	Energy
2	Net Purchases (Account 555)
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)
4	Transmission Rights
5	Ancillary Services
6	Other Items (list separately)
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

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

Monthly Peak Loads and Energy Output
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. Report in column (b) by month the system’s output in Megawatt hours for each month. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.	MonthAxis Month (a)	Total Monthly Energy (MWH) (b)	Monthly Non-Requirements Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak Megawatts (See Instr. 4) (d)	DayOfMonthlyPeak Monthly Peak Day of Month (e)	HourOfMonthlyPeak Monthly Peak Hour (f)
	NAME OF SYSTEM: 0
1	January	1,158,749	482,573	1,428	3	8
2	February	1,107,946	506,373	1,542	3	8
3	March	1,137,072	513,179	1,278	27	19
4	Total for Quarter 1	3,403,767	1,502,125
5	April
6	May
7	June
8	Total for Quarter 2
9	July
10	August
11	September
12	Total for Quarter 3
41	Total

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

MONTHLY TRANSMISSION SYSTEM PEAK LOAD
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. Report on Column (b) by month the transmission system's peak load. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Firm Network Service for Self (e)	Firm Network Service for Others (f)	Long-Term Firm Point-to-point Reservations (g)	Other Long-Term Firm Service (h)	Short-Term Firm Point-to-point Reservation (i)	Other Service (j)
	NAME OF SYSTEM: 0
1	January	3,494	13	8	1,107	118	1,033	200	586	450
2	February	3,856	4	8	1,257	132	1,033	200	784	450
3	March	3,961	26	20	1,075	86	1,033	200	1,117	450
4	Total for Quarter 1				3,439	336	3,099	600	2,487	1,350
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				3,439	336	3,099	600	2,487	1,350

Name of Respondent:

Tucson Electric Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/10/2022

Year/Period of Report

End of:

2022

/

Q1

Monthly ISO/RTO Transmission System Peak Load
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. Report on Column (b) by month the transmission system's peak load. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f). Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Import into ISO/RTO (e)	Exports from ISO/RTO (f)	Through and Out Service (g)	Network Service Usage (h)	Point-to-Point Service Usage (i)	Total Usage (j)
	NAME OF SYSTEM: 0
1	January
2	February
3	March
4	Total for Quarter 1				0	0	0	0	0	0
5	April
6	May
7	June
8	Total for Quarter 2				0	0	0	0	0	0
9	July
10	August
11	September
12	Total for Quarter 3				0	0	0	0	0	0
13	October
14	November
15	December
16	Total for Quarter 4				0	0	0	0	0	0
17	Total Year to Date/Year				0	0	0	0	0	0

FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

Purpose

Who Must Submit

What and Where to Submit

When to Submit

Where to Send Comments on Public Reporting Burden.

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report