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)

AEP Texas

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

AEP Texas

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)

1 Riversise Plaza, Columbus, OH 43215-2373

05 Name of Contact Person

Jason M Johnson

06 Title of Contact Person

Accountant

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

1 Riversise Plaza, Columbus, OH 43215-2373

08 Telephone of Contact Person, Including Area Code

614-716-1000

09 This Report is An Original / A Resubmission

(1)

☑ An Original

(2)

☐ A Resubmission

10 Date of Report (Mo, Da, Yr)

05/26/2022

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

Jeffrey W.Hoersdig

02 Title

Assistant Controller

03 Signature

Jeffrey W.Hoersdig

04 Date Signed (Mo, Da, Yr)

05/26/2022

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:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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	N/A
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
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
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
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

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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.

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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	12,066,168,790	11,855,056,606
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	588,449,264.00	552,902,898
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		12,654,618,054	12,407,959,503
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	2,415,381,199.00	2,368,625,863
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		10,239,236,855	10,039,333,640
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)		10,239,236,855	10,039,333,640
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)		73,170,110	72,113,730
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		1,953,794	1,953,794
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		977,116	972,799
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	26,336,125	26,348,158
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228
24	OtherInvestments Other Investments (124)		15,317,043	15,329,062
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)
29	SpecialFunds Special Funds (Non Major Only) (129)		118,040,315	116,978,318
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		160,670,161	159,636,534
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)
36	SpecialDeposits Special Deposits (132-134)		1,370,425	678,845
37	WorkingFunds Working Fund (135)		100,000	100,000
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		147,363,356	121,846,932
41	OtherAccountsReceivable Other Accounts Receivable (143)		113,349	40,896
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		4,095,048	4,094,496
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		5,866,550	7,688,270
45	FuelStock Fuel Stock (151)	227
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227
47	Residuals Residuals (Elec) and Extracted Products (153)	227
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	78,819,268	73,867,192
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
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)		3,160,456	3,480,282
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)		2,072,004	1,592,729
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		73,864,994	77,926,689
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		11,500,000
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		177,745	1,052
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)
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)		320,313,099	283,128,392
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		25,376,247	26,147,194
70	ExtraordinaryPropertyLosses Extraordinary Property Losses (182.1)	230a
71	UnrecoveredPlantAndRegulatoryStudyCosts Unrecovered Plant and Regulatory Study Costs (182.2)	230b
72	OtherRegulatoryAssets Other Regulatory Assets (182.3)	232	336,612,803	332,892,993
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		45,724	45,724
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)		20	13
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	81,740,002	3,020,368
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)		4,169,818	4,292,086
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	172,103,597	172,497,896
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		620,048,211	538,896,274
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		11,267,098,216	10,948,881,110

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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	1	1
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)		19,482	19,482
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	1,553,947,793	1,553,947,793
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
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	2,108,697,810	2,039,102,442
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	7,687,834	7,699,867
13	ReacquiredCapitalStock (Less) Reaquired Capital Stock (217)	250	40,947	40,947
14	NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218)
15	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	122(a)(b)	6,248,962	6,531,511
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		3,664,063,012	3,594,197,128
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256
19	ReacquiredBonds (Less) Reaquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256	4,813,518,466	4,813,520,781
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		10,928,863	11,198,006
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		4,802,589,603	4,802,322,775
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		81,597,314	85,491,011
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		98,611	128,812
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		8,384,245	8,640,158
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)		274,102	269,015
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		3,587,004	3,734,452
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		93,941,276	98,263,448
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)
38	AccountsPayable Accounts Payable (232)		237,273,021	306,069,403
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		262,204,974	26,898,544
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		49,256,195	51,835,108
41	CustomerDeposits Customer Deposits (235)		1,302,081	399,790
42	TaxesAccrued Taxes Accrued (236)	262	108,250,966	70,331,594
43	InterestAccrued Interest Accrued (237)		56,230,805	42,325,990
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		32,277	32,449
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		51,893,869	43,414,084
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		20,628,737	20,648,406
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities
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)		787,008,371	561,890,470
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	6,678,535	6,799,788
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	110,867,800	93,265,544
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	532,302,570	529,426,732
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)		1,086,328,990	1,077,026,329
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		183,318,057	185,688,895
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		1,919,495,952	1,892,207,288
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		11,267,098,214	10,948,881,109

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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	394,578,591	341,032,238	394,578,591	341,032,238	394,578,591	341,032,238
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	119,126,250	115,564,542	119,126,250	115,564,542	119,126,250	115,564,542
5	MaintenanceExpense Maintenance Expenses (402)	320	22,628,804	19,067,555	22,628,804	19,067,555	22,628,804	19,067,555
6	DepreciationExpense Depreciation Expense (403)	336	80,469,090	70,289,223	80,469,090	70,289,223	80,469,090	70,289,223
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336	11,322	13,796	11,322	13,796	11,322	13,796
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	9,426,020	8,284,354	9,426,020	8,284,354	9,426,020	8,284,354
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336
10	AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11	AmortizationOfConversionExpenses Amort. of Conversion Expenses (407.2)
12	RegulatoryDebits Regulatory Debits (407.3)
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		1,027,376	997,724	1,027,376	997,724	1,027,376	997,724
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	37,373,438	36,313,682	37,373,438	36,313,682	37,373,438	36,313,682
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	9,034,545	6,620,295	9,034,545	6,620,295	9,034,545	6,620,295
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	353,608	170,646	353,608	170,646	353,608	170,646
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	23,054,544	17,913,477	23,054,544	17,913,477	23,054,544	17,913,477
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	16,102,099	16,821,483	16,102,099	16,821,483	16,102,099	16,821,483
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	121,253	159,848	121,253	159,848	121,253	159,848
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)		197,162	317,522	197,162	317,522	197,162	317,522
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)		54,599	55,063	54,599	55,063	54,599	55,063
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		286,139,083	257,991,504	286,139,083	257,991,504	286,139,082	257,991,504
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		108,439,508	83,040,734	108,439,508	83,040,734	108,439,509	83,040,734
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)
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)
35	NonoperatingRentalIncome Nonoperating Rental Income (418)			250		250
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	12,033	42,128	12,033	42,128
37	InterestAndDividendIncome Interest and Dividend Income (419)		119,375	176,442	119,375	176,442
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		4,304,109	4,150,981	4,304,109	4,150,981
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		1,039,587	1,405,775	1,039,587	1,405,775
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)			28,273		28,273
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		5,451,037	5,719,593	5,451,037	5,719,593
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		12,689	8,104	12,689	8,104
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		133,357	109,451	133,357	109,451
46	LifeInsurance Life Insurance (426.2)		112,256	48,527	112,256	48,527
47	Penalties Penalties (426.3)		686	1,284	686	1,284
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		316,963	284,989	316,963	284,989
49	OtherDeductions Other Deductions (426.5)		1,600,816	3,422,374	1,600,816	3,422,374
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		2,176,768	3,777,675	2,176,768	3,777,675
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	469,325	1,231,000	469,325	1,231,000
54	IncomeTaxesOther Income Taxes-Other (409.2)	262
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272		586,716		586,716
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272
57	InvestmentTaxCreditAdjustmentsNonutilityOperations Investment Tax Credit Adj.-Net (411.5)
58	InvestmentTaxCredits (Less) Investment Tax Credits (420)
59	TaxesOnOtherIncomeAndDeductions TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)		469,325	644,284	469,325	644,284
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		3,743,595	2,586,202	3,743,595	2,586,202
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		43,107,825	39,218,192	43,107,825	39,218,192
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		977,642	1,196,714	977,642	1,196,714
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		122,268	345,836	122,268	345,836
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)		259,973	151,843	259,973	151,843
68	OtherInterestExpense Other Interest Expense (431)		365,216	744,718	365,216	744,718
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		2,233,158	2,184,824	2,233,158	2,184,824
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		42,599,766	39,472,479	42,599,766	39,472,479
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		69,583,336	46,154,457	69,583,336	46,154,457
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)		69,583,336	46,154,457	69,583,336	46,154,457

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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		2,039,102,442	1,749,074,246
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)		69,595,368	46,196,586
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)
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)		2,108,697,810	1,795,270,832
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)		2,108,697,810	1,795,270,832
	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:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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)	69,583,336	46,154,457
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	89,906,432	78,587,373
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of	1,027,376	997,724
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	6,952,444	1,678,710
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	121,253	159,848
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	24,245,879	14,480,192
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	4,952,076	279,507
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	61,280,980	44,949,848
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	3,780,888	11,429,127
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	868,273	353,274
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	4,304,109	4,150,981
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies	12,033	42,128
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other (provide details in footnote):	(a) 83,897,337	81,554,802
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	108,329,332	61,268,071
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)	361,740,374	299,661,081
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	4,304,109	4,150,981
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Other (provide details in footnote):
31.2	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Acquired Assets	171,789	602,467
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	357,608,054	296,112,567
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)	(b) 2,026,527	447,410
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 CIAC Proceeds	11,750,725	17,233,600
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription (Increase) Decrease in Other Special Deposits		43,673
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Notes Receivable from Associated Companies
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	343,830,801	278,475,230
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
64.1	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Other (provide details in footnote):
64.2	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Long Term Issuances Costs	4,616	3,008
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceeds on Capital Leaseback	(c) 201,971	299,491
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Notes Payable to Associated Companies - Issued	235,306,429	216,912,890
67.3	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Capital Contributions from Parent
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	235,503,784	217,209,373
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	2,315	2,214
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.2	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Notes Payable to Associated Companies - Retired
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)	235,501,469	217,207,159
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)
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	100,000	100,000
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	100,000	100,000

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities


Schedule Page: 120-121 Line No: 18	Column (b)	Column (c)

	2021 Cash Flow Incr / (Decr)	2020 Cash Flow Incr / (Decr)

Utility Plant, Net	$(30,314,527)	$(55,040,789)
Property and Investments, Net	(380,410)	(1,878,858)
Special Funds	—	—
Margin Deposits	(480,866)	(73,637)
Mark-to-Market of Risk Management Contracts	(19)	103,663
Prepayments	(906,921)	(12,866,107)
Accrued Utility Revenues, Net	(15,129,442)	(6,041,273)
Miscellaneous Current and Accr Assets	—	1,502,586
Unamortized Debt Expense	2,333,897	2,331,516
Other Deferred Debits, Net	(24,899,687)	(21,270,607)
Proprietary Capital, Net	—	41,655
Other Comprehensive Income, Net	792,011	792,011
Unamortized Discount/Premium on Long-Term Debt	792,530	653,005
Accumulated Provisions - Misc	(6,319,528)	(66,252,632)
Current and Accrued Liabilities, Net	(14,443,729)	14,447,144
Other Deferred Credits, Net	16,935,912	(40,904,051)

Total	$(72,020,779)	$(184,456,374)

(b) Concept: ProceedsFromDisposalOfNoncurrentAssets


Schedule Page: 120-121 Line No: 37	Column (b)	Column (c)

	2021 Cash Flow Incr / (Decr)	2020 Cash Flow Incr / (Decr)

Proceeds on Sales file over $100K

Total	$—	$—

(c) Concept: OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities


Schedule Page: 120-121 Line No: 67	Column (b)	Column (c)

	2020 Cash Flow Incr / (Decr)	2019 Cash Flow Incr / (Decr)

Proceeds on Capital Leaseback

Total	$—	$—

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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.

INDEX OF NOTES TO FINANCIAL STATEMENTS


			Glossary of Terms for Notes
1.			Significant Accounting Matters
2.			New Accounting Standards
3.			Comprehensive Income
4.			Rate Matters
5.			Commitments, Guarantees and Contingencies
6.			Benefit Plans
7.			Business Segments
8.			Derivatives and Hedging
9.			Fair Value Measurements
10.			Income Taxes
11.			Financing Activities
12.			Revenue from Contracts with Customers

GLOSSARY OF TERMS FOR NOTES

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.


Term						Meaning

AEP						American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority-owned consolidated subsidiaries and consolidated affiliates.
AEP System						American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP Texas						AEP Texas Inc., an AEP electric utility subsidiary.
AEPSC						American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC						Allowance for Equity Funds Used During Construction.
AOCI						Accumulated Other Comprehensive Income.
COVID-19						Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
Excess ADIT						Excess accumulated deferred income taxes.
FASB						Financial Accounting Standards Board.
FERC						Federal Energy Regulatory Commission.
FTR						Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
IRS						Internal Revenue Service.
MTM						Mark-to-Market.
OPEB						Other Postretirement Benefits.
OTC						Over-the-counter.
Parent						American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PUCT						Public Utility Commission of Texas.
Risk Management Contracts						Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Tax Reform						On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
Utility Money Pool						Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.

1. SIGNIFICANT ACCOUNTING MATTERS

General

The financial statements and footnotes were prepared in accordance with the Uniform System of Accounts prescribed by the FERC. The unaudited financial statements and footnotes should be read in conjunction with AEP Texas’ 2021 FERC Form 1 (2021 Annual Report).

In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods. Net income for the three months ended March 31, 2022 is not necessarily indicative of results that may be expected for the year ending December 31, 2022.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

Cash and Cash Equivalents on the statements of cash flows include Cash, Working Fund and Temporary Cash Investments on the balance sheets with original maturities of three months or less.

Supplementary Information


	2022			2021
For the Three Months Ended March 31,	(in millions)
Cash was Paid for Interest (Net of Capitalized Amounts)	$	27.7		$	27.6
Noncash Acquisitions Under Finance Leases			0.6			0.8
As of March 31,
Construction Expenditures Included in Current and Accrued Liabilities			147.6			120.5

Subsequent Events

Management has evaluated the impact of events occurring after March 31, 2022 through April 28, 2022, the date that AEP Texas’ 2022 first quarter Form 10-Q was issued, and has updated such evaluation for disclosure purposes through May 26, 2022. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.

2. NEW ACCOUNTING STANDARDS

During the FASB’s standard-setting process and upon issuance of final standards, management reviews the new accounting literature to determine its relevance, if any, to AEP Texas’ business. There are no new standards expected to have a material impact on AEP Texas’ financial statements.

3. COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI and details of reclassifications from AOCI. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 - Benefit Plans for additional information.


		Cash Flow Hedge –		Pension
Three Months Ended March 31, 2022		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2021		$	(1.3)	$	(5.2)	$	(6.5)
Change in Fair Value Recognized in AOCI		—		—		—
Amount of (Gain) Loss Reclassified from AOCI
Interest on Long-Term Debt (a)		0.4		—		0.4
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.4		—		0.4
Income Tax (Expense) Benefit		0.1		—		0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.3		—		0.3
Net Current Period Other Comprehensive Income (Loss)		0.3		—		0.3
Balance in AOCI as of March 31, 2022		$	(1.0)	$	(5.2)	$	(6.2)


		Cash Flow Hedge –		Pension
Three Months Ended March 31, 2021		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2020		$	(2.3)	$	(6.6)	$	(8.9)
Change in Fair Value Recognized in AOCI		0.1		—		0.1
Amount of (Gain) Loss Reclassified from AOCI
Interest on Long-Term Debt (a)		0.3		—		0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.3		—		0.3
Income Tax (Expense) Benefit		0.1		—		0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.2		—		0.2
Net Current Period Other Comprehensive Income (Loss)		0.3		—		0.3
Balance in AOCI as of March 31, 2021		$	(2.0)	$	(6.6)	$	(8.6)

(a)Amounts reclassified to the referenced line item on the statements of income.

4. RATE MATTERS

As discussed in the 2021 Annual Report, AEP Texas is involved in rate and regulatory proceedings at the FERC and the PUCT. The Rate Matters note within the 2021 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2022 and updates the 2021 Annual Report.

Regulatory Assets Pending Final Regulatory Approval


	March 31,		December 31,
	2022		2021
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Mobile Generation Lease Payments	$	1.3	$	—
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	23.6		22.4
Vegetation Management Program	5.2		5.2
Texas Retail Electric Provider Bad Debt Expense	4.1		4.1
COVID-19	3.6		2.1
Other Regulatory Assets Pending Final Regulatory Approval	8.0		7.4
Total Regulatory Assets Pending Final Regulatory Approval	$	45.8	$	41.2

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Interim Transmission and Distribution Rates

Through March 31, 2022, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is approximately $368 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. AEP Texas is required to file for a comprehensive rate review no later than April 5, 2024.

5. COMMITMENTS, GUARANTEES AND CONTINGENCIES

AEP Texas is subject to certain claims and legal actions arising in the ordinary course of business. In addition, AEP Texas’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against AEP Texas cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2021 Annual Report should be read in conjunction with this report.

GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third-parties unless specified below.

Letters of Credit

Standby letters of credit are entered into with third-parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under five uncommitted facilities totaling $400 million. AEP Texas’ maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, 2022 was $2 million with a maturity date of July 2022.

Indemnifications and Other Guarantees

Contracts

AEP Texas enters into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, 2022, there were no material liabilities recorded for any indemnifications.

Master Lease Agreements

AEP Texas leases certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, AEP Texas is committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed. As of March 31, 2022, the maximum potential loss by AEP Texas for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was $11 million.

ENVIRONMENTAL CONTINGENCIES

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

Transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials. AEP Texas currently incurs costs to dispose of these substances safely. For remediation processes not specifically discussed, management does not anticipate that the liabilities, if any, arising from such remediation processes would have a material effect on the financial statements.

OPERATIONAL CONTINGENCIES

Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula

Four participants in The American Electric Power System Retirement Plan (the Plan) filed a class action complaint in December 2021 in the U.S. District Court for the Southern District of Ohio against AEPSC and the Plan. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented. Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula. The Plaintiffs assert a number of claims on behalf of themselves and the purported class, including that: (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act and (c) AEP failed to provide required notice regarding the changes to the Plan. Among other relief, the Complaint seeks reformation of the Plan to provide additional benefits and the recovery of plan benefits for former employees under such reformed plan. The Plaintiffs previously had submitted claims for additional plan benefits to AEP, which were denied. On February 15, 2022, AEPSC and the Plan filed a motion to dismiss the complaint for failure to state a claim. AEP will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

6. BENEFIT PLANS

AEP Texas participates in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP Texas employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP Texas also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost (credit) for the plans:


	Pension Plans				OPEB
	Three Months Ended March 31,				Three Months Ended March 31,
	2022		2021		2022		2021
	(in millions)
Service Cost	$	2.8	$	3.0	$	0.1	$	0.2
Interest Cost	3.0		2.8		0.6		0.6
Expected Return on Plan Assets	(5.3)		(4.9)		(2.3)		(1.9)
Amortization of Prior Service Credit	—		—		(1.5)		(1.5)
Amortization of Net Actuarial Loss	1.3		2.1		—		—
Net Periodic Benefit Cost (Credit)	$	1.8	$	3.0	$	(3.1)	$	(2.6)

7. BUSINESS SEGMENTS

AEP Texas has one reportable segment, an electricity transmission and distribution business. AEP Texas’ other activities are insignificant.

8. DERIVATIVES AND HEDGING

AEPSC is agent for and transacts on behalf of AEP Texas.

Risk Management Strategies

AEP Texas’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEP Texas utilizes financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. AEP Texas does not hedge all fuel price risk. The gross notional volumes of AEP Texas’ outstanding derivative contracts for heating oil and gasoline as of March 31, 2022 and December 31, 2021 were 1 million gallons and 2 million gallons, respectively.

Cash Flow Hedging Strategies

AEP Texas utilizes a variety of interest rate derivative transactions in order to manage interest rate risk exposure. AEP Texas also utilizes interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. AEP Texas does not hedge all interest rate exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and other assumptions. In order to determine the relevant fair values of the derivative instruments, AEP Texas applies valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” AEP Texas reflects the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, AEP Texas is required to post or receive cash collateral based on third-party contractual agreements and risk profiles. The netted cash collateral from third-parties against short-term and long-term risk management assets and netted cash collateral paid to third-parties against short-term and long-term risk management liabilities were immaterial for AEP Texas as of March 31, 2022 and December 31, 2021.

The following tables represent the gross fair value of AEP Texas’ derivative activity on the balance sheets:


	March 31, 2022
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Derivative Instrument Assets	$	1.5	$	(1.3)	$	0.2
Long-Term Portion of Derivative Instrument Assets	—		—		—

Derivative Instrument Liabilities	—		—		—
Long-Term Portion of Derivative Instrument Liabilities	—		—		—


	December 31, 2021
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Derivative Instrument Assets	$	0.6	$	(0.6)	$	—
Long-Term Portion of Derivative Instrument Assets	—		—		—

Derivative Instrument Liabilities	—		—		—
Long-Term Portion of Derivative Instrument Liabilities	—		—		—

(a)Derivative instruments within these categories are disclosed as gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”

(b)Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”

(c)All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.

The table below presents AEP Texas’ activity of derivative risk management contracts:


Amount of Gain Recognized on Risk Management Contracts

	Three Months Ended March 31,
Location of Gain	2022		2021
	(in millions)
Operation Expenses	$	0.2	$	0.1
Maintenance Expenses	0.2		0.1
Other Regulatory Liabilities (a)	0.9		0.4
Total Gain on Risk Management Contracts	$	1.3	$	0.6

(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment.

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.

The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same line item on the statements of income as that of the associated risk being hedged. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), AEP Texas initially reports the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income on the balance sheets until the period the hedged item affects net income.

AEP Texas reclassifies gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income on the balance sheets into Interest on Long-Term Debt on the statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2022 and 2021, AEP Texas did not apply cash flow hedging to outstanding interest rate derivatives.

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.

Cash flow hedges included in Accumulated Other Comprehensive Income on the balance sheets were:

Impact of Cash Flow Hedges on the Balance Sheets

March 31, 2022

December 31, 2021

Interest Rate

Expected to be

Reclassified to

Net Income During

AOCI Gain (Loss)

the Next

AOCI Gain (Loss)

the Next

Net of Tax

Twelve Months

Net of Tax

Twelve Months

(in millions)

$

(1.0)

$

(1.0)

$

(1.3)

$

(1.1)

The actual amounts reclassified from Accumulated Other Comprehensive Income to Net Income can differ from the estimate above due to market price changes.

Credit Risk

Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.

Credit-Risk-Related Contingent Features

Cross-Acceleration Triggers

Certain interest rate derivative contracts contain cross-acceleration provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-acceleration provisions could be triggered if there was a non-performance event by AEP Texas under any of their outstanding debt of at least $50 million and the lender on that debt has accelerated the entire repayment obligation. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-acceleration provisions in contracts. AEP Texas had no derivative contracts with cross-acceleration provisions outstanding as of March 31, 2022 and December 31, 2021.

9. FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

Fair Value Measurements of Long-Term Debt

The fair values of Long-Term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

The book values and fair values of Long-Term Debt are summarized in the following table:


March 31, 2022				December 31, 2021
Book Value		Fair Value		Book Value		Fair Value
(in millions)
$	4,802.6	$	4,731.3	$	4,802.3	$	5,244.4

Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, AEP Texas’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2022


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Derivative Instrument Assets
Risk Management Commodity Contracts (a)	$	—	$	1.5	$	—	$	(1.3)	$	0.2

December 31, 2021


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Derivative Instrument Assets
Risk Management Commodity Contracts (a)	$	—	$	0.6	$	—	$	(0.6)	$	—

(a)Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’

10. INCOME TAXES

Effective Tax Rates (ETR)

The interim ETR for AEP Texas reflects the estimated annual ETR for 2022 and 2021 adjusted for tax expense associated with certain discrete items.

AEP Texas includes the amortization of Excess ADIT not subject to normalization requirements in the annual estimated ETR when regulatory proceedings instruct AEP Texas to provide the benefits of Tax Reform to customers over multiple interim periods. Certain regulatory proceedings may instruct AEP Texas to provide the benefits of Tax Reform to customers in a single period (e.g. by applying the Excess ADIT not subject to normalization requirements against an existing regulatory asset balance) and in these circumstances, AEP Texas recognizes the tax benefit discretely in the period recorded. The annual amount of Excess ADIT approved by the PUCT may not impact the ETR ratably during each interim period due to the variability of pretax book income between interim periods and the application of an annual estimated ETR.

The ETR for AEP Texas is included in the following table:


	Three Months Ended March 31,
	2022		2021
U.S. Federal Statutory Rate	21.0	%	21.0	%
Increase (decrease) due to:
State Income Tax, net of Federal benefit	0.3	%	1.4	%
Tax Reform Excess ADIT Reversal	(2.0)	%	(7.8)	%
Production and Investment Tax Credits	(0.2)	%	(0.3)	%
Flow Through	0.3	%	0.3	%
AFUDC Equity	(0.9)	%	(1.4)	%
Other	—	%	0.1	%
Effective Income Tax Rate	18.5	%	13.3	%

Federal and State Income Tax Audit Status

In the third quarter of 2019, AEP Texas and other AEP subsidiaries elected to amend the 2014 through 2017 federal returns. In the first quarter of 2020, the IRS notified AEP Texas and other AEP subsidiaries that it was beginning an examination of these amended returns, including the net operating losses (NOL) carryback to 2015 that originated in the 2017 return. As of March 31, 2022, the IRS has not issued any proposed adjustment and has accepted the 2014 amended return as filed. AEP Texas and other AEP subsidiaries have agreed to extend the statute of limitations on the 2017 tax return to December 31, 2022 to allow time for the audit to be completed and the Congressional Joint Committee on Taxation to approve the associated refund claim.

AEP Texas and other AEP subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns, and AEP Texas and other AEP subsidiaries are currently under examination in several state and local jurisdictions. Generally, the statutes of limitations have expired for tax years prior to 2017. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.

11. FINANCING ACTIVITIES

Long-Term Debt Activity

AEP Texas did not have any long-term debt issuances or retirements during the first three months of 2022.

Dividend Restrictions

AEP Texas pays dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of AEP Texas to transfer funds to Parent in the form of dividends.

All of the dividends declared by AEP Texas are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only.

AEP Texas has credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.

The Federal Power Act restriction does not limit the ability of AEP Texas to pay dividends out of retained earnings.

Corporate Borrowing Program - AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC. The amounts of outstanding borrowings from the Utility Money Pool as of March 31, 2022 and December 31, 2021 are included in Notes Payable to Associated Companies, respectively, on AEP Texas’ balance sheets. AEP Texas’ activity and corresponding authorized borrowing limits for the three months ended March 31, 2022 are described in the following table:

Maximum

Average

Borrowings

Maximum

Borrowings

Average

Borrowings from

Authorized

from the

Loans to the

from the

Loans to the

the Utility Money

Short-term

Utility

Pool as of

Borrowing

Money Pool

March 31, 2022

Limit

(in millions)

$

264.7

$

—

$

152.8

$

—

$

262.2

$

500.0

The maximum, minimum and average interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:

Maximum

Minimum

Maximum

Minimum

Average

Interest Rate

Three

for Funds

Months

Borrowed from

Loaned to

Borrowed from

Loaned to

Ended

the Utility

March 31,

Money Pool

2022

1.00

%

0.10

%

—

%

—

%

0.70

%

—

%

2021

0.40

%

0.25

%

—

%

—

%

0.31

%

—

%

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 5.

12. REVENUE FROM CONTRACTS WITH CUSTOMERS

Disaggregated Revenues from Contracts with Customers

The table below represents revenues from contracts with customers, net of respective provisions for refund, by type of revenue:


	Three Months Ended March 31,
	2022		2021
	(in millions)
Retail Revenues:
Residential Revenues	$	132.0	$	112.3
Commercial Revenues	84.5		70.1
Industrial Revenues	27.9		23.9
Other Retail Revenues	7.8		6.4
Total Retail Revenues	252.2		212.7

Wholesale Revenues:
Transmission Revenues	133.1		112.0
Total Wholesale Revenues	133.1		112.0

Other Revenues from Contracts with Customers (a)	8.6		15.0

Total Revenues from Contracts with Customers	393.9		339.7

Other Revenues:
Alternative Revenues	(1.3)		(0.7)
Other Revenues	2.0		2.0
Total Other Revenues	0.7		1.3

Total Operating Revenues	$	394.6	$	341.0

(a)Amounts include affiliated and nonaffiliated revenues.

Fixed Performance Obligations

The following table represents AEP Texas’ remaining fixed performance obligations satisfied over time as of March 31, 2022. Fixed performance obligations primarily include wholesale transmission services and electricity sales for fixed amounts of energy. The amounts shown in the table below include affiliated and nonaffiliated revenues.


2022		2023-2024		2025-2026		After 2026		Total
(in millions)
$	410.0	$	—	$	—	$	—	$	410.0

Contract Assets and Liabilities

Contract assets are recognized when AEP Texas has a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. AEP Texas did not have material contract assets as of March 31, 2022 and December 31, 2021.

When AEP Texas receives consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheets in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. AEP Texas’ contract liabilities typically arise from services provided under joint use agreements for utility poles. AEP Texas did not have material contract liabilities as of March 31, 2022 and December 31, 2021.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on AEP Texas’ balance sheets within the Customer Accounts Receivable line item. AEP Texas’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Customer Accounts Receivable were not material as of March 31, 2022 and December 31, 2021.

The amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable from Associated Companies on AEP Texas’ balance sheets were not material as of March 31, 2022 and December 31, 2021.

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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				6,662,692	2,288,032		8,950,724
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income				41,863	264,004		305,867
3	Preceding Quarter/Year to Date Changes in Fair Value
4	Total (lines 2 and 3)				41,863	264,004		305,867	46,154,457	46,460,324
5	Balance of Account 219 at End of Preceding Quarter/Year				6,620,829	2,024,028		8,644,857
6	Balance of Account 219 at Beginning of Current Year				5,299,494	1,232,018		6,531,511
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income				18,546	264,004		282,549
8	Current Quarter/Year to Date Changes in Fair Value
9	Total (lines 7 and 8)				18,546	264,004		282,549	69,583,336	69,865,885
10	Balance of Account 219 at End of Current Quarter/Year				5,280,948	968,014		6,248,962

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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)	10,533,193,066.00	10,533,193,066
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	100,542,938.00	100,542,938.00
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	1,429,962,146.00	1,429,962,146.00
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	12,063,698,150	12,063,698,150
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	625,209	625,209
11	ConstructionWorkInProgress Construction Work in Progress	588,449,264.00	588,449,264
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	1,845,431	1,845,431
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	12,654,618,054	12,654,618,054
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	2,415,381,199.00	2,415,381,199
15	UtilityPlantNet Net Utility Plant (13 less 14)	10,239,236,855	10,239,236,855
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	2,319,492,525.00	2,319,492,525.00
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	94,043,245	94,043,245
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	2,413,535,770	2,413,535,770
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	2.00	2.00
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)	2	2
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	1,845,431	1,845,431
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	2,415,381,199.00	2,415,381,199

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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	208,837,610	94,043,245
2	Steam Production Plant
3	Nuclear Production Plant
4	Hydraulic Production - Conventional
5	Hydraulic Production - Pumped Storage
6	Other Production
7	Transmission	5,986,980,858	760,356,691
8	Distribution	5,044,591,611	1,413,581,351
9	Regional Transmission and Market Operation
10	General	722,745,133	145,554,483
11	TOTAL (Total of lines 1 through 10)	11,963,155,212	2,413,535,770

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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	Texas (ERCOT)
3	(a) 17INR0035	84,922	186
4	17INR0052	14,960	186
5	18INR0058	650	186
6	19INR0022	15,215	186
7	19INR0035	84	186
8	19INR0171	243	186
9	19INR0177	1,084	186
10	20AEPSC001	926	186
11	20INR0013	665	186
12	20INR0014	621	186
13	20INR0016	974	186
14	20INR0053	9,923	186	50,000	186
15	20INR0054	63,372	186
16	20INR0070	614	186
17	20INR0086	4,014	186
18	20INR0097	5,570	186
19	20INR0128	609	186
20	20INR0129	5,972	186
21	20INR0213	1,317	186
22	20INR0232	926	186
23	20INR0249	6,799	186
24	21INR0223	2,109	186
25	21INR0253	11,858	186
26	21INR0259	404	186
27	21INR0344	8,926	186
28	21INR0346	10,990	186
29	21INR0467	1,537	186
20	Total
21	Generation Studies
39	Total
40	Grand Total

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: DescriptionOfStudyPerformed

Respondent is unable to expand on the description due to Electric Reliability Council of Texas (ERCOT) disclosure limitations when studies are in process.

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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	Under-recovery of Energy Efficiency Program Expenses - as approved by PUCT Docket (updated annually)	14,512,703	1,451,552	456/907	2,551,335	13,412,920
2	Advanced Metering Systems Existing Meter Investment of "old meters retired" and replaced by "Advanced Meters" as approved in PUCT Docket #36928	22,691,234		403	1,660,907	21,030,327
3	Advanced Metering Systems O&M expenses to be recovered over 11 years beginning in 2010 as approved in PUCT Docket #36928
4	Defer incremental expense as it relates to Covid-19	2,127,636	10,358,108	142/1823/234/254/450/451/454/921/923/935	8,885,006	3,600,739
5	Distribution Vegetation Estimate PUCT Docket #49494 - Rate Case	22,546,233	63,054	116/403/407	1,228,890	21,380,397
6	TX Line Inspection Costs	2,377,012	707,435	571	14,963	3,069,484
7	Over Refunded AEPTX ITR Rider	1,663,907				1,663,907
8	Power of Texas Holdings	4,092,318				4,092,318
9	Reserve for Catastrophe for storm recovery. Currently funded at an annual rate of $4.2M per year. Updated last on PUCT Docket #49494.	35,236,411	1,133,739	924	1,068,042	35,302,108
10	SFAS 106 Medicare Subsidy (Amortization period Jan 2013 - Dec 2024)	2,088,784		926	174,065	1,914,719
11	SFAS 109 Deferred FIT	29,859,221	622,262			30,481,483
12	SFAS 109 Deferred SIT	32,111,043	576,075	283	114,255	32,572,863
13	SFAS 158 Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans	119,089,834	1,497,994	129/190/219/228	1,239,976	119,347,852
14	Under-recovery of Advanced Metering Systems Expense as approved in PUCT Docket #36928	10,589,333	119,691	403/419	3,710,460	6,998,564
15	Under-recovery of Transmission Cost Recovery Factor - as approved by PUCT Dockey (updated semiannually)	30,633,699	13,137,210	565	6,566,730	37,204,179
16	Wholesale Distribution Substation Service - Oncor	1,452,740				1,452,740
17	Various Rate Case Expenses pending	5,047				5,047
18	Defer Mobile Gen		1,295,549	1823/570/588/589/593/931	28,230	1,267,319
19	Other Regulatory Assets	1,825,932				1,825,932
44	TOTAL	332,892,993	30,962,670		27,242,860	336,612,803

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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	SFAS 109 Deferred FIT	520,243,790	1823/190/236/254/255/282/283/409/410/411	1,734,413	3,943,491	522,452,868
2	Earnings Subject to Refund under State of Texas Restructuring Legislation Amortization @ 3.361% or approximately 30 years per Docket No. 22354	4,837,631	407	124,003		4,713,628
3	FERC System Integration Agreement (SIA) Refund to be applied as a reduction to Advanced Metering System Investment - PUCT Docket #36924 and 36928
4	Transition Regulatory Liability	3,285,956				3,285,956
5	Unrealized Gain/Loss on Forward Commitments	589,015	175	589,015	1,457,288	1,457,288
6	Deferred Income Tax Adjustment - for Oncor Acquisition	470,340	407	77,510		392,830
41	TOTAL	529,426,732		2,524,941	5,400,779	532,302,570

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting
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
11	SalesForResaleAbstract (447) Sales for Resale
12	SalesOfElectricityAbstract TOTAL Sales of Electricity
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	4,053
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(a) 2,612,430
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	5,164,297
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(b) 253,684,763
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	133,113,048
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	394,578,591
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	394,578,591
Line12, column (b) includes $ of unbilled revenues.
Line12, column (d) includes MWH relating to unbilled revenues

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: MiscellaneousServiceRevenues

Customer service revenue, including connects, reconnects, disconnects, temporary services, and other charges billed to customers. (Applies to current and previous year).

(b) Concept: OtherElectricRevenue


Account 456.0 Other Electric Revenues:
Wires Revenue (Billed and Unbilled) *	$	675,070,943
Demand Side Management Programs Revenue	(325,299)
Electric Operations - related (Affiliated)	1,121,336
Electric Operations - related (Non Affiliated)	11,591,574
Third Party Plant Operations including related overhead	226,299
Amortization of Deferred Equity Income - Transition Funding III	6,296,790
Other Misc. Revenues - Items < $250,000	63

Total	$	693,981,706

* AEP Texas sells wire services through Retail Electric Providers in Texas and therefore, records both "Billed and Unbilled Revenues" in account 456 - Other Electric Revenue.

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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)	116,175
3	SteamPowerGenerationMaintenanceExpense Steam Power Generation – Maintenance (510-515)
4	PowerProductionExpensesSteamPower Total Power Production Expenses - Steam Power	116,175
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)	125
12	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration Other Power Generation – Maintenance (551-554.1)
13	MaintenanceOfMiscellaneousOtherPowerGenerationPlant Total Power Production Expenses - Other Power	125
14	OtherPowerSuplyExpensesAbstract Other Power Supply Expenses
15	PurchasedPower (555) Purchased Power
15.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations
16	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching
17	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	147
18	OtherPowerSupplyExpense Total Other Power Supply Expenses (line 15-17)	147
19	PowerProductionExpenses Total Power Production Expenses (Total of lines 4, 7, 10, 13 and 18)	115,903
20	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
21	TransmissionExpensesOperationAbstract Transmission Operation Expenses
22	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	4,964,099
24	LoadDispatchReliability (561.1) Load Dispatch-Reliability
25	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	1,040,929
26	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	1,471
27	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	16,391
28	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	171,451
29	TransmissionServiceStudies (561.6) Transmission Service Studies
30	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
31	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services
32	StationExpensesTransmissionExpense (562) Station Expenses	251,629
32.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
33	OverheadLineExpense (563) Overhead Lines Expenses	57,788
34	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses
35	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	78,396,397
36	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	681,100
37	RentsTransmissionElectricExpense (567) Rents	1,022
38	OperationSuppliesAndExpensesTransmissionExpense (567.1) Operation Supplies and Expenses (Non-Major)
39	TransmissionOperationExpense TOTAL Transmission Operation Expenses (Lines 22 - 38)	85,579,334
40	TransmissionMaintenanceAbstract Transmission Maintenance Expenses
41	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	28,130
42	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	8,238
43	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	4,904
44	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	244,333
45	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	212,312
46	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
47	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	1,280,858
47.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
48	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	4,851,681
49	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	1,609
50	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	8,871
51	MaintenanceOfTransmissionPlant (574) Maintenance of Transmission Plant
52	TransmissionMaintenanceExpenseElectric TOTAL Transmission Maintenance Expenses (Lines 41 – 51)	6,640,936
53	TransmissionExpenses Total Transmission Expenses (Lines 39 and 52)	92,220,270
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)	14,191,480
74	DistributionMaintenanceExpenseElectric Distribution Maintenance Expenses (590-598)	11,975,638
75	DistributionExpenses Total Distribution Expenses (Lines 73 and 74)	26,167,118

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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	2,909,947
2	CustomerServiceAndInformationExpenses (907-910) Customer Service and Information Expenses	3,867,045
3	SalesExpenses (911-917) Sales Expenses	23,716
4	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
5	AdministrativeAndGeneralExpensesOperationAbstract Operation
6	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	9,926,909
7	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	744,489
8	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	2,258,206
9	OutsideServicesEmployed (923) Outside Services Employed	2,630,310
10	PropertyInsurance (924) Property Insurance	1,639,985
11	InjuriesAndDamages (925) Injuries and Damages	522,970
12	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	1,667,810
13	FranchiseRequirements (927) Franchise Requirements
14	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	185,151
15	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.
16	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	62,970
17	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	567,000
18	RentsAdministrativeAndGeneralExpense (931) Rents	316,864
19	AdministrativeAndGeneralOperationExpense TOTAL Operation (Total of lines 6 thru 18)	12,670,632
20	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
21	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	4,012,231
22	AdministrativeAndGeneralExpenses TOTAL Administrative and General Expenses (Total of lines 19 and 21)	16,682,863

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

1

(a)

0

2

Giddings, City of (1)

Various

SFP

N/A

Various

26,017

3

Sanger, City of (1)

Various

SFP

N/A

Various

26,029

4

Austin Energy (1)

Various

SFP

N/A

Various

5,351,359

5

Golden Spread Electric Cooperative, Inc (1)

Various

SFP

N/A

Various

543,166

6

Schulenberg, City of (1)

Various

SFP

N/A

Various

27,216

7

Bandera Electric Coop (1)

Various

SFP

N/A

Various

305,402

8

Goldsmith, City of (1)

Various

SFP

N/A

Various

2,300

9

Seguin, City of (1)

Various

SFP

N/A

Various

126,724

10

Bartlett, City of (1)

Various

SFP

N/A

Various

5,491

11

Goldthwaite, City of (1)

Various

SFP

N/A

Various

10,833

12

Sempra Energy Solutions, LLC (2)

Various

SFP

N/A

Various

951

675

13

Bastrop, City of (1)

Various

SFP

N/A

Various

33,383

14

Gonzales, City of (1)

Various

SFP

N/A

Various

36,425

15

Seymour, City of (1)

Various

SFP

N/A

Various

13,706

16

Bellville, City of (1)

Various

SFP

N/A

Various

26,393

17

Granbury Municipal Utilities (1)

Various

SFP

N/A

Various

43,820

18

Shiner, City of (1)

Various

SFP

N/A

Various

20,307

19

Bluebonnet Electric Coop (1)

Various

SFP

N/A

Various

1,017,288

20

Guadalupe Valley Electric Coop (1)

Various

SFP

N/A

Various

881,051

21

Smithville, City of (1)

Various

SFP

N/A

Various

20,223

22

Boerne, City of (1)

Various

SFP

N/A

Various

67,037

23

Hallettsville, City of (1)

Various

SFP

N/A

Various

18,776

24

South Texas Electric Cooperative, Inc (1)

Various

SFP

N/A

Various

2,827,019

25

Brady, City of (1)

Various

SFP

N/A

Various

29,225

26

Hamilton County Electric Coop (1)

Various

SFP

N/A

Various

83,213

27

Tenaska Power Service Company (2)

ERCOT

SPP

OS

N/A

Various

2,627

2,016

28

Brazos Electric Coop (1)

Various

SFP

N/A

Various

6,849,240

29

Hearne, City of (1)

Various

SFP

N/A

Various

22,143

30

Texas-New Mexico Power Company (1)

Various

SFP

N/A

Various

3,892,166

31

Brenham, City of (1)

Various

SFP

N/A

Various

115,519

32

Hempstead, City of (1)

Various

SFP

N/A

Various

25,096

33

Tex-La Electric Coop (1)

Various

SFP

N/A

Various

243,197

34

Bridgeport, City of (1)

Various

SFP

N/A

Various

24,310

35

Kerrville Public Utility Board (1)

Various

SFP

N/A

Various

218,277

36

TransAlta Energy Marketing (2)

Various

SFP

N/A

Various

4,255

2,992

37

Brownsville Public Utilities Board (1)

Various

SFP

N/A

Various

548,174

38

LaGrange Utilities (1)

Various

SFP

N/A

Various

31,220

39

Waelder, City of (1)

Various

SFP

N/A

Various

9,498

40

Bryan Texas Utilities (1)

Various

SFP

N/A

Various

749,650

41

Lamar County Electric Cooperative (1)

Various

SFP

N/A

Various

89,742

42

Weatherford, City of (1)

Various

SFP

N/A

Various

178,939

43

Burnet, City of (1)

Various

SFP

N/A

Various

38,966

44

Lampasas, City of (1)

Various

SFP

N/A

Various

49,837

45

Weimer, City of (1)

Various

SFP

N/A

Various

15,504

46

Canadian Wood Products Energy (2)

Various

SFP

N/A

Various

12,225

47

Lexington, City of (1)

Various

SFP

N/A

Various

5,818

48

Westar Energy Inc. (2)

ERCOT

SPP

OS

N/A

Various

14,972

27,373

49

Centerpoint Energy Houston Electric, LLC (1)

Various

SFP

N/A

Various

37,007,532

50

Llano, City of (1)

Various

SFP

N/A

Various

21,141

51

Western Farmers Electric Cooperative (1)

Various

SFP

N/A

Various

24,142

52

Central Texas Electric Coop (1)

Various

SFP

N/A

Various

295,849

53

Lockhart, City of (1)

Various

SFP

N/A

Various

53,394

54

Whitesboro, City of (1)

Various

SFP

N/A

Various

16,200

55

Coleman, City of (1)

Various

SFP

N/A

Various

17,853

56

Lubbock, City of (1)

Various

SFP

N/A

Various

858,082

57

Yoakum, City of (1)

Various

SFP

N/A

Various

40,233

58

College Station, City of (1)

Various

SFP

N/A

Various

415,044

59

Luling, City of (1)

Various

SFP

N/A

Various

26,349

60

Conoco Phillips (1)

ERCOT

SPP

OS

N/A

Various

4,329

4,062

61

MAG Energy Solutions (2)

Various

SFP

N/A

Various

16,471

16,113

62

Cuero, City of (1)

Various

SFP

N/A

Various

43,807

63

Mason, City of (1)

Various

SFP

N/A

Various

11,920

64

Denton Municipal Electric (1)

Various

SFP

N/A

Various

631,871

65

Moulton, City of (1)

Various

SFP

N/A

Various

4,786

66

Dynasty Power (2)

ERCOT

SPP

OS

N/A

Various

32,691

29,550

67

New Braunfels Utilities (1)

Various

SFP

N/A

Various

601,268

68

East Texas Electic Coop (1)

Various

SFP

N/A

Various

63,003

69

Oncor Electric Delivery (1)

Various

SFP

N/A

Various

51,108,956

70

Endure Energy LLC (2)

ERCOT

SPP

OS

N/A

Various

3,939

5,198

71

Pedernales Electric Cooperative, Inc (1)

ERCOT

SPP

OS

N/A

Various

3,195,534

72

Farmersville, City of (1)

Various

SFP

N/A

Various

13,974

73

Rainbow Energy Marketing (2)

ERCOT

SPP

OS

N/A

Various

151,291

157,927

74

Fayette Electric Cooperative (1)

Various

SFP

N/A

Various

122,693

75

Rayburn Country Electric Cooperative, Inc (1)

Various

SFP

N/A

Various

1,823,067

76

Flatonia, City of (1)

Various

SFP

N/A

Various

12,231

77

Rio Grande Electric Coop (1)

Various

SFP

N/A

Various

117,693

78

Floresville Electric Power System (1)

Various

SFP

N/A

Various

169,002

79

Robstown Utility System, City of (2)

Various

SFP

N/A

Various

42,482

80

Fredericksburg, City of (1)

Various

SFP

N/A

Various

64,875

81

San Antonio City Public Service (1)

Various

SFP

N/A

Various

9,458,505

82

Garland Power and Light (1)

Various

SFP

N/A

Various

851,729

83

San Bernard Electric Coop (1)

Various

SFP

N/A

Various

306,405

84

Georgetown, City of (1)

Various

SFP

N/A

Various

312,083

85

San Marcos, City of (1)

Various

SFP

N/A

Various

252,391

86

GEUS (1)

Various

SFP

N/A

Various

201,972

87

San Saba, City of (1)

Various

SFP

N/A

Various

19,152

35

TOTAL

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: PaymentByCompanyOrPublicAuthority

Transmission Cost of Service pursuant to Texas Substantive Rule 23.67

(2) High Voltage Direct Current Tie

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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	American Electric Power Service Corporation (1, 2, 3)	SFP					113,408	113,408
2	Austin Energy (2)	SFP					1,823,332	1,823,332
3	(a) Bandera Electric Cooperative (2)	SFP					122,043	122,043
4	Brazos Electric Cooperative (2)	SFP					2,902,604	2,902,604
5	Brownsville Public Utilities Board (2)	SFP					209,637	209,637
6	Bryan Texas Utilities (2)	SFP					785,234	785,234
7	Centerpoint Energy Houston Electric (2)	SFP					8,786,601	8,786,601
8	Cherokee County Electric Cooperative(2)	SFP					4,442	4,442
9	College Station City of (2)	SFP					84,863	84,863
10	Cross Texas Transmission (2, 4)	SFP					1,528,435	1,528,435
11	Deep East Texas Cooperative (2)	SFP					3,213	3,213
12	Denton Municipal Electric (2)	SFP					1,293,647	1,293,647
13	East Texas Electric Cooperative (2)	SFP					15,751	15,751
14	(b) Electric Transmission Tx, LLC (2)	SFP					7,207,669	7,207,669
15	Farmers Electric Coop (2)	SFP					15,206	15,206
16	Fayette Electric Cooperative (2)	SFP					3,366	3,366
17	Floresville Electric Power System (2)	SFP					9,894	9,894
18	Garland Power and Light (2)	SFP					1,395,835	1,395,835
19	GEUS (2)	SFP					72,374	72,374
20	Golden Spread Electric Cooperative (2)	SFP					54,137	54,137
21	Grayson-Collin Electric Cooperative (2)	SFP					34,906	34,906
22	Houston County Electric Cooperative (2)	SFP					30,220	30,220
23	Lamar County Electric Cooperative (2)	SFP					6,350	6,350
24	City of Lampasas (2)	SFP					408,027	408,027
25	Lone Star Transmission, LLC (2, 4)	SFP					2,086,738	2,086,738
26	Lower Colorado River Authority (LCRA) (2)	SFP					12,241,820	12,241,820
27	Lyntegar Electric Cooperative (2)	SFP					17,454	17,454
28	NRG Power Marketing, Inc (2)	SFP					4,955,037	4,955,037
29	Oncor Electric Delivery (2)	SFP					25,869,982	25,869,982
30	Rayburn Country Electric Cooperative (2)	SFP					506,995	506,995
31	Rio Grande Electric Cooperative (2)	SFP					16,542	16,542
32	San Antonio City Public Service (2)	SFP					4,736,898	4,736,898
33	San Bernard Electric Cooperative (2)	SFP					87,649	87,649
34	San Miguel Electric Cooperative (2)	SFP					31,486	31,486
35	Sharyland Utilities, LP (2, 4)	SFP					416,566	416,566
36	South Texas Electric Cooperative (2)	SFP					1,971,529	1,971,529
37	Southwest Texas Electric Cooperative (2)	SFP					1,460	1,460
38	Texas Municipal Power Agency (2)	SFP					668,798	668,798
39	Texas-New Mexico Power Company (2)	SFP					2,264,184	2,264,184
40	Transmission Cost Recovery Factor (5)	SFP					6,570,481	6,570,481
41	Trinity Valley Electric Cooperative (2)	SFP					16,453	16,453
42	Wind Energy Transmission Texas(2,4)	SFP					2,194,678	2,194,678
43	Wood County Electric Cooperative (2)	SFP					2,917	2,917
	TOTAL		0	0	0	0	78,396,397	78,396,397

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers

PAGE 332 - TCC

(1) Respondent is an affiliated company of American Electric Power Service Corporation

(2) Transmission Cost of Service pursuant to Texas Substantive Rule 23.67

(3) High Voltage Direct Current (HVDC) East Tie facilities charge

(4) Transmission service surcharge

(5) Transmission Cost Recovery Factor Deferral

(b) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers

PAGE 332 (ETT Footnote) - TCC

Electric Transmission Texas, LLC (ETT) is a joint venture of which American Electric Power is a 50% member.

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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			9,426,020		9,426,020
2	Steam Production Plant
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant
7	Transmission Plant	33,773,723				33,773,723
8	Distribution Plant	41,450,971				41,450,971
9	General Plant	5,244,396	11,322			5,255,718
10	Common Plant-Electric
11	TOTAL	80,469,090	11,322	9,426,020		89,906,432

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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
2	February
3	March
4	Total for Quarter 1
5	April
6	May
7	June
8	Total for Quarter 2
9	July			(a) 0
10	August
11	September
12	Total for Quarter 3
41	Total

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: MonthlyPeakLoad

Monthly peak information is no longer available from the Electric Reliability Council of Texas.

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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	0
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	(a) 0
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				0	0	0	0	0	0

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: MonthlyPeakLoadExcludingIsoAndRto

AEP Texas' transmission service is administered through a Regional Transmission Organization (RTO) and requested information is not available on an individual company basis.

Name of Respondent:

AEP Texas

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/26/2022

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