FERC Form

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

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

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES

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

GENERAL INFORMATION

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES

What and Where to Submit

Purpose

Who Must Submit

What and Where to Submit

When to Submit

Where to Send Comments on Public Reporting Burden.

THIS FILING IS

Item 1:

☑ An Initial (Original) Submission

☐ 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 Inc.

Year/Period of Report

End of:

2018

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 and Licensees 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).

Submit FERC Forms 1 and 3-Q electronically through the forms submission software. Retain one copy of each report for your files. Any electronic submission must be created by using the forms submission software provided free by the Commission at its web site: http://www.ferc.gov/docs-filing/forms/form-1/elec-subm-soft.asp. The software is used to submit the electronic filing to the Commission via the Internet.
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 for the year ended on which we have reported separately under date of , we have also reviewed 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. To further that effort, new selections, “Annual Report to Stockholders,” and “CPA Certification Statement” have been added to the dropdown “pick list” from which companies must choose when eFiling. Further instructions are found on the Commission’s website at http://www.ferc.gov/help/how-to.asp.
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 http://www.ferc.gov/docs-filing/forms/form-1/form-1.pdf and http://www.ferc.gov/docs-filing/forms.asp#3Q-gas .

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)).

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, submit the electronic filing using the form submission software only. 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.

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.

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 be 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 salt 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..."

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.

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

IDENTIFICATION

01 Exact Legal Name of Respondent

AEP Texas Inc.

02 Year/ Period of Report

End of:

2018

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 Riverside Plaza, Columbus, Ohio 43215-2373

05 Name of Contact Person

Kathy L. Messer

06 Title of Contact Person

Accountant

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

AEP Service Corporation, 1 Riverside Plaza, Columbus, Ohio 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)

Annual Corporate Officer Certification

The undersigned officer certifies that:

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

01 Name

Jeffrey Hoersdig

02 Title

Assistant Controller

03 Signature

04 Date Signed (Mo, Da, Yr)

04/11/2019

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 Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line No.	Title of Schedule (a)	Reference Page No. (b)	Remarks (c)
	ScheduleIdentificationAbstract Identification	1
	ScheduleListOfSchedulesAbstract List of Schedules	2
1	ScheduleGeneralInformationAbstract General Information	101
2	ScheduleControlOverRespondentAbstract Control Over Respondent	102
3	ScheduleCorporationsControlledByRespondentAbstract Corporations Controlled by Respondent	103
4	ScheduleOfficersAbstract Officers	104
5	ScheduleDirectorsAbstract Directors	105
6	ScheduleInformationOnFormulaRatesAbstract Information on Formula Rates	106
7	ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Year	108
8	ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet	110
9	ScheduleStatementOfIncomeAbstract Statement of Income for the Year	114	Page 116 - N/A
10	ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Year	118
11	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120
12	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122
13	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Other Comp Income, Comp Income, and Hedging Activities	122a
14	ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep	200
15	ScheduleNuclearFuelMaterialsAbstract Nuclear Fuel Materials	202	N/A
16	ScheduleElectricPlantInServiceAbstract Electric Plant in Service	204
17	ScheduleElectricPropertyLeasedToOthersAbstract Electric Plant Leased to Others	213	N/A
18	ScheduleElectricPlantHeldForFutureUseAbstract Electric Plant Held for Future Use	214
19	ScheduleConstructionWorkInProgressElectricAbstract Construction Work in Progress-Electric	216
20	ScheduleAccumulatedProvisionForDepreciationOfElectricUtilityPlantAbstract Accumulated Provision for Depreciation of Electric Utility Plant	219
21	ScheduleInvestmentsInSubsidiaryCompaniesAbstract Investment of Subsidiary Companies	224
22	ScheduleMaterialsAndSuppliesAbstract Materials and Supplies	227
23	ScheduleAllowanceInventoryAbstract Allowances	228
24	ScheduleExtraordinaryPropertyLossesAbstract Extraordinary Property Losses	230a	N/A
25	ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract Unrecovered Plant and Regulatory Study Costs	230b	N/A
26	ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract Transmission Service and Generation Interconnection Study Costs	231
27	ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets	232
28	ScheduleMiscellaneousDeferredDebitsAbstract Miscellaneous Deferred Debits	233
29	ScheduleAccumulatedDeferredIncomeTaxesAbstract Accumulated Deferred Income Taxes	234
30	ScheduleCapitalStockAbstract Capital Stock	250	N/A
31	ScheduleOtherPaidInCapitalAbstract Other Paid-in Capital	253
32	ScheduleCapitalStockExpenseAbstract Capital Stock Expense	254b	N/A
33	ScheduleLongTermDebtAbstract Long-Term Debt	256
34	ScheduleReconciliationOfReportedNetIncomeWithTaxableIncomeForFederalIncomeTaxesAbstract Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax	261
35	ScheduleTaxesAccruedPrepaidAndChargedDuringYearDistributionOfTaxesChargedAbstract Taxes Accrued, Prepaid and Charged During the Year	262
36	ScheduleAccumulatedDeferredInvestmentTaxCreditsAbstract Accumulated Deferred Investment Tax Credits	266
37	ScheduleOtherDeferredCreditsAbstract Other Deferred Credits	269
38	ScheduleAccumulatedDeferredIncomeTaxesAcceleratedAmortizationPropertyAbstract Accumulated Deferred Income Taxes-Accelerated Amortization Property	272	N/A
39	ScheduleAccumulatedDeferredIncomeTaxesOtherPropertyAbstract Accumulated Deferred Income Taxes-Other Property	274
40	ScheduleAccumulatedDeferredIncomeTaxesOtherAbstract Accumulated Deferred Income Taxes-Other	276
41	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278
42	ScheduleElectricOperatingRevenuesAbstract Electric Operating Revenues	300
43	ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1)	302	N/A
44	ScheduleSalesOfElectricityByRateSchedulesAbstract Sales of Electricity by Rate Schedules	304	N/A
45	ScheduleSalesForResaleAbstract Sales for Resale	310
46	ScheduleElectricOperationsAndMaintenanceExpensesAbstract Electric Operation and Maintenance Expenses	320
47	SchedulePurchasedPowerAbstract Purchased Power	326	N/A
48	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
49	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331	N/A
50	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
51	ScheduleMiscellaneousGeneralExpensesAbstract Miscellaneous General Expenses-Electric	335
52	ScheduleDepreciationDepletionAndAmortizationAbstract Depreciation and Amortization of Electric Plant (Account 403, 404, 405)	336
53	ScheduleRegulatoryCommissionExpensesAbstract Regulatory Commission Expenses	350
54	ScheduleResearchDevelopmentOrDemonstrationExpendituresAbstract Research, Development and Demonstration Activities	352
55	ScheduleDistributionOfSalariesAndWagesAbstract Distribution of Salaries and Wages	354
56	ScheduleCommonUtilityPlantAndExpensesAbstract Common Utility Plant and Expenses	356	N/A
57	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts included in ISO/RTO Settlement Statements	397	N/A
58	SchedulePurchasesSalesOfAncillaryServicesAbstract Purchase and Sale of Ancillary Services	398	N/A
59	ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load	400
60	ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load	400a	N/A
61	ScheduleElectricEnergyAccountAbstract Electric Energy Account	401a
62	ScheduleMonthlyPeakAndOutputAbstract Monthly Peaks and Output	401b
63	ScheduleSteamElectricGeneratingPlantStatisticsAbstract Steam Electric Generating Plant Statistics	402
64	ScheduleHydroelectricGeneratingPlantStatisticsAbstract Hydroelectric Generating Plant Statistics	406	N/A
65	SchedulePumpedStorageGeneratingPlantStatisticsAbstract Pumped Storage Generating Plant Statistics	408	N/A
66	ScheduleGeneratingPlantStatisticsAbstract Generating Plant Statistics Pages	410	N/A
0	ScheduleEnergyStorageOperationsLargePlantsAbstract Energy Storage Operations (Large Plants)	414
67	ScheduleTransmissionLineStatisticsAbstract Transmission Line Statistics Pages	422
68	ScheduleTransmissionLinesAddedAbstract Transmission Lines Added During Year	424
69	ScheduleSubstationsAbstract Substations	426
70	ScheduleTransactionsWithAssociatedAffiliatedCompaniesAbstract Transactions with Associated (Affiliated) Companies	429
71	FootnoteDataAbstract Footnote Data	450
	StockholdersReportsAbstract Stockholders' Reports (check appropriate box)
	Stockholders' Reports Check appropriate box: ☑ Two copies will be submitted ☐ No annual report to stockholders is prepared

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general corporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the general corporate books are kept. Jeffrey W Hoersdig, Assistant Controller 212 e. 6th Street Tulsa, Oklahoma 740119
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized. State of Texas December 31,2016 State of Incorporation: Date of Incorporation: Incorporated Under Special Law:
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased. Not Applicable (a) Name of Receiver or Trustee Holding Property of the Respondent: (b) Date Receiver took Possession of Respondent Property: (c) Authority by which the Receivership or Trusteeship was created: (d) Date when possession by receiver or trustee ceased:
4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated. AEP Texas is a public utility engaged in the purchase, sale, transmission and distribution of electricity in the State of Texas. Under the Texas electric restructuring legislation, we completed the final stage of exiting the generation business and have ceased serving retail load. AEP Texas' remaining generating capacity that is not deactivated has been transferred to an affiliated company at our cost pursuant to a 20-year agreement.
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant for your previous year's certified financial statements? (1) ☐ Yes 03/02/2017 (2) ☑ No

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the respondent at the end of the year, state name of controlling corporation or organization, manner in which control was held, and extent of control. If control was in a holding company organization, show the chain of ownership or control to the main parent company or organization. If control was held by a trustee(s), state name of trustee(s), name of beneficiary or beneficiaries for whom trust was maintained, and purpose of the trust.

In 2016, AEP Utilities, Inc. (formerly Central and South West Corporation, a registered holding company) owned 100% of the outstanding shares of common stock of both AEP Texas Central Company and AEP Texas North Company. On December 31, 2016, those companies merged into AEP Utilities, Inc., and AEP Utilities, Inc. name was changed to AEP Texas. American Electric Power Company, Inc., a registered holding company, owned 100% of AEP Utilities, Inc.'s outstanding shares of common stock during 2016 and owns 100% of AEP Texas outstanding common stock.

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

CORPORATIONS CONTROLLED BY RESPONDENT
Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests. Definitions See the Uniform System of Accounts for a definition of control. Direct control is that which is exercised without interposition of an intermediary. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line No.	NameOfCompanyControlledByRespondent Name of Company Controlled (a)	CompanyControlledByRespondentKindOfBusinessDescription Kind of Business (b)	VotingStockOwnedByRespondentPercentage Percent Voting Stock Owned (c)	FootnoteReferences Footnote Ref. (d)
1	AEP Texas North Generation Company, LLC	Non Regulated Generation	100
2	AEP Texas Central Transition Funding LLC	Financing	100
3	AEP Texas Central Transition Funding II LLC	Financing	100
4	AEP Texas Central Transition Funding III LLC	Financing	100

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

OFFICERS
Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made.
Line No.	OfficerTitle Title (a)	OfficerName Name of Officer (b)	OfficerSalary Salary for Year (c)	DateOfficerIncumbencyStarted Date Started in Period (d)	DateOfficerIncumbencyEnded Date Ended in Period (e)
1	(a) See Footnote

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: OfficerTitle

Summary Compensation Table

The following table provides summary information concerning compensation earned by our Chief Executive Officer, our Chief Financial Officer and the three other most highly compensated executive officers, to whom we refer collectively as the named executive officers.


Name and Principal Position	Year	Salary ($)(1)	Bonus ($)	Stock Awards ($)(2)	Non-Equity Incentive Plan Compensation ($)(3)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(4)	All Other Compensation ($)(5)	Total ($)
Nicholas K. Akins—
Chairman of the Board and Chief Executive Officer	2018	1,415,423	—	7,564,313	2,900,000	207,401	114,891	12,202,028
Brian X. Tierney—
Executive Vice President and Chief Financial Officer	2018	771,958	—	1,945,785	890,000	0	59,547	3,667,290
David M. Feinberg—
Executive Vice President, General Counsel and Secretary	2018	650,492	—	1,362,082	655,000	25,724	48,106	2,741,404
Lisa M. Barton—
Executive Vice President- Transmission	2018	571,189	—	1,167,470	575,000	40,845	55,264	2,409,768
Lana L. Hillebrand—
Executive Vice President- Chief Administrative Officer	2018	597,289	—	972,924	600,000	47,656	57,530	2,275,399

Amounts in the salary column are composed of executive salaries earned for the year shown, which include 261 days of pay for 2018. This is one day more than the standard 260 calendar work days and holidays in a year.

The amounts reported in this column reflect the aggregate grant date fair value calculated in accordance with FASB ASC Topic 718 of the performance units and restricted stock units (RSUs) granted under our Long-Term Incentive Plan. See Note 15 to the Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2018 for a discussion of the relevant assumptions used in calculating these amounts. The value realized for the performance units, if any, will depend on the Company’s performance during a three-year performance period. The potential payout can range from 0 percent to 200 percent of the target number of performance units, plus any dividend equivalents.

The value of the 2018 performance units will be based on two equally weighted measures: a Board approved cumulative operating earnings per share measure (Cumulative EPS) and a total shareholder return measure (Relative TSR). The grant date fair value of the 2018 performance units that are based on Cumulative EPS was computed in accordance with FASB ASC Topic 718 and was measured based on the closing price of AEP’s common stock on the date of grant. The maximum amount payable for the 2018 performance units that are based on Cumulative EPS is equal to: $5,831,240 for Mr. Akins; $1,499,965 for Mr. Tierney; $1,049,996 for Mr. Feinberg; $900,006 for Ms. Barton and $750,016 for Ms. Hillebrand. The grant date fair value of the 2018 performance units that are based on Relative TSR is calculated using a Monte-Carlo model as of the date of grant, in accordance with FASB ASC Top 718. As the performance units that are based on Relative TSR are subject to market conditions as defined under FASB ASC Topic 718, they had no maximum grant date fair values that differed from the grant date fair values presented in the table.

The performance units granted in 2018 will settle in AEP shares. Because the 2018 performance units are to be settled in AEP shares and the Relative TSR measure is a market condition, the maximum value is factored into the calculation of the grant date fair value.

The amounts shown in this column are annual incentive compensation paid for the year shown. At the outset of each year, the HR Committee sets annual incentive targets and performance criteria that are used after year-end to determine if and the extent to which executive officers may receive annual incentive award payments.

The amounts shown in this column are attributable to the increase in the actuarial values of each of the named executive officer’s combined benefits under AEP’s qualified and non-qualified defined benefit plans determined using interest rate and mortality assumptions consistent with those used in the Company’s financial statements. See Note 8 to the Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2018 for a discussion of the relevant assumptions.

(5) Amounts shown in the All Other Compensation column for 2018 include: (a) Company contributions to the Company’s Retirement Savings Plan, (b) Company contributions to the Company’s Supplemental Retirement Savings Plan and (c) perquisites. The amounts are listed in the following table:


Type	Nicholas K. Akins	Brian X. Tierney	David M. Feinberg	Lisa M. Barton	Lana L. Hillebrand
Retirement Savings Plan Match	$ 12,141	$ 12,375	$ 12,375	$ 12,375	$ 12,375
Supplemental Retirement Savings Plan Match	$ 77,625	$ 47,172	$ 23,552	$ 29,217	$ 31,244
Perquisites	$ 25,125	$ 0	$ 12,179	$ 13,672	$ 13,911
Total	$ 114,891	$ 59,547	$ 48,106	$ 55,264	$ 57,530

Perquisites provided in 2018 included: financial counseling and tax preparation services, and, for Mr. Akins, director’s accidental death insurance premium. Executive officers may also have the occasional personal use of event tickets when such tickets are not being used for business purposes, however, there is no associated incremental cost. From time to time executive officers may receive customary gifts from third parties that sponsor sporting events (subject to our policies on conflicts of interest).

Although Mr. Akins has entered into an Aircraft Time Sharing Agreement that allows him to use our corporate aircraft for personal use for a limited number of hours each year, Mr. Akins did not use our corporate aircraft for personal use during 2018. The Aircraft Time Sharing Agreement requires Mr. Akins to reimburse the Company for the cost of his personal use of corporate aircraft in accordance with limits set forth in Federal Aviation Administration regulations. The amount of such reimbursements are expected to exceed the aggregate incremental cost of such flights.

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

DIRECTORS
Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated titles of the directors who are officers of the respondent. Designate members of the Executive Committee in column (c) and the Chairman of the Executive Committee in column (d).
Line No.	NameAndTitleOfDirector Name (and Title) of Director (a)	PrincipalBusinessAddress Principal Business Address (b)	MemberOfTheExecutiveCommittee Member of the Executive Committee (c)	ChairmanOfTheExecutiveCommittee Chairman of the Executive Committee (d)
1	Nicholas K. Akins, Chairman of the Board and	Columbus, Ohio
2	Chief Executive Officer
3	Lisa M. Barton, Vice President	Columbus, Ohio
4	David M. Feinberg, Secretary	Columbus, Ohio
5	Lana L. Hillebrand, Vice President	Columbus, Ohio
6	Mark C. McCullough, Vice President	Columbus, Ohio
7	Paul Chodak III, Vice President	Columbus, Ohio
8	Brian X. Tierney, Vice President and	Columbus, Ohio
9	Chief Financial Officer
10	Charles R Patton, Vice President	Columbus, Ohio
11	The Respondent does not have an Executive Committee

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

INFORMATION ON FORMULA RATES
Does the respondent have formula rates?		☐ Yes ☑ No
Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No) accepting the rate(s) or changes in the accepted rate.
Line No.	RateScheduleTariffNumber FERC Rate Schedule or Tariff Number (a)	ProceedingDocketNumber FERC Proceeding (b)
1

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent) filings containing the inputs to the formula rate(s)?			☐ Yes ☑ No (Checked by default - Not explicitly defined)
If yes, provide a listing of such filings as contained on the Commission's eLibrary website.
Line No.	AccessionNumber Accession No. (a)	DocumentDate Document Date / Filed Date (b)	DocketNumber Docket No. (c)	DescriptionOfFiling Description (d)	RateScheduleTariffNumber Formula Rate FERC Rate Schedule Number or Tariff Number (e)
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Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

INFORMATION ON FORMULA RATES - Formula Rate Variances
If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from amounts reported in the Form 1. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the Form 1. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line No.	PageNumberOfFormulaRateVariances Page No(s). (a)	ScheduleOfFormulaRateVariances Schedule (b)	ColumnOfFormulaRateVariances Column (c)	LineNumberOfFormulaRateVariances Line No. (d)
1
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Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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 Page 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest.
(Reserved.)
If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period.
In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.

1.	Date Acquired		Period of Franchise &
	Or Extended	Community	Termination	Consideration
	Renewed on	Karnes City, Karnes	Thirty (30) year franchise
	May 22, 2018	County, Texas	renewal expiring on December 13, 2048	None
	Renewed on	City of Kenedy	Thirty (30) year franchise
	May 8, 2018	Karnes County, Texas	renewal expiring on December 13, 2048	None
	Renewed on	City of Charlotte;	Thirty (30) year franchise
	May 10, 2018	Atascosa County, Texas	renewal expiring on October 13, 2048	None
	Renewed on	City of Nordheim;	Thirty (30) year franchise
	May 29, 2018	Dewitt County, Texas	renewal expiring on December 19, 2048	None
	Renewed on	City of Eagle Lake;	Thirty (30) year franchise
	July 10, 2018	Colorado County, Texas	renewal expiring on December 13, 2048	None
	Renewed on	City of Portland;	Thirty (30) year franchise
	September 4, 2018	San Patricio, Texas	renewal expiring on November 1, 2048	None
	Renewed on	City of Munday;	Twenty-five (25) year franchise
	August 14, 2018	Knox County, Texas	renewal expiring on August 13, 2043	None
	Renewed on	City of Sinton;	Thirty (30) year franchise
	September 11, 2018	San Patricio County, Texas	renewal expiring on November 15, 2048	None
	Renewed on	City of Pleasanton;	Twenty-five (25) year franchise
	September 6, 2018	Atascosa County, Texas	renewal expiring on September 5, 2043	None
	Renewed on	City of George West;	Thirty (30) year franchise
	September 26, 2018	Live Oak County, Texas	renewal expiring on October 17, 2048	None
	Renewed on	City of Kingsville;	Thirty (30) year franchise
	November 26, 2018	Kleberg County, Texas	renewal expiring on November 22, 2048	None
	Renewed on	City of Palmhurst;	Twenty-five (25) year franchise
	November 20, 2018	Hildalgo County, Texas	renewal expiring on May 31, 2039	None
	effective
	June 1, 2014


2.	None

3.	The letter with the required journal entries for the sale of the Walker County Site land, jointly owned by SWEPCo, AEP Texas, and PSO, to third parties was filed with the FERC on May 4, 2018. AEP Texas' portion of the total $11.5 million gain on sale was $2.4 million.


4.	None

5.	None

FERC Authority (Docket No. ES18-22-000)

	$2,800,000 Letter of Credit issued by American Electric Power Company, Inc. on
	behalf of AEP Texas Central Company to benefit UFG (United Fire Group) Specialty

Insurance

FERC Authority (Docket No. ES18-22-000)

$500,000,000 Series E, Senior Unsecured Notes, 3.95% , Due June 1, 2028


7.	None

8.	None

Please refer to the Notes to Financial Statements Pages 122-123


10.	None

11.

(Reserved)

12.

Not Used

13.	Rogier, Daniel J. Elected As Vice President 12/12/2018
	Chodak, Paul Elected As Vice President 4/26/2018
	Strahler, Leigh Anne Elected As Vice President - Regulatory & Finance 3/10/2018
	Sherwood, Julie A. Elected As Vice President 1/1/2018
	Dieck, Lonni L. Resigned As Vice President & Treasurer 12/31/2018
	Ford, Ronald K. Resigned As Vice President - Regulatory & Finance 5/2/2018
	Pyle, Mark A. Resigned As Vice President-Tax 1/28/2018

14.

Proprietary capital ratio exceeds 30%

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlant Utility Plant (101-106, 114)	200	8,793,403,251	7,570,778,951
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	836,188,274	835,749,544
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		9,629,591,525	8,406,528,495
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	2,284,845,318	2,183,018,567
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		7,344,746,207	6,223,509,928
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)		7,344,746,207	6,223,509,928
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		2,666,998	2,691,746
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		1,006,974	763,475
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	25,436,632	25,491,242
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228
24	OtherInvestments Other Investments (124)		14,138,942	13,680,506
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)		39,138,710	58,772,953
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)		80,374,308	99,872,972
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		2,974,040	1,949,829
36	SpecialDeposits Special Deposits (132-134)		299,186	129,786
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)		108,272,661	102,745,715
41	OtherAccountsReceivable Other Accounts Receivable (143)		1,549,179	1,133,850
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		1,287,279	652,303
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)			103,538,150
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		15,187,240	12,262,859
45	FuelStock Fuel Stock (151)	227	8,667,188	3,438,722
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227	158,854	142,942
47	Residuals Residuals (Elec) and Extracted Products (153)	227
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	52,796,335	52,044,738
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)		3,378,960	2,568,785
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)		1,259,695	2,793,873
60	RentsReceivable Rents Receivable (172)		2,605,149	2,502,446
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		70,407,414	75,791,425
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		4,685
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)			511,816
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)		266,363,937	361,002,633
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		16,506,855	14,443,247
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	482,144,146	434,742,374
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		31,149	328,895
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)		244	244
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	2,467,651	1,401,598
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)		6,023,917	7,577,150
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	207,916,285	220,717,834
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		715,090,247	679,211,342
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		8,406,574,699	7,363,596,875

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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
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	1,257,947,794	1,057,947,794
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	1,329,777,746	1,116,620,111
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	7,964,752	8,019,361
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)	15,147,764	12,649,577
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		2,580,521,063	2,169,916,224
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	3,114,186,630	2,644,194,500
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		7,619,198	6,620,858
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		3,106,567,432	2,637,573,642
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		23,933,909	18,527,867
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		254,933	330,091
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		7,688,887	11,976,525
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)		31,424,242	976,500
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)		27,348,667	26,136,594
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		90,650,638	57,947,577
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)
38	AccountsPayable Accounts Payable (232)		276,429,790	379,322,375
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		216,042,230
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		65,558,994	66,276,093
41	CustomerDeposits Customer Deposits (235)		20,000	20,000
42	TaxesAccrued Taxes Accrued (236)	262	29,585,069	35,376,376
43	InterestAccrued Interest Accrued (237)		26,195,290	26,364,417
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		297,449	2,318
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		46,087,677	43,275,537
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		4,547,665	4,223,151
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		179,158
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)		664,943,322	554,855,631
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	10,843,500	12,305,570
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	143,644,391	130,160,510
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	688,165,365	704,857,783
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)		844,676,506	760,871,350
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		276,562,482	335,108,588
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		1,963,892,244	1,943,303,801
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		8,406,574,699	7,363,596,875

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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 columnin 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 purches, and a summary of the adjustments made to balance sheet, income, and expense accounts. If any notes appearing in the report to stokholders 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	1,322,396,025	1,263,517,167			1,322,396,025	1,263,517,167
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	506,888,993	466,706,300			506,888,993	466,706,300
5	MaintenanceExpense Maintenance Expenses (402)	320	89,429,855	75,905,562			89,429,855	75,905,562
6	DepreciationExpense Depreciation Expense (403)	336	235,272,512	200,664,254			235,272,512	200,664,254
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336	2,878,158	84,710			2,878,158	84,710
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	24,054,567	20,553,455			24,054,567	20,553,455
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)		9,441,783	9,459,990			9,441,783	9,459,990
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		4,745,763	4,745,763			4,745,763	4,745,763
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	132,490,639	121,313,648			132,490,639	121,313,648
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	34,742,843	96,369,830			34,742,843	96,369,830
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	1,766,143	716,706			1,766,143	716,706
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	1,976,990,602	410,290,062			1,976,990,602	410,290,062
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	1,988,530,935	326,560,157			1,988,530,935	326,560,157
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	1,462,070	1,570,091			1,462,070	1,570,091
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)		186,360	2,576,896			186,360	2,576,896
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)		1,201,315	1,150,114			1,201,315	1,150,114
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		1,020,605,002	874,852,644			1,020,605,002	874,852,644
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		301,791,023	388,664,523			301,791,023	388,664,523
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)			45,393
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		167,386	327,831
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	54,609	127,887
37	InterestAndDividendIncome Interest and Dividend Income (419)		1,211,611	1,944,951
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		20,024,063	6,839,780
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		2,352,490	1,059,897
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		578,516
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		21,856,235	9,999,179
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)			2,880
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		880,284	552,067
46	LifeInsurance Life Insurance (426.2)		247,432	625,362
47	Penalties Penalties (426.3)		827,043	180,021
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		1,195,357	1,012,105
49	OtherDeductions Other Deductions (426.5)		550,949	523,868
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		3,206,201	1,645,579
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	25	1,385
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	2,298,164	11,083,336
54	IncomeTaxesOther Income Taxes-Other (409.2)	262
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	15,300,833	4,364,508
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	20,301,781	25,104,871
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)		2,702,759	9,655,642
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		21,352,793	18,009,242
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		121,490,766	96,437,519
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		2,975,652	2,071,544
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		1,553,233	1,085,571
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)		2,889,771	1,852,951
68	OtherInterestExpense Other Interest Expense (431)		1,281,964	924,493
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		18,392,972	6,839,389
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		111,798,414	95,532,689
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		211,345,402	311,141,076
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)		211,345,402	311,141,076

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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 122-123.
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		1,116,620,111	805,351,148
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
4.1	AdjustmentsToRetainedEarningsCredit Implementation of ASU 2018-02 - Remeasurement of AOCI		1,757,624
4.2	AdjustmentsToRetainedEarningsCredit
4.3	AdjustmentsToRetainedEarningsCredit
4.4	AdjustmentsToRetainedEarningsCredit
4.5	AdjustmentsToRetainedEarningsCredit
4.6	AdjustmentsToRetainedEarningsCredit
4.7	AdjustmentsToRetainedEarningsCredit
4.8	AdjustmentsToRetainedEarningsCredit
4.9	AdjustmentsToRetainedEarningsCredit
4.10	AdjustmentsToRetainedEarningsCredit
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)		1,757,624
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
10.1	AdjustmentsToRetainedEarningsDebit
10.2	AdjustmentsToRetainedEarningsDebit
10.3	AdjustmentsToRetainedEarningsDebit
10.4	AdjustmentsToRetainedEarningsDebit
10.5	AdjustmentsToRetainedEarningsDebit
10.6	AdjustmentsToRetainedEarningsDebit
10.7	AdjustmentsToRetainedEarningsDebit
10.8	AdjustmentsToRetainedEarningsDebit
10.9	AdjustmentsToRetainedEarningsDebit
10.10	AdjustmentsToRetainedEarningsDebit
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		211,400,011	311,268,963
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
17.1	AppropriationsOfRetainedEarnings
17.2	AppropriationsOfRetainedEarnings
17.3	AppropriationsOfRetainedEarnings
17.4	AppropriationsOfRetainedEarnings
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)
23	DividendsDeclaredPreferredStockAbstract Dividends Declared-Preferred Stock (Account 437)
23.1	DividendsDeclaredPreferredStock
23.2	DividendsDeclaredPreferredStock
23.3	DividendsDeclaredPreferredStock
23.4	DividendsDeclaredPreferredStock
23.5	DividendsDeclaredPreferredStock
29	DividendsDeclaredPreferredStock TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30	DividendsDeclaredCommonStockAbstract Dividends Declared-Common Stock (Account 438)
30.1	DividendsDeclaredCommonStock
30.2	DividendsDeclaredCommonStock
30.3	DividendsDeclaredCommonStock
30.4	DividendsDeclaredCommonStock
30.5	DividendsDeclaredCommonStock
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)		1,329,777,746	1,116,620,111
	AppropriatedRetainedEarningsAbstract APPROPRIATED RETAINED EARNINGS (Account 215)
.1	AppropriatedRetainedEarnings
.2	AppropriatedRetainedEarnings
.3	AppropriatedRetainedEarnings
.4	AppropriatedRetainedEarnings
.5	AppropriatedRetainedEarnings
.6	AppropriatedRetainedEarnings
.7	AppropriatedRetainedEarnings
.8	AppropriatedRetainedEarnings
.9	AppropriatedRetainedEarnings
.10	AppropriatedRetainedEarnings
.11	AppropriatedRetainedEarnings
.12	AppropriatedRetainedEarnings
.13	AppropriatedRetainedEarnings
.14	AppropriatedRetainedEarnings
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)		1,329,777,746	1,116,620,111
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)		8,019,361	8,147,248
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)		54,609	127,887
51	DividendsReceived (Less) Dividends Received (Debit)
52	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
52.1	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)		7,964,752	8,019,361

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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)	211,345,402	311,141,076
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	262,205,237	221,132,999
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Regulatory Debits and Credits (Net)	4,696,020	4,714,227
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	16,541,281	62,989,542
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	1,462,070	1,570,091
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	(b) 6,795,311	(j) 13,367,621
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	(c) 5,995,975	(k) 3,199,496
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	27,101,128	5,721,578
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	(d) 15,771,388	(l) 100,952,044
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	511,816	103,767
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	20,024,063	6,839,780
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies	54,609	127,887
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription (a) Other (provide details in footnote):	25,793,558	88,427,178
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	409,891,794	397,973,858
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)	(e) 1,448,850,545	(m) 997,704,463
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant		(n) 17,832
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	(f) 20,024,063	(o) 6,839,780
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Acquired Assets	(g) 1,420,461	826,768
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	(h) 1,430,246,943	(p) 991,709,283
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)	1,677,661	4,419,119
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 Contribution in Aid of Construction Proceeds	34,910,192	15,356,218
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription (Increase) Decrease in Other Special Deposits	1,357	42,686
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Notes Receivable from Associated Companies	103,538,150	103,538,150
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	1,290,122,297	1,075,514,782
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	500,000,000	760,000,000
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
64.1	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Long Term Issuance Costs	5,975,838	10,385,380
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceeds on Capital Leaseback	1,196,192	182,755
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Notes Payable to Associated Companies	216,042,230
67.3	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Capital Contributions from Parent	200,000,000	200,000,000
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	911,262,584	949,431,865
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	(i) 30,007,870	(q) 100,897,525
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Notes Payable to Assciated Companies		(r) 169,504,561
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)	881,254,714	679,029,779
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)	1,024,211	1,488,855
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	2,049,829	560,974
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	3,074,040	2,049,829

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription

		2018		2017
		Cash Flow		Cash Flow
Other Operating Activities - Continued:		Incr / (Decr)		Incr / (Decr)

Utility Plant, Net	$	(44,950,439)	$	(55,747,712)
Property and Investments, Net		(254,696)		(1,629,335)
Special Funds		0		0
Margin Deposits		(168,043)		144,069
Mark-to-Market of Risk Management Contracts		690,974		(288,760)
Prepayments		(8,037,980)		(7,243,830)
Accrued Utility Revenues, Net		5,384,012		(10,956,866)
Miscellaneous Current and Accr Assets		229,260		0
Unamortized Debt Expense		2,261,673		1,168,137
Other Deferred Debits, Net		3,118,938		53,707,676
Proprietary Capital, Net		0		(49,051,069)
Other Comprehensive Income, Net		89,115		868,873
Unamortized Discount/Premium on Long-Term Debt		651,661		491,005
Accumulated Provisions - Misc		25,976,697		2,976,921
Current and Accrued Liabilities, Net		(17,618,638)		(4,473,008)
Other Deferred Credits, Net		58,421,024		(18,393,279)
Total	$	25,793,558	$	(88,427,178)

(b) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities

Original value: -6795311

Original value: -5995975

(d) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities

Original value: -15771388

(e) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities

Original value: -1448850545

(f) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities

Original value: -20024063

(g) Concept: OtherConstructionAndAcquisitionOfPlantInvestmentActivities

Original value: -1420461

(h) Concept: CashOutflowsForPlant

Original value: -1430246943

(i) Concept: PaymentsForRetirementOfLongTermDebtFinancingActivities

Original value: -30007870

(j) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities

Original value: -13367621

(k) Concept: NetIncreaseDecreaseInInventoryOperatingActivities

Original value: 3199496

(l) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities

Original value: -100952044

(m) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities

Original value: -997704463

(n) Concept: GrossAdditionsToNonutilityPlantInvestingActivities

Original value: -17832

(o) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities

Original value: -6839780

(p) Concept: CashOutflowsForPlant

Original value: -991709283

(q) Concept: PaymentsForRetirementOfLongTermDebtFinancingActivities

Original value: -100897525

(r) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities

Original value: -169504561

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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.	Organization and Summary of Significant Accounting Policies
2.	New Accounting Pronouncements
3.	Comprehensive Income
4.	Rate Matters
5.	Effects of Regulation
6.	Commitments, Guarantees and Contingencies
7.	Benefit Plans
8.	Business Segments
9.	Derivatives and Hedging
10.	Fair Value Measurements
11.	Income Taxes
12.	Leases
13.	Financing Activities
14.	Related Party Transactions
15.	Property, Plant and Equipment
16.	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 subsidiaries and 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.
AEP Utilities		AEP Utilities, Inc., a former subsidiary of AEP and holding company for TCC, TNC and CSW Energy, Inc. Effective December 31, 2016, TCC and TNC were merged into AEP Utilities, Inc. Subsequently following this merger, the assets and liabilities of CSW Energy, Inc. were transferred to a competitive affiliate company and AEP Utilities, Inc. was renamed AEP Texas Inc.
AEPEP		AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in the deregulated Ohio and Texas markets.
AEPSC		American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC		Allowance for Funds Used During Construction.
AOCI		Accumulated Other Comprehensive Income.
ARAM		Average Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for ratemaking purposes.
ARO		Asset Retirement Obligations.
ASU		Accounting Standards Update.
CWIP		Construction Work in Progress.
EIS		Energy Insurance Services, Inc., a nonaffiliated captive insurance company.
ERCOT		Electric Reliability Council of Texas regional transmission organization.
ETT		Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Excess ADIT		Excess accumulated deferred income taxes.
FASB		Financial Accounting Standards Board.
Federal EPA		United States Environmental Protection Agency.
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.
GAAP		Accounting Principles Generally Accepted in the United States of America.
IRS		Internal Revenue Service.
MTM		Mark-to-Market.
MW		Megawatt.
OATT		Open Access Transmission Tariff.
Oklaunion Power Station		A single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant is jointly owned by AEP Texas, PSO and certain nonaffiliated entities.
OPEB		Other Postretirement Benefits.
OTC		Over the counter.
Parent		American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PPA		Purchase Power and Sale Agreement.
PSO		Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCT		Public Utility Commission of Texas.
REP		Texas Retail Electric Provider.
Risk Management Contracts		Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
SEC		U.S. Securities and Exchange Commission.
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.
TCC		Formerly AEP Texas Central Company, now a division of AEP Texas.
Texas Restructuring Legislation		Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC		Formerly AEP Texas North Company, now a division of AEP Texas.
Utility Money Pool		Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

AEP Texas was formed by the merger of TCC and TNC into AEP Utilities, Inc. on December 31, 2016. The merging parties retained their respective rate structures. Following the merger, AEP Utilities, Inc. changed its name to AEP Texas Inc.

AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,050,000 retail customers through REPs in west, central and southern Texas. Among the principal industries served by AEP Texas are petroleum and coal products manufacturing, chemical manufacturing, oil and gas extraction, pipeline transportation and primary metal manufacturing. The territory served by AEP Texas also includes several military installations and correctional facilities. AEP Texas is a member of ERCOT. Under Texas Restructuring Legislation, AEP Texas’ utility predecessors, TCC and TNC, exited the generation business and ceased serving retail load. However, AEP Texas continues as part owner in the Oklaunion Power Station operated by PSO, which management announced plans to close by October 2020 pending necessary approvals.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

AEP Texas’ rates are regulated by the FERC and PUCT. The FERC also regulates AEP Texas’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The PUCT also regulates certain intercompany transactions under various orders and affiliate statutes. Both the FERC and PUCT are permitted to review and audit the relevant books and records of companies within a public utility holding company system.

The PUCT regulates all of the retail distribution operations and rates of AEP Texas’ retail public utility subsidiaries on a cost basis.

The FERC also regulates AEP Texas’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the PUCT.

Basis of Accounting

AEP Texas’ accounting is subject to the requirements of the PUCT and the FERC. The financial statements have been prepared in accordance with the Uniform System of Accounts prescribed by the FERC. The principal differences from GAAP include:

·	Accounting for subsidiaries on an equity basis.
·	The requirement to report deferred tax assets and liabilities separately rather than as a single amount.
·	The classification of accrued taxes as a single amount rather than as assets and liabilities.
·	The exclusion of current maturities of long-term debt from current liabilities.
·	The classification of accrued non-ARO asset removal costs as accumulated depreciation rather than regulatory liabilities.
·	The classification of capital lease payments as operating activities instead of financing activities.
·	The classification of gains/losses from disposition of allowances as utility operating expenses rather than as operating revenues.
·	The classification of tax assets related to the accounting guidance for “Uncertainty in Income Taxes” as a reduction to current liabilities rather than a tax benefit.
·	The classification of noncurrent tax liabilities related to the accounting guidance for “Uncertainty in Income Taxes” as a current liability rather than a noncurrent liability.
·	The classification of an accrued provision for potential refund as other noncurrent liability rather than a current liability.
·	The classification of regulatory assets and liabilities related to the accounting guidance for “Accounting for Income Taxes” as separate assets and liabilities rather than as a single amount.
·	The presentation of capital leased assets and their associated accumulated amortization as a single amount instead of as separate amounts.
·	The classification of certain nonoperating revenues as miscellaneous nonoperating income instead of as operating revenue.
·	The classification of certain nonoperating expenses as miscellaneous nonoperating expense instead of as operating expense.
·	The separate classification of income tax expense for operating and nonoperating activities instead of as a single income tax expense.
·	The classification of interest receivable and interest accrued related to federal income tax and state income tax balances as separate current assets and current liabilities rather than as a single net amount.
·	The classification of unamortized loss on reacquired debt in deferred debits rather than in regulatory assets.
·	The classification of accumulated deferred investment tax credits in deferred credits rather than in regulatory liabilities and deferred investment tax credits.
·	The accounting for AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC as nonaffiliated companies rather than consolidating the entities in accordance with the accounting guidance for "Variable Interest Entities."
·	The classification of deferred equity income in other deferred credits rather than in other non-current assets as securitized transition assets.
·	The classification of amortization of deferred equity in operating revenues rather than in depreciation and amortization.
·	The classification of certain other assets and liabilities as current instead of noncurrent.
·	The classification of certain other assets and liabilities as noncurrent instead of current.
·	The classification of debt issuance costs as noncurrent assets instead of noncurrent liabilities.
·	The classification of rents receivable as rents receivable instead of customer accounts receivable.
·	The classification of Non-Service Cost Components of Net Periodic Benefit Cost as Operating Expense instead of Other Income (Expense).

Accounting for the Effects of Cost-Based Regulation

AEP Texas’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.

Use of Estimates

The preparation of these financial statements requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.

Cash and Cash Equivalents

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

Supplementary Information

2018

2017

For the Years Ended December 31,

(in millions)

Cash was Paid (Received) for:

	Interest (Net of Capitalized Amounts)	$	106.9		$	86.1
	Income Taxes (Net of Refunds)		7.9			(28.1	)

Noncash Acquisitions Under Capital Leases	10.6	8.2
As of December 31,
Construction Expenditures Included in Current and Accrued Liabilities	243.1	325.7

Special Deposits

Special Deposits include funds held by trustees primarily for margin deposits for risk management activities.

Inventory

Fossil fuel and materials and supplies inventories are carried at average cost.

Accounts Receivable

Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities.

Revenue is recognized over time as the performance obligations of delivering energy to customers are satisfied. To the extent that deliveries have occurred but a bill has not been issued, AEP Texas accrues and recognizes, as Accrued Utility Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

Allowance for Uncollectible Accounts

For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.

Concentrations of Credit Risk and Significant Customers

AEP Texas had significant transactions with REPs which on a combined basis account for the following percentages of Operating Revenues for the years ended December 31 and Customer Accounts Receivable as of December 31:

Significant Customers of AEP Texas:
Centrica, Just Energy, TXU Energy and Reliant Energy		2018 (a)		2017

Percentage of Operating Revenues		54	%		66	%
Percentage of Customer Accounts Receivable		36	%		50	%

Just Energy did not meet the Operating Revenue threshold of 10% in order to be considered a significant customer.

AEP Texas monitors credit levels and the financial condition of its customers on a continuous basis to minimize credit risk. The PUCT allows recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying financial statements.

Property, Plant and Equipment

Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are charged to accumulated depreciation. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses.

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not probable, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Investment in Subsidiary Company

AEP Texas has a wholly-owned subsidiary, AEP Texas North Generation Company, LLC. AEP Texas transferred all of its mothballed generation assets and related liabilities to this subsidiary, substantially completing the business separation requirement of the Texas Restructuring Legislation.

AEP Texas also has three wholly-owned subsidiaries, AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, that are engaged in financing activities associated with AEP Texas’s securitized transition assets. Investments in the net assets of AEP Texas’s three wholly-owned subsidiaries are carried at cost plus equity in their undistributed earnings since creation.

Allowance for Funds Used During Construction

AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant.

Valuation of Nonderivative Financial Instruments

The book values of Cash, Special Deposits, Working Fund, Notes Receivable from Associated Companies, Notes Payable to Associated Companies, accounts receivable and accounts payable approximate fair value because of the short-term maturity of these instruments.

Fair Value Measurements of Assets and Liabilities

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 contracts 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.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts.

Assets in the benefits trusts are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Investments classified as Other are valued using Net Asset Value as a practical expedient. Items classified as Other are primarily cash equivalent funds, common collective trusts, commingled funds, structured products, private equity, real estate, infrastructure and alternative credit investments. These investments do not have a readily determinable fair value or they contain redemption restrictions which may include the right to suspend redemptions under certain circumstances. Redemption restrictions may also prevent certain investments from being redeemed at the reporting date for the underlying value.

Revenue Recognition

Regulatory Accounting

AEP Texas’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses or alternative revenues recognized in accordance with the guidance for “Regulated Operations”) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching revenue with its passage to customers in cost-based regulated rates.

When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is derecognized as a charge against income.

Retail and Wholesale Supply and Delivery of Electricity

AEP Texas recognizes revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. AEP Texas recognizes such revenues on the statements of income as the performance obligations of delivering energy to customers are satisfied. Recognized revenues include both billed and unbilled amounts.

Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. Revenues initially recognized per the annual rate filing are compared to actual costs, resulting in the subsequent recognition of an over or under recovered amount, with interest, that is refunded or recovered, respectively, in a future year’s rates. These annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations”, and are recognized by AEP Texas in the second quarter following the filing of annual FERC reports. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable from Associated Companies or Accounts Payable to Associated Companies on the balance sheets. Any portion of the true-ups applicable to third parties is recorded as regulatory assets or regulatory liabilities on the balance sheets. See Note 16 - Revenue from Contracts with Customers for additional information related to retail and wholesale revenues.

Power Purchase and Sale Agreement

AEP Texas recognizes revenue from an affiliate, AEPEP, for a 20-year PPA. AEP Texas recognizes revenues for the fuel, operations and maintenance and all other taxes on a billed basis. Revenue is recognized for the capacity and depreciation billed to AEPEP on a straight-line basis over the term of the PPA as these amounts represent the minimum amount due.

Maintenance

AEP Texas expenses maintenance costs as incurred. If it becomes probable that AEP Texas will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with its recovery in cost-based regulated revenues.

Income Taxes and Investment Tax Credits (ITC)

AEP Texas uses the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. AEP Texas revalued deferred tax assets and liabilities at the new federal corporate income tax rate of 21% in December 2017. See Note 11 - Income Taxes for additional information related to Tax Reform.

When the flow-through method of accounting for temporary differences is required by a regulator to be reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.

AEP Texas applies the deferral methodology for the recognition of ITC. Deferred ITC is amortized to income tax expense over the life of the asset that generated the credit. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized.

AEP Texas accounts for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” AEP Texas classifies interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classifies penalties as Penalties on the statements of income.

Excise Taxes

As an agent for some state and local governments, AEP Texas collects from customers certain excise taxes levied by those state or local governments on customers. AEP Texas does not record these taxes as revenue or expense.

Debt

Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates.

Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations.

Pension and OPEB Plans

AEP Texas participates in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all of 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. AEP Texas is allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. See Note 7 - Benefit Plans for additional information including significant accounting policies associated with the plans.

Investments Held in Trust for Future Liabilities

AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance.

Benefit Plans

All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan.

The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include:

Maintaining a long-term investment horizon.
Diversifying assets to help control volatility of returns at acceptable levels.
Managing fees, transaction costs and tax liabilities to maximize investment earnings.
Using active management of investments where appropriate risk/return opportunities exist.
Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks.
Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.

The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows:

Pension Plan Assets

Target

Equity	25	%
Fixed Income	59	%
Other Investments	15	%
Cash and Cash Equivalents	1	%


OPEB Plans Assets		Target

Equity	49	%
Fixed Income	49	%
Cash and Cash Equivalents	2	%

The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law.

For equity investments, the concentration limits are as follows:

No security in excess of 5% of all equities.
Cash equivalents must be less than 10% of an investment manager’s equity portfolio.
No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio.
No investment in excess of 5% of an outstanding class of any company.
No securities may be bought or sold on margin or other use of leverage.

For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices.

A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and opportunistic classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities.

A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments.

AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is to provide modest incremental income with a limited increase in risk. As of December 31, 2018 and 2017, the fair value of securities on loan as part of the program was $241 million and $492 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2018 and 2017.

Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities.

Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.

Comprehensive Income (Loss)

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners.

Subsequent Events

Management has evaluated the impact of events occurring after December 31, 2018 through February 21, 2019, the date that AEP Texas’ Form 10-K was issued, and has updated such evaluation for disclosure purposes through April 11, 2019. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.

2. NEW ACCOUNTING PRONOUNCEMENTS

During FASB’s standard-setting process and upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to AEP Texas’ business. The following pronouncements will impact the financial statements.

ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09)

In May 2014, the FASB issued ASU 2014-09 changing the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract with a customer, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

Management adopted ASU 2014-09 effective January 1, 2018. The adoption of ASU 2014-09 did not have a material impact on results of operations, financial position or cash flows. In that regard, the application of the new standard did not cause any significant differences in any individual financial statement line items had those line items been presented in accordance with the guidance that was in effect prior to the adoption of the new standard. Further, given the lack of material impact to the financial statements, the adoption of the new standard did not give rise to any material changes in AEP Texas’ previously established accounting policies for revenue. See Note 16 - Revenue from Contracts with Customers for additional disclosures required by the new standard.

ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01)

In January 2016, the FASB issued ASU 2016-01 revising the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. For equity investments that do not have a readily determinable fair value, entities are permitted to elect a practicality exception and measure the investment at cost, less impairment, plus or minus observable price changes. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets.

Management adopted ASU 2016-01 effective January 1, 2018, by means of a cumulative-effect adjustment to the balance sheet. The adoption of ASU 2016-01 resulted in no impact to the results of operations, financial position or cash flows.

ASU 2016-02 “Accounting for Leases” (ASU 2016-02)

In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard.

New leasing standard implementation activities included the identification of the lease population within the AEP System as well as the sampling of representative lease contracts to analyze accounting treatment under the new accounting guidance. Based upon the completed assessments, management also prepared a gap analysis to outline new disclosure compliance requirements.

Management adopted ASU 2016-02 effective January 1, 2019 by means of a cumulative-effect adjustment to the balance sheet. Management elected the following practical expedients upon adoption:

Practical Expedient		Description
Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package)		Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases.
Lease and Non-lease Components (elect by class of underlying asset)		Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component.
Short-term Lease (elect by class of underlying asset)		Elect as an accounting policy to not apply the recognition requirements to short-term leases.
Existing and expired land easements not previously accounted for as leases		Elect optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840.
Cumulative-effect adjustment in the period of adoption		Elect the optional transition practical expedient to adopt the new lease requirements through a cumulative-effect adjustment on the balance sheet in the period of adoption.

Management concluded that the result of adoption would not materially change the volume of contracts that qualify as leases going forward. The adoption of the new standard did not materially impact results of operations or cash flows, but did have a material impact on the balance sheets. An impact of $80 million to AEP Texas’ balance sheet has been estimated for the first quarter of 2019.

ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13)

In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 and related implementation guidance effective January 1, 2020.

ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07)

In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented on the statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component is eligible for capitalization as applicable following labor. Management adopted ASU 2017-07 effective January 1, 2018

ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12)

In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives of the new standard are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and to reduce the complexity of applying hedge accounting. Among other things, ASU 2017-12: (a) expands the types of transactions eligible for hedge accounting, (b) eliminates the separate measurement and presentation of hedge ineffectiveness, (c) simplifies the requirements for assessments of hedge effectiveness, (d) provides companies more time to finalize hedge documentation and (e) enhances presentation and disclosure requirements.

Management early adopted ASU 2017-12 in the second quarter of 2018, effective January 1, 2018. The adoption of ASU 2017-12 resulted in no impact to results of operations, financial position or cash flows. The adoption of the new standard did not give rise to any material changes to AEP Texas’ previously established accounting policies for derivatives and hedging.

ASU 2018-02 “Reclassification of Certain Tax Effects from AOCI” (ASU 2018-02)

In February 2018, the FASB issued ASU 2018-02 allowing a reclassification from AOCI to Retained Earnings for stranded tax effects resulting from Tax Reform. The accounting guidance for “Income Taxes” requires deferred tax assets and liabilities to be adjusted for the effect of a change in tax law or rates with the effect included in income from continuing operations in the reporting period that includes the enactment date of the tax change. This guidance is applicable for the tax effects of items in AOCI that were originally recognized in Other Comprehensive Income. As a result and absent the new guidance in this ASU, the tax effects of items within AOCI would not reflect the newly enacted corporate tax rate.

Management adopted ASU 2018-02 effective January 1, 2018, electing to reclassify the effects of the change in the federal corporate tax rate due to Tax Reform from AOCI to Retained Earnings. The portion of the one-time reclassification to Retained Earnings was recorded to FERC Account 439, Adjustments to Retained Earnings. A request was made in November 2018 for use of Account 439 and in January 2019 the FERC approved the request. The adoption of the ASU and the use of Account 439 had an insignificant effect on the Company’s rates charged to customers. Additionally, a portion of the reclassification was recorded to Other Regulatory Liabilities to adjust the tax effects of certain interest rate hedges that were previously deferred as a part of the accounting for Tax Reform. There were no other effects from Tax Reform that impacted AOCI. Management applied the new guidance at the beginning of the period of adoption. The adoption of the new standard did not have a material impact on the statement of financial position and did not impact results of operations or cash flows.

ASU 2018-14 “Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans” (ASU 2018-14)

In August 2018, the FASB issued ASU 2018-14 modifying the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendments remove disclosures that no longer are considered cost beneficial, clarify the specific requirements of disclosures and add disclosure requirements identified as relevant.

Management early adopted ASU 2018-14 for the 2018 Annual Report and applied the new standard retrospectively for all periods presented. As a result of adoption, AEP Texas’ disclosures were updated as follows:

Amended the disclosure to remove the amounts in AOCI expected to be recognized as components of net periodic benefit cost over the next fiscal year.
Amended the disclosure to remove the effects of a one-percentage-point change in assumed health care cost trend rates on the (a) aggregate of the service and interest cost components of net periodic benefit costs and (b) benefit obligation for postretirement health care benefits.
Amended the disclosure to include the weighted-average interest crediting rates for cash balance plans and other plans with promised interest crediting rates.
Amended the disclosure to include an explanation of the reasons for significant gains and losses related to changes in the benefit obligation for the period.

See Note 7 - Benefit Plans for updates to the disclosures required by the new standard.

ASU 2018-15 “Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract” (ASU 2018-15)

In August 2018, the FASB issued ASU 2018-15 aligning the requirements for capitalizing implementation costs incurred in a cloud computing arrangement (hosting arrangement) that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The new standard requires an entity (customer) in a hosting arrangement that is a service contract to follow the accounting guidance for “Internal-Use Software” to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. To eliminate diversity in practice, the new standard changes the presentation of implementation costs for cloud service arrangements that are service contracts without the purchase of a license. Implementation costs for cloud service contracts will be presented on the balance sheets in the same manner as a prepayment. AEP Texas currently presents implementation costs in utility plant on the balance sheets. Under the new standard, amortization of capitalized implementation costs of a hosting arrangement will be recorded in Operation Expenses and Maintenance Expenses over the term of the cloud service arrangement, rather than Depreciation Expense on the statements of income. Payments for capitalized implementation costs in the statement of cash flows will be classified in the same manner as payments made for fees associated with the hosting element.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. Management is analyzing the impact of this new standard and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows. Management plans to adopt ASU 2018-15 prospectively, effective January 1, 2020.

3. COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2018 and 2017. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional details.

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Year Ended December 31, 2018

Pension and OPEB

	Amortization	Changes in
Cash Flow Hedge –	of Deferred	Funded
Interest Rate	Costs	Status	Total

(in millions)

Balance in AOCI as of December 31, 2017

(4.5

)

4.5

(12.6

)

(12.6

)

Change in Fair Value Recognized in AOCI

—

(1.0

)

(1.0

)

Amount of (Gain) Loss Reclassified from AOCI

Interest on Long-Term Debt (a)	1.3		—		—		1.3
Amortization of Prior Service Cost (Credit)	—		(0.1	)	—		(0.1	)
Amortization of Actuarial (Gains) Losses	—		0.4		—		0.4
Reclassifications from AOCI, before Income Tax (Expense) Benefit	1.3		0.3		—		1.6
Income Tax (Expense) Benefit	0.3		0.1		—		0.4
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	1.0		0.2		—		1.2
Net Current Period Other Comprehensive Income (Loss)	1.0		0.2		(1.0	)	0.2
ASU 2018-02 Adoption (b)	(0.9	)	—		(1.8	)	(2.7	)

Balance in AOCI as of December 31, 2018

(4.4

)

4.7

(15.4

)

(15.1

)

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Year Ended December 31, 2017

Pension and OPEB

	Amortization	Changes in
Cash Flow Hedge –	of Deferred	Funded
Interest Rate	Costs	Status	Total

(in millions)

Balance in AOCI as of December 31, 2016

(5.4

)

4.2

(13.7

)

(14.9

)

Change in Fair Value Recognized in AOCI

—

1.1

Amount of (Gain) Loss Reclassified from AOCI

Interest on Long-Term Debt (a)	1.3	—		—	1.3
Amortization of Prior Service Cost (Credit)	—	(0.1	)	—	(0.1	)
Amortization of Actuarial (Gains) Losses	—	0.5		—	0.5
Reclassifications from AOCI, before Income Tax (Expense) Benefit	1.3	0.4		—	1.7
Income Tax (Expense) Benefit	0.4	0.1		—	0.5
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	0.9	0.3		—	1.2
Net Current Period Other Comprehensive Income (Loss)	0.9	0.3		1.1	2.3

Balance in AOCI as of December 31, 2017

(4.5

)

4.5

(12.6

)

(12.6

)

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

(b) See Note 2 - New Accounting Pronouncements for additional information.

4. RATE MATTERS

AEP Texas is involved in rate and regulatory proceedings at the FERC and the PUCT. Rate matters can have a material impact on net income, cash flows and possibly financial condition. AEP Texas’ recent significant rate orders and pending rate filings are addressed in this note.

Impact of Tax Reform

Rate and regulatory matters are impacted by federal income tax implications. In December 2017, Tax Reform was enacted, which impacts outstanding rate and regulatory matters. For additional details on the impact of Tax Reform, see Note 11 - Income Taxes.

AEP Texas Interim Transmission and Distribution Rates

As of December 31, 2018, AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2018, subject to review, are estimated to be $1 billion. 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.

In April 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely within ERCOT to make periodic filings for rate proceedings. The rule requires AEP Texas to file for a comprehensive rate review no later than May 1, 2019.

In 2018, the PUCT issued approvals to increase AEP Texas’ transmission rates by $22 million annually. The approvals included an increase in annual revenues to recover transmission capital additions of $46 million offset by a reduction in annual revenues of $24 million due to the reduction in the federal income tax rate due to Tax Reform. The approvals did not address the return of Excess ADIT benefits to customers.

In August 2018, the PUCT approved a Stipulation and Settlement agreement to amend AEP Texas’ Distribution Cost Recovery Factor to reduce annual distribution rates by approximately $24 million annually, beginning September 1, 2018. The settlement included an increase in annual revenues to recover 2017 distribution capital additions of $19 million offset by reductions in annual revenues of: (a) $21 million due to the reduction in the federal income tax rate due to Tax Reform, (b) $10 million due to Excess ADIT associated with certain depreciable property to be amortized using ARAM and (c) $12 million due to Excess ADIT that is not subject to rate normalization requirements to be refunded over 5 years.

Hurricane Harvey and Texas Storm Cost Securitization

In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of December 31, 2018, the total balance of AEP Texas’ regulatory asset for deferred storm costs is approximately $152 million, inclusive of approximately $129 million of incremental storm expenses related to Hurricane Harvey. See the table below for additional information on the Hurricane Harvey storm restoration costs:

December 31, 2018

Total Hurricane Harvey Storm Costs

Capital

O&M

Regulatory Asset

Total

(in millions)

Restoration Costs Incurred

219.1

136.9

—

356.0

Incremental Operation and Maintenance Expenses (O&M)		—			(129.8	)		129.8			—
Insurance Proceeds		(12.7	)		—			(1.2	)		(13.9	)

Total Hurricane Harvey Storm Costs, Net

206.4

7.1

128.6

342.1

The securitization of storm cost recovery in Texas requires two filings with the PUCT. In August 2018, AEP Texas filed a Determination of System Restoration Costs (DSRC) with the PUCT for total estimated storm costs in the amount of $425 million, which includes estimated carrying costs. The total estimated storm costs net of insurance proceeds, tax credits received for the Disaster Tax Relief and Airport and Airway Extension Act of 2017, and Excess ADIT that is not subject to rate normalization requirements utilized to reduce the non-capital Hurricane Harvey costs is $370 million.

In November 2018, AEP Texas, the PUCT staff and intervenors filed a stipulation and settlement agreement with the PUCT that included all aspects of the DSRC filing with the following exceptions: (a) a $5 million permanent storm restoration reduction, (b) a $4 million disallowance of charges not directly related to storm restoration that will be included in a future regulatory proceeding and (c) a $5 million disallowance due to additional insurance proceeds received. See the table below for a reconciliation of the filed Determination of System Restoration Costs and settlement and stipulation agreement:

Total Estimated Storm Costs Requested in the DSRC		December 31, 2018
		(in millions)

Total Estimated Hurricane Harvey Storm Costs

356.0

Estimated Hurricane Harvey Carrying Costs		31.5
Estimated Litigation Costs		0.6
Non-Hurricane Harvey Storm Restoration Costs		36.5
Total Estimated Storm Costs requested in the DSRC		424.6

less:

Tax Credit	(0.8	)
Insurance Proceeds	(8.7	)
Excess ADIT (a)	(45.5	)
Total Estimated Storm Costs requested in the DSRC, after adjustments	369.6

less:

Settlement Agreement Adjustments		(10.6	)
Incremental Insurance Proceeds Received		(5.1	)

Total Estimated Storm Costs per Settlement Agreement

353.9

Amount represents Non-Hurricane Harvey Excess ADIT that is not subject to rate normalization requirements.

AEP Texas will seek to securitize estimated distribution related assets of $247 million in the first half of 2019 while the remaining $107 million of estimated transmission related assets is expected to be recovered through interim transmission filings or an upcoming base rate case. If these costs are not recovered, it could have an adverse effect on future net income, cash flows and financial condition.

5. EFFECTS OF REGULATION

Regulatory assets and liabilities are comprised of the following items:

December 31,

Remaining

Recovery

Period

Regulatory Assets:

2018

2017

(in millions)

Regulatory assets pending final regulatory approval:

Regulatory Assets Currently Not Earning a Return

Storm-Related Costs (a)

152.4

123.3

Rate Case Expense		0.2			0.1
Total Regulatory Assets Pending Final Regulatory Approval		152.6			123.4

Advanced Metering System	45.3	33.5	2 years
Meter Replacement Costs	40.1	44.9	9 years
Total Regulatory Assets Currently Earning a Return	85.4	78.4

Regulatory Assets Currently Not Earning a Return

Pension and OPEB Funded Status	176.9	151.2	12 years
Income Tax Assets Subject to Flow Through	45.8	41.9	31 years
Securitization Assets	12.3	21.7	2 years
Transmission Cost Recovery Factor	1.7	9.5	2 years
Other Regulatory Assets Approved for Recovery	7.4	8.6	various
Total Regulatory Assets Currently Not Earning a Return	244.1	232.9

Total Regulatory Assets Approved for Recovery	329.5	311.3

Total FERC Account 182.3 Regulatory Assets

482.1

434.7

As of December 31, 2018, AEP Texas has deferred $129 million related to Hurricane Harvey and will seek securitization of the distribution related assets. See Note 4 - Rate Matters for additional information.

December 31,

Remaining

Refund

Period

Regulatory Liabilities:

2018

2017

(in millions)

Regulatory liabilities pending final regulatory determination:

Income Tax Related Regulatory Liabilities (a)

Excess ADIT Associated with Certain Depreciable Property

277.1

578.3

Excess ADIT that is Not Subject to Rate Normalization Requirements		141.5			103.3
Total Regulatory Liabilities Pending Final Regulatory Determination		418.6			681.6

Advanced Metering Infrastructure Surcharge		8.5			12.7			2 years
Excess Earnings		6.3			6.8			13 years

Total Regulatory Liabilities Currently Paying a Return		14.8		19.5
Regulatory Liabilities Currently Not Paying a Return

Other Regulatory Liabilities Approved for Payment	—	0.6	various
Total Regulatory Liabilities Currently Not Paying a Return	—	0.6
Income Tax Related Regulatory Liabilities (a)
Excess ADIT Associated with Certain Depreciable Property	251.9	—	(b)
Income Tax Liabilities Subject to Flow Through	2.9	3.2	31 years
Total Income Tax Related Regulatory Liabilities	254.8	3.2

Total Regulatory Liabilities Approved for Payment	269.6	23.3

Total FERC Account 254 Regulatory Liabilities

688.2

704.9

This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. See “Federal Tax Reform and Legislation” section of Note 11 - Income Taxes for additional information.
Refunded using ARAM.

6. 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 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.

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 AEP Texas under four uncommitted facilities totaling $305 million. AEP Texas’ maximum future payments for letters of credit issued under the uncommitted facilities as of December 31, 2018 was $3 million with a maturity date of January 2019. In January 2019, the letter of credit was amended to $2 million and the maturity date was extended until January 2020.

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 December 31, 2018, there were no material liabilities recorded for any indemnifications.

Lease Obligations

AEP Texas leases equipment under master lease agreements. See “Master Lease Agreements” section of Note 12 - Leases for additional information.

ENVIRONMENTAL CONTINGENCIES

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

The 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.

Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income.

Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often non-hazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as Potentially Responsible Parties for each site and several of the parties are financially sound enterprises. As of December 31, 2018, management’s estimates do not anticipate material clean-up costs for identified Superfund sites.

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

AEP Texas maintains insurance coverage normal and customary for electric utilities, subject to various deductibles. AEP Texas also maintains property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third-parties and are in excess of retentions absorbed by AEP Texas. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers.

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition.

7. BENEFIT PLANS

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1.

AEP Texas participates in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all 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.

AEP Texas recognizes the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. AEP Texas recognizes an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognizes, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. AEP Texas records a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

Actuarial Assumptions for Benefit Obligations

The weighted-average assumptions used in the measurement of benefit obligations are shown in the following table:

Pension Plans

OPEB

December 31,

Assumption

2018

2017

2018

2017

Discount Rate

4.30

3.65

4.30

3.60

Interest Crediting Rate		4.00	%			4.00	%			NA		NA
Rate of Compensation Increase		4.95	%	(a)		4.90	%	(a)		NA		NA

Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

NA Not applicable.

A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.

For 2018, the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above.

Actuarial Assumptions for Net Periodic Benefit Costs

The weighted-average assumptions used in the measurement of benefit costs are shown in the following table:

Pension Plans

OPEB

Years Ended December 31,

Assumption

2018

2017

2018

2017

Discount Rate

3.65

4.05

3.60

4.10

Interest Crediting Rate

4.00

Expected Return on Plan Assets

6.00

6.75

Rate of Compensation Increase

4.95

(a)

4.90

(a)

Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

NA Not applicable.

The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third-party forecasts and current prospects for economic growth.

The health care trend rate assumptions used for OPEB plans measurement purposes are shown below:

December 31,

Health Care Trend Rates

2018

2017

Initial		6.25	%		6.50	%
Ultimate		5.00	%		5.00	%

Year Ultimate Reached	2024	2024

Significant Concentrations of Risk within Plan Assets

In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2018, the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details.

Benefit Plan Obligations, Plan Assets, Funded Status and Amounts Recognized on the Balance Sheets

For the year ended December 31, 2018, the pension and OPEB plans had an actuarial gain due to an increase in the discount rate as well as updated estimates for future medical expenses in the OPEB plans. For the year ended December 31, 2017, the pension plans had an actuarial loss due to a decrease in the discount rate. The OPEB plans had an actuarial gain primarily due to a change in medical benefits for retirees which was partially offset by a decrease in the discount rate. The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets, funded status and the presentation on the balance sheets. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.

Pension Plans

OPEB

2018

2017

2018

2017

Change in Benefit Obligation

(in millions)

Benefit Obligation as of January 1,

441.3

421.7

107.1

120.4

Service Cost	9.2		8.6		0.9		0.9
Interest Cost	16.0		17.1		3.8		4.9
Actuarial (Gain) Loss	(20.9	)	25.6		(8.3	)	(11.9	)
Benefit Payments	(36.3	)	(31.7	)	(10.7	)	(10.8	)
Participant Contributions	—		—		3.1		3.6

Benefit Obligation as of December 31,

409.3

441.3

95.9

107.1


Change in Fair Value of Plan Assets

Fair Value of Plan Assets as of January 1,

455.9

416.6

147.3

134.1

Actual Gain (Loss) on Plan Assets	(9.3	)	61.8		(14.6	)	20.4
Company Contributions	0.4		9.2		4.8		—
Participant Contributions	—		—		3.1		3.6
Benefit Payments	(36.3	)	(31.7	)	(10.7	)	(10.8	)

Fair Value of Plan Assets as of December 31,

410.7

455.9

129.9

147.3

Funded Status as of December 31,

1.4

14.6

34.0

40.2

Pension Plans

OPEB

December 31,

2018

2017

2018

2017

(in millions)

Special Funds – Prepaid Benefit Costs

5.2

18.6

34.0

40.2

Miscellaneous Current and Accrued Liabilities – Short-term Benefit Liability		(0.4	)		(0.4	)		—			—
Accumulated Provision for Pensions and Benefits – Long-term Benefit Liability		(3.4	)		(3.6	)		—			—

Funded Status

1.4

14.6

34.0

40.2

Amounts Included in Regulatory Assets, Deferred Income Taxes, AOCI and Income Tax Expense

The following tables show the components of the plans included in regulatory assets, Deferred Income Taxes, AOCI and Income Tax Expense and the items attributable to the change in these components:

Pension Plans

OPEB

December 31,

2018

2017

2018

2017

Components

(in millions)

Net Actuarial Loss

182.0

175.2

38.0

23.9

Prior Service Credit

—

(29.5

)

(35.4

)


Recorded as

Regulatory Assets

168.2

161.4

8.7

(10.2

)

Deferred Income Taxes	2.9	2.9	—		(0.3	)
Net of Tax AOCI	10.9	8.9	(0.2	)	(0.8	)
Income Tax Expense (a)	—	2.0	—		(0.2	)

Amounts relate to the re-measurement of Deferred Income Taxes as a result of Tax Reform. In accordance with the accounting guidance for “Income Taxes”, re-measurement of Deferred Income Taxes related to AOCI must flow through the statement of income.

Pension Plans

OPEB

2018

2017

2018

2017

Components

(in millions)

Actuarial (Gain) Loss During the Year

14.0

(11.1

)

14.9

(23.6

)

Amortization of Actuarial Loss		(7.2	)		(7.0	)		(0.8	)		(3.2	)
Amortization of Prior Service Credit		—			—			5.9			5.8

Change for the Year Ended December 31,

6.8

(18.1

)

20.0

(21.0

)

Determination of Pension Expense

The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return.

Pension and OPEB Assets

The fair value tables within Pension and OPEB Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to AEP Texas using the percentages in the table below:

Pension Plan

OPEB

December 31,

2018

2017

2018

2017

8.7

8.8

8.5

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2018:

Asset Class

Level 1

Level 2

Level 3

Other

Total

Year End

Allocation

(in millions)

Equities (a):

Domestic

277.3

—

277.3

5.9

International	384.1	—	—	—	384.1	8.2	%
Options	—	18.3	—	—	18.3	0.4	%
Common Collective Trusts (c)	—	—	—	370.1	370.1	7.9	%
Subtotal – Equities	661.4	18.3	—	370.1	1,049.8	22.4	%

Fixed Income (a):

United States Government and Agency Securities	0.2	1,512.5	—	—	1,512.7	32.2	%
Corporate Debt	—	1,082.9	—	—	1,082.9	23.0	%
Foreign Debt	—	221.6	—	—	221.6	4.7	%
State and Local Government	—	28.2	—	—	28.2	0.6	%
Other – Asset Backed	—	7.4	—	—	7.4	0.2	%
Subtotal – Fixed Income	0.2	2,852.6	—	—	2,852.8	60.7	%

Infrastructure (c)	—		—	—	72.2	72.2	1.5	%
Real Estate (c)	—		—	—	220.4	220.4	4.7	%
Alternative Investments (c)	—		—	—	444.6	444.6	9.5	%
Cash and Cash Equivalents (c)	(0.4	)	36.3	—	11.9	47.8	1.0	%
Other – Pending Transactions and Accrued Income (b)	—		—	—	8.3	8.3	0.2	%

Total

661.2

2,907.2

—

1,127.5

4,695.9

100.0

Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.
Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2018:

Asset Class

Level 1

Level 2

Level 3

Other

Total

Year End

Allocation

(in millions)

Equities:

Domestic

233.3

—

233.3

15.2

International	185.9	—	—	—	185.9	12.1	%
Options	—	4.3	—	—	4.3	0.3	%
Common Collective Trusts (b)	—	—	—	226.2	226.2	14.7	%
Subtotal – Equities	419.2	4.3	—	226.2	649.7	42.3	%

Fixed Income:

Common Collective Trust – Debt (b)	—	—	—	163.6	163.6	10.7	%
United States Government and Agency Securities	0.2	181.5	—	—	181.7	11.8	%
Corporate Debt	—	188.6	—	—	188.6	12.3	%
Foreign Debt	—	35.0	—	—	35.0	2.3	%
State and Local Government	41.8	11.8	—	—	53.6	3.5	%
Other – Asset Backed	—	0.2	—	—	0.2	—	%
Subtotal – Fixed Income	42.0	417.1	—	163.6	622.7	40.6	%

Trust Owned Life Insurance:

International Equities	—	49.4	—	—	49.4	3.2	%
United States Bonds	—	154.4	—	—	154.4	10.1	%
Subtotal – Trust Owned Life Insurance	—	203.8	—	—	203.8	13.3	%

Cash and Cash Equivalents (b)		54.4			—			—			4.8			59.2			3.9	%
Other – Pending Transactions and Accrued Income (a)		—			—			—			(1.2	)		(1.2	)		(0.1	)%

Total

515.6

625.2

—

393.4

1,534.2

100.0

Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2017:

Asset Class

Level 1

Level 2

Level 3

Other

Total

Year End
Allocation

(in millions)

Equities (a):

Domestic

318.6

—

318.6

6.2

International	507.7	—	—	—	507.7	9.8	%
Options	—	26.9	—	—	26.9	0.5	%
Common Collective Trusts (c)	—	—	—	452.9	452.9	8.7	%
Subtotal – Equities	826.3	26.9	—	452.9	1,306.1	25.2	%

Fixed Income (a):

United States Government and Agency Securities	—	1,376.5	—	—	1,376.5	26.6	%
Corporate Debt	—	1,277.0	—	—	1,277.0	24.7	%
Foreign Debt	—	296.9	—	—	296.9	5.7	%
State and Local Government	—	31.7	—	—	31.7	0.6	%
Other – Asset Backed	—	10.2	—	—	10.2	0.2	%
Subtotal – Fixed Income	—	2,992.3	—	—	2,992.3	57.8	%

Infrastructure (c)	—	—	—	59.5	59.5	1.2	%
Real Estate (c)	—	—	—	290.3	290.3	5.6	%
Alternative Investments (c)	—	—	—	446.0	446.0	8.6	%
Cash and Cash Equivalents (c)	0.4	35.6	—	21.2	57.2	1.1	%
Other – Pending Transactions and Accrued Income (b)	—	—	—	22.7	22.7	0.5	%

Total

826.7

3,054.8

—

1,292.6

5,174.1

100.0

Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.
Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.

The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets:

Infrastructure

Real

Estate

Alternative

Investments

Total

Level 3

(in millions)

Balance as of January 1, 2017

57.6

254.9

411.1

723.6

Actual Return on Plan Assets

Relating to Assets Still Held as of the Reporting Date	—		—		—		—
Relating to Assets Sold During the Period	—		—		—		—
Purchases and Sales	—		—		—		—
Transfers into Level 3	—		—		—		—
Transfers out of Level 3 (a)	(57.6	)	(254.9	)	(411.1	)	(723.6	)

Balance as of December 31, 2017

—

The classification of Level 3 assets from the prior year was corrected in the current year presentation and included within the fair value hierarchy table as of December 31, 2017 as “Other” investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent). Management concluded that these disclosure errors were immaterial individually and in the aggregate to all prior periods presented. he following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2017:

Asset Class

Level 1

Level 2

Level 3

Other

Total

Year End
Allocation

(in millions)

Equities:

Domestic

307.1

—

307.1

17.7

International	306.9	—	—	—	306.9	17.7	%
Options	—	9.4	—	—	9.4	0.5	%
Common Collective Trusts (b)	—	—	—	153.6	153.6	8.9	%
Subtotal – Equities	614.0	9.4	—	153.6	777.0	44.8	%

Fixed Income:

Common Collective Trust – Debt (b)	—	—	—	185.0	185.0	10.7	%
United States Government and Agency Securities	—	187.4	—	—	187.4	10.8	%
Corporate Debt	—	214.1	—	—	214.1	12.4	%
Foreign Debt	—	40.7	—	—	40.7	2.4	%
State and Local Government	49.7	16.8	—	—	66.5	3.8	%
Other – Asset Backed	—	0.2	—	—	0.2	—	%
Subtotal – Fixed Income	49.7	459.2	—	185.0	693.9	40.1	%

Trust Owned Life Insurance:

International Equities	—	105.4	—	—	105.4	6.1	%
United States Bonds	—	118.2	—	—	118.2	6.8	%
Subtotal – Trust Owned Life Insurance	—	223.6	—	—	223.6	12.9	%

Cash and Cash Equivalents (b)		36.7			—			—			4.2			40.9			2.4	%
Other – Pending Transactions and Accrued Income (a)		—			—			—			(2.9	)		(2.9	)		(0.2	)%

Total

700.4

692.2

—

339.9

1,732.5

100.0

Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.

Accumulated Benefit Obligation

The accumulated benefit obligation for the pension plans was as follows:

December 31,

Accumulated Benefit Obligation

2018

2017

(in millions)

Qualified Pension Plan	$	393.2	$	421.4
Nonqualified Pension Plans		3.6		3.8
Total	$	396.8	$	425.2

Obligations in Excess of Fair Values

The tables below show the underfunded pension plans that had obligations in excess of plan assets.

Projected Benefit Obligation

December 31,

2018

2017

(in millions)

Projected Benefit Obligation

3.8

4.0

Fair Value of Plan Assets

—

Underfunded Projected Benefit Obligation

(3.8)

(4.0)

Accumulated Benefit Obligation

December 31,

2018

2017

(in millions)

Accumulated Benefit Obligation

3.6

3.8

Fair Value of Plan Assets

—

Underfunded Accumulated Benefit Obligation

(3.6)

(3.8)

Estimated Future Benefit Payments and Contributions

AEP Texas expects contributions and payments for the pension plans of $8 million during 2019. For the pension plans, this amount includes the payment of unfunded nonqualified benefits plus contributions to the qualified trust fund of at least the minimum amount required by the Employee Retirement Income Security Act. For the qualified pension plan, AEP Texas may also make additional discretionary contributions to maintain the funded status of the plan.

The table below reflects the total benefits expected to be paid from the plan or from AEP Texas’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows:

Estimated Payments

Pension Plans

OPEB

(in millions)

2019

30.8

10.0

2020	34.3	10.5
2021	34.9	10.7
2022	33.5	10.9
2023	34.9	10.9
Years 2024 to 2028, in Total	164.7	53.6

Components of Net Periodic Benefit Cost

The following table provides the components of net periodic benefit cost (credit) for the plans:

Pension Plans

OPEB

Years Ended December 31,

2018

2017

2018

2017

(in millions)

Service Cost

9.2

8.6

0.9

Interest Cost	16.0		17.1		3.8		4.9
Expected Return on Plan Assets	(25.6	)	(25.0	)	(8.6	)	(8.8	)
Amortization of Prior Service Cost (Credit)	—		—		(5.9	)	(5.8	)
Amortization of Net Actuarial Loss	7.2		7.0		0.8		3.2
Net Periodic Benefit Cost (Credit)	6.8		7.7		(9.0	)	(5.6	)
Capitalized Portion	(4.8	)	(4.0	)	(0.5	)	2.9

Net Periodic Benefit Cost (Credit) Recognized in Expense

2.0

3.7

(9.5

)

(2.7

)

American Electric Power System Retirement Savings Plan

AEP Texas participates in an AEP sponsored defined contribution retirement savings plan, the American Electric Power System Retirement Savings Plan, for substantially all employees. This qualified plan offers participants an opportunity to contribute a portion of their pay, includes features under Section 401(k) of the Internal Revenue Code and provides for company matching contributions. The matching contributions to the plan are 100% of the first 1% of eligible employee contributions and 70% of the next 5% of contributions. The cost for matching contributions to the retirement savings plans was $6 million for both years ended December 31, 2018 and 2017.

8. BUSINESS SEGMENTS

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

9. DERIVATIVES AND HEDGING

AEP Texas adopted ASU 2017-12 in the second quarter of 2018, effective January 1, 2018. See Note 2 - New Accounting Pronouncements for additional information.

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 December 31, 2018 and 2017 were 2 million gallons and 1 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, supply and demand market data and 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 as of December 31, 2018 and 2017.

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

Fair Value of Derivative Instruments

December 31, 2018

	Risk Management	Gross Amounts Offset	Net Amounts of Assets/Liabilities
	Contracts -	in the Statement of	Presented in the Statement
Balance Sheet Location	Commodity (a)	Financial Position (b)	of Financial Position (c)

(in millions)

Derivative Instrument Assets

—

Long-Term Portion of Derivative Instrument Assets

—

Derivative Instrument Liabilities		0.7			(0.5	)		0.2
Long-Term Portion of Derivative Instrument Liabilities		—			—			—

Fair Value of Derivative Instruments

December 31, 2017

	Risk Management	Gross Amounts Offset	Net Amounts of Assets/Liabilities
	Contracts -	in the Statement of	Presented in the Statement
Balance Sheet Location	Commodity (a)	Financial Position (b)	of Financial Position (c)

(in millions)

Derivative Instrument Assets

0.5

—

0.5

Long-Term Portion of Derivative Instrument Assets

—

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

Derivative instruments within this category are reported 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.”
Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.

The table below presents the activity of derivative risk management contracts:

Amount of Gain (Loss) Recognized on

Risk Management Contracts

Years Ended December 31,

Location of Gain (Loss)

2018

2017

(in millions)

Operating Expenses	$	0.4	$	0.1
Maintenance Expenses		0.4		0.2
Other Regulatory Assets (a)		(0.7)		—
Other Regulatory Liabilities (a)		(0.5)		0.1
Total Gain (Loss) on Risk Management Contracts	$	(0.4)	$	0.4

(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 expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses 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.

Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Operating Revenues or Operation Expenses on the statements of income or in Other Regulatory Assets or Other Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the years ended 2018 and 2017, AEP Texas did not apply cash flow hedging to outstanding power derivatives.

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 years ended 2018 and 2017, AEP Texas did not apply cash flow hedging to outstanding interest rate derivatives.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income on the balance sheets into Depreciation Expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the years ended 2018 and 2017, AEP Texas did not apply cash flow hedging to any outstanding foreign currency 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

December 31, 2018

December 31, 2017

Interest Rate

	Expected to be		Expected to be
	Reclassed to		Reclassed to
	Net Income During		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)

(4.4)

(1.1)

(4.5)

(0.9)

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.

10. FAIR VALUE MEASUREMENTS

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:

December 31,

2018

2017

Book Value

Fair Value

Book Value

Fair Value

(in millions)

3,106.6

3,165.2

2,637.6

2,909.5

Fair Value Measurements of Financial Assets and Liabilities

For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1.

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

December 31, 2018

Level 1

Level 2

Level 3

Other

Total

Liabilities:

(in millions)

Derivative Instrument Liabilities

Risk Management Commodity Contracts (a)

—

0.7

—

(0.5

)

0.2

December 31, 2017

Level 1

Level 2

Level 3

Other

Total

Assets:

(in millions)

Derivative Instrument Assets

Risk Management Commodity Contracts (a)

—

0.5

—

0.5

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.”

There were no transfers between Level 1 and Level 2 during the years ended December 31, 2018 and 2017.

11. INCOME TAXES

Federal Tax Reform and Legislation

In December 2017, Tax Reform legislation was signed into law. Tax Reform includes significant changes to the Internal Revenue Code of 1986, as amended, including lowering the corporate federal income tax rate from 35% to 21%. As a result of this rate change, AEP Texas’ deferred tax assets and liabilities were remeasured using the newly enacted rate of 21% in December 2017. In response to Tax Reform, the SEC staff issued Staff Accounting Bulletin 118 (SAB 118) in December 2017. SAB 118 provided for up to a one year period (the measurement period) in which to complete the required analyses and accounting required by Tax Reform.

During 2017, AEP Texas recorded provisional amounts for the income tax effects of Tax Reform. Throughout 2018, AEP Texas continued to assess the impacts of legislative changes in the tax code as well as interpretative changes of the tax code. The measurement period adjustments recorded during 2018 were immaterial.

The measurement period under SAB 118 ended in December 2018. However, Tax Reform uncertainties still remain and AEP Texas will continue to monitor income tax effects that may change as a result of future legislation and further interpretation of Tax Reform based on proposed U.S. Treasury regulations and guidance from the IRS and state tax authorities.

Federal Legislation

The IRS has proposed new regulations that provide guidance regarding the additional first-year depreciation deduction under Section 168(k). The proposed regulations reflect changes as a result of Tax Reform and affect taxpayers with qualified depreciable property acquired and placed in service after September 27, 2017. Generally, AEP Texas’ regulated businesses will not be eligible for any bonus depreciation for property acquired and placed in service after January 1, 2018. However, for self-constructed property and other property placed in service in 2018 for which construction began prior to January 1, 2018, taxpayers are required to evaluate the contractual terms to determine if these additions qualify for 100% expensing under Tax Reform or 50% bonus depreciation as provided under prior tax law.

Excess and Deficient Accumulated Deferred Income Taxes as Result of Tax Reform

Accounting guidance for “Income Taxes” requires deferred tax assets and liabilities to be measured at the enacted income tax rate expected to apply when the related temporary differences will be realized or settled. As a result, AEP Texas’ deferred tax assets and liabilities were re-measured in December 2017 using the newly enacted tax rate of 21% resulting in excess or deficient accumulated deferred income taxes (“ADIT”).

With respect to the AEP Texas’ regulated operations, the change to net deferred income taxes was primarily offset by a corresponding change in net income tax related regulatory assets and liabilities to reflect amounts expected to be provided to customers. Where the deferred income tax amount was not previously contemplated in regulated rates or pertained to unregulated operations, the re-measurement was recorded as an adjustment to income tax expense.

The FERC accounts affected by the re-measurement of ADIT include:

182.3 Other Regulatory Assets

190 Accumulated Deferred Income Taxes

254 Other Regulatory Liabilities

281 Accumulated Deferred Income Taxes – Accelerated Amortization

282 Accumulated Deferred Income Taxes – Other Property

283 Accumulated Deferred Income Taxes – Other

410.1 Provision for Deferred Income Taxes, Utility Operating Income

410.2 Provision for Deferred Income Taxes, Utility Non-Operating Income

411.1 Provision for Deferred Income Taxes – Credit, Utility Operating Income

411.2 Provision for Deferred Income Taxes – Credit, Utility Non-Operating Income

Tax Reform included certain rate normalization requirements that stipulate how the portion of total excess or deficient ADIT that is related to certain depreciable property must be returned to customers. Specifically, regulated public utilities subject to these rate normalization requirements must recognize the impact of re-measured deferred taxes applicable to prior depreciation using an average rate assumption method. As a result, once the amortization of Excess ADIT is reflected in rates, customers will receive the benefits over the remaining weighted average useful life of the applicable property. The remaining balance of excess or deficient ADIT will be returned to customers via the mechanisms and time periods as agreed to and/or ordered by the PUCT. See “AEP Texas Interim Transmission and Distribution Rates” section of Note 4 - Rate Matters for additional information.

As of December 31, 2018, AEP Texas had recorded a regulatory liability for approximately $530 million of Excess ADIT as well as an incremental liability of $141 million to reflect the Excess ADIT on a pretax basis which is presented in Other Regulatory Liabilities on the balance sheet. $417 million of the Excess ADIT relates to temporary differences associated with certain depreciable property.

During 2018, AEP Texas recognized $12 million of amortization of Excess ADIT within Provisions for Deferred Income Taxes – Credit, Utility Operating Income on the statements of income.

Income Tax Expense (Benefit)

The details of AEP Texas’ Income Tax Expense (Benefit) are as follows:

Years Ended December 31,

2018

2017

(in millions)

Charged (Credited) to Operating Expenses, Net:

Current	$	36.5	$	(95.6)
Deferred		(11.5)		83.7
Deferred Investment Tax Credits		(1.5)		(1.6)

Total	23.5	(13.5)

Charged (Credited) to Nonoperating Income, Net:

	Current		2.3			11.1
	Deferred		(5.0)			(20.8)

Total		(2.7)			(9.7)
Total Income Taxes (Benefit)	$	20.8		$	(23.2)

The following is a reconciliation between the federal income taxes computed by multiplying pretax income by the federal statutory tax rate and the income taxes reported:

Years Ended December 31,

2018

2017

(in millions)

Net Income

211.3

311.1

Income Tax Expense (Benefit)

20.8

(23.2)

Pretax Income

232.1

287.9

Income Taxes on Pretax Income at Statutory Rate (21% and 35% in 2018 and 2017, Respectively)

48.7

100.8

Increase (Decrease) in Income Taxes Resulting from the Following Items:

	State and Local Income Taxes, Net		1.3		0.4	)
	AFUDC		(4.2)		(3.9)	)
	Parent Company Loss Benefit		(3.1)		—	)
	Tax Reform Adjustments		(11.0)		(119.2)
	Tax Adjustments		—		(2.5)	)
Tax Reform Excess ADIT Reversal		(11.8)		—
	Other		0.9		1.2	)

Income Tax Expense (Benefit)

20.8

(23.2)

Effective Income Tax Rate

9.0

(8.1)

Net Deferred Tax Liability

The following table shows elements of AEP Texas’ net deferred tax liability and significant temporary differences:

December 31,

2018

2017

(in millions)

Deferred Tax Assets

207.9

220.7

Deferred Tax Liabilities

(1,121.2)

(1,096.0)

Net Deferred Tax Liabilities

(913.3)

(875.3)

Property Related Temporary Differences

(836.4)

(753.4)

Amounts Due to Customers for Future Federal Income Taxes	142.3	140.9
Deferred State Income Taxes	(27.1)	(27.5)
Regulatory Assets	(53.9)	(65.2)
Securitized Transition Assets	(144.4)	(190.5)
Deferred Income Taxes on Other Comprehensive Loss	4.0	4.1
Deferred Revenues	4.6	18.9
All Other, Net	(2.4)	(2.6)

Net Deferred Tax Liabilities

(913.3)

(875.3)

AEP System Tax Allocation Agreement

AEP Texas joins in the filing of a consolidated federal income tax return with its affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent and tax credits, the method of allocation reflects a separate return result for each company in the consolidated group.

Federal and State Income Tax Audit Status

AEP Texas and other AEP subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011 through 2013 started in April 2014. AEP Texas and other AEP subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. To resolve the issue under consideration, AEP Texas and other AEP subsidiaries and the IRS exam team agreed to utilize the Fast Track Settlement Program in December 2017. The program was completed in March 2018 and tax years 2014 and 2015 were added to the IRS examination to reflect the impact of the Fast Track changes that were carried forward to 2014 and 2015. In June 2018, AEP Texas and other AEP subsidiaries settled all outstanding issues under audit for tax years 2011-2015. The Joint Committee approved the settlement in November 2018. The settlement did not materially impact AEP Texas’ net income, cash flows or financial condition. The IRS examination of 2016 began in October 2018.

AEP Texas and other AEP subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns. AEP Texas and other AEP subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. AEP Texas is no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2007.

Uncertain Tax Positions

The reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

2018

2017

(in millions)

Balance as of January 1,	$	(0.8)	$	6.5
Increase – Tax Positions Taken During a Prior Period		—		2.0
Decrease – Tax Positions Taken During a Prior Period		—		(12.3)
Increase – Tax Positions Taken During the Current Year		—		—
Decrease – Tax Positions Taken During the Current Year		—		—
Increase – Settlements with Taxing Authorities		—		—
Decrease – Settlements with Taxing Authorities		—		3.0
Decrease – Lapse of the Applicable Statute of Limitations		—		—
Balance as of December 31,	$	(0.8)	$	(0.8)

The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $1 million and $1 million for 2018 and 2017, respectively. Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date.

State Tax Legislation

In June 2018, the United States Supreme Court issued a decision which eliminated a physical presence requirement for the imposition of sales and use tax and instead applied an economic nexus concept. Although this case was specific to sales and use taxes, many states are beginning to consider whether they could also apply this economic nexus concept to income taxes. Management continues to monitor state legislation to determine whether it could create any income tax liability in any states in which AEP Texas currently does not file.

12. LEASES

Leases of property, plant and equipment are for remaining periods up to 10 years and require payments of related property taxes, maintenance and operating costs. Many of the leases have purchase or renewal options. Leases not renewed are often replaced by other leases.

Lease rentals for both operating and capital leases are generally charged to Operation Expenses and Maintenance Expenses in accordance with rate-making treatment for regulated operations. The components of rental costs were as follows:

Years Ended December 31,

2018

2017

(in millions)

Net Lease Expense on Operating Leases	$	13.6	$	10.5
Amortization of Capital Leases		4.8		4.0
Interest on Capital Leases		1.2		0.8
Total Lease Rental Costs	$	19.6	$	15.3

The following table shows the property, plant and equipment under capital leases and related obligations recorded on AEP Texas’ balance sheets.

December 31,

2018

2017

(in millions)

Property, Plant and Equipment Under Capital Leases
Total Property, Plant and Equipment	$	38.8	$	32.7
Accumulated Amortization		10.3		10.0
Net Property, Plant and Equipment Under Capital Leases	$	28.5	$	22.7

Obligations Under Capital Leases:
Noncurrent	$	24.0	$	18.5
Current		4.5		4.2
Total Obligations Under Capital Leases	$	28.5	$	22.7

Future minimum lease payments consisted of the following as of December 31, 2018:

				Noncancelable
		Capital		Operating
		Leases		Leases

(in millions)

2019	$	5.8	$	15.1
2020		5.3		14.1
2021		4.7		13.2
2022		4.2		12.2
2023		3.7		10.8
Later Years		10.1		28.4
Total Future Minimum Lease Payments		33.8	$		93.8
Less Estimated Interest Element		5.3
Estimated Present Value of Future Minimum Lease Payments	$	28.5

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 December 31, 2018, 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.

13. FINANCING ACTIVITIES

Long-term Debt

The following table details long-term debt outstanding:

				Weighted-Average		Interest Rate Ranges as of		Outstanding as of
				Interest Rate as of		December 31,		December 31,

Maturity

December 31, 2018

2018

2017

2018

2017

(in millions)

Senior Unsecured Notes

2019-2047

4.06%

2.40%-6.76%

2,420.0

1,950.0

Pollution Control Bonds	2020-2030	4.39%	1.75%-6.30%	1.75%-6.30%	493.2		493.2
Other Long-term Debt	2019-2059	3.94%	3.94%-4.50%	2.75%-4.50%	201.0		201.0
Unamortized Discount, Net					(7.6	)	(6.6	)

Total Long-term Debt

3,106.6

2,637.6

As of December 31, 2018, long-term debt was payable as follows:

(in millions)

2019	$	250.0
2020		110.6
2021		—
2022		425.0
2023		125.0
After 2023		2,203.6
Principal Amount		3,114.2
Unamortized Discount, Net		(7.6)
Total Long-term Debt	$	3,106.6

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 most restrictive dividend limitation for AEP Texas is through the credit agreements. As of December 31, 2018, the maximum amount of restricted net assets of AEP Texas that may not be distributed to the Parent in the form of a loan, advance or dividend was $1.6 billion.

The credit agreement covenant restrictions can limit the ability of AEP Texas to pay dividends out of retained earnings. As of December 31, 2018, the amount of any such restrictions was $354 million.

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 the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2018 and 2017 are included in Notes Receivable from Associated Companies and Notes Payable to Associated Companies, respectively, on the balance sheets. AEP Texas’ money pool activity and their corresponding authorized borrowing limits are described in the following table:

Maximum

Average

Loans to

Borrowings

Maximum

Borrowings

Average

(Borrowings from)

Authorized

from the

Loans to the

from the

Loans to the

the Utility Money

Short-term

Years Ended

Utility

Pool as of

Borrowing

December 31,

Money Pool

December 31,

Limit

(in millions)

2018

390.6

106.9

176.0

47.1

(216.0

)

500.0

2017

296.0

451.7

194.8

264.6

103.5

400.0

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 Rates

Interest Rate

for Funds

Borrowed from

Loaned to the

Borrowed from

Loaned to the

Years Ended

the Utility

Utility Money

the Utility

Utility Money

December 31,

Money Pool

Pool

Money Pool

Pool

2018

2.97%

1.81%

2.51%

1.85%

2.26%

2.29%

2017

1.49%

0.92%

1.85%

1.12%

1.29%

1.26%

Interest expense and interest income related to the Utility Money Pool financing relationship are included in Interest on Debt to Associated Companies and Interest and Dividend Income, respectively, on the statements of income. The interest expense and interest income related to the corporate borrowing programs were immaterial for the years ended December 31, 2018 and 2017.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 6 - Commitments, Guarantees and Contingencies.

14. RELATED PARTY TRANSACTIONS

For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 11 - Income Taxes in addition to “Corporate Borrowing Program – AEP System” section of Note 13 - Financing Activities.

Affiliated Revenues and Purchases

The following table shows the revenues derived from direct sales to affiliates, auction sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2018 and 2017:

Years Ended December 31,

Related Party Revenues

2018

2017

(in millions)

Direct Sales to AEPEP		$	103.6		$	63.6
Other Revenues			1.6			2.1

ERCOT Transmission Service Charges

Pursuant to an order from the PUCT, ETT bills AEP Texas for its ERCOT wholesale transmission services. ETT billed AEP Texas $27 million and $30 million for transmission services in 2018 and 2017, respectively. The billings are recorded in Operation Expenses on AEP Texas’ statements of income.

Oklaunion PPA between AEP Texas and AEPEP

In 2007, AEP Texas entered into a PPA with an affiliate, AEPEP, whereby AEP Texas agrees to sell AEPEP 100% of AEP Texas’ capacity and associated energy from its undivided interest (54.69%) in the Oklaunion Power Station. AEPEP pays AEP Texas for the capacity and associated energy delivered to the delivery point, the sum of fuel, operation and maintenance, depreciation, capacity and all taxes other than federal income taxes applicable. A portion of the payment is fixed and is payable regardless of the level of output. There are no penalties if AEP Texas fails to maintain a minimum availability level or exceeds a maximum heat rate level. The PPA was approved by the FERC. AEP Texas recognizes revenues for the fuel, operations and maintenance and all other taxes as-billed. Revenue is recognized for the capacity and depreciation billed to AEPEP, on a straight-line basis over the term of the PPA as these represent the minimum payments due. In September 2018, the co-owners of Oklaunion Power Station voted to close the plant in 2020. Effective October 2018, AEP Texas increased depreciation expense to ensure the plant balances are fully depreciated as of September 2020 and recovered through the PPA billings to AEPEP. Under the early termination provisions of the PPA, AEPEP expects to pay AEP Texas the full Utility Plant balance through depreciation payments over the remaining period of operation of the plant, which is currently estimated to be September 2020.

AEP Texas recorded revenue of $104 million and $64 million from AEPEP for the years ended December 31, 2018 and 2017, respectively. These amounts are included in Operating Revenues on AEP Texas’ statements of income.

Sales and Purchases of Property

AEP Texas had affiliated sales and purchases of electric property amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following table shows the sales and purchases, recorded at net book value, for the years ended December 31, 2018 and 2017:

Years Ended December 31,

2018

2017

(in millions)

Sales		$	0.3		$	0.2
Purchases			0.1			0.4

The amounts above are recorded in Utility Plant on the balance sheets.

Intercompany Billings

AEP Texas and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.

AEPSC

AEPSC provides certain managerial and professional services to AEP Texas. The costs of the services are based on a direct charge or on a prorated basis and billed to AEP Texas at AEPSC’s cost. AEPSC and its billings are subject to regulation by the FERC. AEP Texas’ total billings from AEPSC were $188 million and $153 million for the years ended December 31, 2018 and 2017, respectively.

15. PROPERTY, PLANT AND EQUIPMENT

Depreciation

AEP Texas provides for depreciation of Utility Plant on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following table provides total regulated annual composite depreciation rates by functional class:

Year

Steam

Transmission

Distribution

General

(in percentages)

2018			7.2			1.7			3.6			6.0
2017			2.4			1.7			3.6			8.7

The composite depreciation rate generally includes a component for non-ARO removal costs, which is credited to accumulated depreciation on the balance sheets. Actual removal costs incurred are charged to accumulated depreciation.

Asset Retirement Obligations

AEP Texas records ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms and certain coal mining facilities. AEP Texas has identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since AEP Texas plans to use its facilities indefinitely. The retirement obligation would only be recognized if and when AEP Texas abandons or ceases the use of specific easements, which is not expected.

The following is a reconciliation of the 2018 and 2017 aggregate carrying amounts of ARO:

									Revisions in
			ARO at		Accretion		Liabilities		Cash Flow		ARO at

Year

January 1,

Expense

Settled

Estimates

December 31,

(in millions)

2018		$	26.1		$	1.2		$	(0.1)		$	0.1		$	27.3
2017			25.0			1.1			(0.1)			0.1			26.1

Jointly-owned Electric Facilities

AEP Texas has electric facilities that are jointly-owned with affiliated and nonaffiliated companies. Using its own financing, AEP Texas is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. AEP Texas’ proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Utility Plant as follows:

			Construction
Fuel	Percent of	Utility Plant	Work in	Accumulated
Type	Ownership	In Service	Progress	Depreciation

(in millions)

AEP Texas’ Share as of December 31, 2018

Oklaunion Power Station (a)

Coal

54.7

352.1

0.2

218.6


AEP Texas’ Share as of December 31, 2017

Oklaunion Power Station (a)

Coal

54.7

350.7

1.3

194.1

Operated by PSO, which owns 15.6%. Also jointly-owned (54.7%) by AEP Texas and various nonaffiliated companies.

16. REVENUE FROM CONTRACTS WITH CUSTOMERS

Disaggregated Revenues from Contracts with Customers

The following table represents AEP Texas’ revenues from contracts with customers, net of respective provisions for refund, by type of revenue:

		Twelve Months Ended
		December 31, 2018
		(in millions)
Retail Revenues:

Residential Revenues

462.4

Commercial Revenues		307.5
Industrial Revenues		78.7
Other Retail Revenues		23.8
Total Retail Revenues		872.4


Wholesale Revenues:

Transmission Revenues		313.4
Total Wholesale Revenues		313.4

Other Revenues from Contracts with Customers (a)

27.0

Total Revenues from Contracts with Customers

1,212.8


Other Revenues:

Alternative Revenues	(1.3	)
Other Revenues (a)	110.9
Total Other Revenues	109.6

Total Operating Revenues

1,322.4

Amounts include affiliated and nonaffiliated revenues.

Performance Obligations

AEP Texas has performance obligations as part of its normal course of business. A performance obligation is a promise to transfer a distinct good or service, or a series of distinct goods or services that are substantially the same and have the same pattern of transfer to a customer. The invoice practical expedient within the accounting guidance for “Revenue from Contracts with Customers” allows for the recognition of revenue from performance obligations in the amount of consideration to which there is a right to invoice the customer and when the amount for which there is a right to invoice corresponds directly to the value transferred to the customer.

The purpose of the invoice practical expedient is to depict an entity’s measure of progress toward completion of the performance obligation within a contract and can only be applied to performance obligations that are satisfied over time and when the invoice is representative of services provided to date. AEP Texas elected to apply the invoice practical expedient to recognize revenue for performance obligations satisfied over time as the invoices from the respective revenue streams are representative of services or goods provided to date to the customer. Performance obligations for AEP Texas are summarized as follows:

Retail Revenues

AEP Texas has performance obligations to generate, transmit and distribute electricity for sale to rate-regulated retail customers. The performance obligation to deliver electricity is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are variable as they are subject to the customer’s usage requirements.

Rate-regulated retail customers typically have the right to discontinue receiving service at will, therefore these contracts between AEP Texas and their customers for rate-regulated services are generally limited to the services requested and received to date for such arrangements. Retail customers are generally billed on a monthly basis, and payment is typically due within 15 to 20 days after the issuance of the invoice. Payments from Retail Electric Providers are due to AEP Texas within 35 days.

Wholesale Revenues - Transmission

AEP Texas has performance obligations to transmit electricity to wholesale customers through assets owned and operated. The performance obligation to provide transmission services in ERCOT encompass a time frame greater than a year, where the performance obligation within ERCOT is partially fixed for a period of one year or less. Payments from ERCOT for transmission services are typically received within one week from the issuance of the invoice, which is issued monthly for ERCOT.

AEP Texas within the ERCOT region collect revenues through a combination of base rates and interim Transmission Costs of Services filings that are approved by the PUCT.

Fixed Performance Obligations

The following table represents the remaining fixed performance obligations satisfied over time as of December 31, 2018. Fixed performance obligations primarily include wholesale transmission services and electricity sales for fixed amounts of energy. The amounts below include affiliated and nonaffiliated revenues.

2019

2020-2021

2022-2023

After 2024

Total

(in millions)

332.8

—

332.8

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 any material contract assets as of December 31, 2018.

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 any material contract liabilities as of December 31, 2018.

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 December 31, 2018.

Affiliated accounts receivable from contracts with customers included in Accounts Receivable from Associated Companies on AEP Texas’ balance sheets were immaterial as of December 31, 2018 and January 1, 2018.

Contract Costs

Contract costs to obtain or fulfill a contract for AEP Texas are accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and are neither bifurcated nor reclassified between current assets and deferred debits on the balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Operation Expenses on the income statements. AEP Texas did not have material contract costs as of December 31, 2018.

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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				9,518,192	5,358,052		14,876,244
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income				264,139	868,873		1,133,012
3	Preceding Quarter/Year to Date Changes in Fair Value				1,093,655			1,093,655
4	Total (lines 2 and 3)				1,357,794	868,873		2,226,667	311,141,076	313,367,743
5	Balance of Account 219 at End of Preceding Quarter/Year				8,160,398	4,489,179		12,649,577
6	Balance of Account 219 at Beginning of Current Year				8,160,398	4,489,179		12,649,577
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income				215,257	1,056,015		1,271,272
8	Current Quarter/Year to Date Changes in Fair Value				2,802,559	966,900		3,769,459
9	Total (lines 7 and 8)				2,587,302	89,115		2,498,187	211,345,402	208,847,215
10	Balance of Account 219 at End of Current Quarter/Year				10,747,700	4,400,064		15,147,764

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.
Line No.	Classification (a)	Total Company For the Current Year/Quarter Ended (b)	Electric (c)	Gas (d)	Other (Specify) (e)	Other (Specify) (f)	Other (Specify) (g)	Common (h)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlantInServiceAbstract In Service
3	UtilityPlantInServiceClassified Plant in Service (Classified)	7,630,043,940	7,630,043,940
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	28,482,207	28,482,207
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	1,128,090,081	1,128,090,081
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	8,786,616,228	8,786,616,228
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	4,941,592	4,941,592
11	ConstructionWorkInProgress Construction Work in Progress	836,188,274	836,188,274
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	1,845,431	1,845,431
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	9,629,591,525	9,629,591,525
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	2,284,845,318	2,284,845,318
15	UtilityPlantNet Net Utility Plant (13 less 14)	7,344,746,207	7,344,746,207
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	2,217,252,691	2,217,252,691
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	65,747,196	65,747,196
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	2,282,999,887	2,282,999,887
23	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract Leased to Others
24	DepreciationUtilityPlantLeasedToOthers Depreciation
25	AmortizationAndDepletionUtilityPlantLeasedToOthers Amortization and Depletion
26	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers Total Leased to Others (24 & 25)
27	DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract Held for Future Use
28	DepreciationUtilityPlantHeldForFutureUse Depreciation
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	1,845,431	1,845,431
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	2,284,845,318	2,284,845,318

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing arrangements.
Line No.	Description of item (a)	Balance Beginning of Year (b)	Changes during Year Additions (c)	Changes during Year Amortization (d)	Changes during Year Other Reductions (Explain in a footnote) (e)	Balance End of Year (f)
1	Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1)
2	Fabrication
3	Nuclear Materials
4	Allowance for Funds Used during Construction
5	(Other Overhead Construction Costs, provide details in footnote)
6	SUBTOTAL (Total 2 thru 5)
7	Nuclear Fuel Materials and Assemblies
8	In Stock (120.2)
9	In Reactor (120.3)
10	SUBTOTAL (Total 8 & 9)
11	Spent Nuclear Fuel (120.4)
12	Nuclear Fuel Under Capital Leases (120.6)
13	(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5)
14	TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13)
15	Estimated Net Salvage Value of Nuclear Materials in Line 9
16	Estimated Net Salvage Value of Nuclear Materials in Line 11
17	Est Net Salvage Value of Nuclear Materials in Chemical Processing
18	Nuclear Materials held for Sale (157)
19	Uranium
20	Plutonium
21	Other (Provide details in footnote)
22	TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21)

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Report below the original cost of electric plant in service according to the prescribed accounts. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent’s plant actually in service at end of year. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date.
Line No.	Account (a)	Balance Beginning of Year (b)	Additions (c)	Retirements (d)	Adjustments (e)	Transfers (f)	Balance at End of Year (g)
1	1. INTANGIBLE PLANT
2	(301) Organization	21,968					21,968
3	(302) Franchise and Consents
4	(303) Miscellaneous Intangible Plant	120,195,575	36,876,850	13,119,355		16,188	143,936,882
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	120,217,543	36,876,850	13,119,355		16,188	143,958,850
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	6,241,380					6,241,380
9	(311) Structures and Improvements	49,181,356	1,094,440	154,906			50,120,890
10	(312) Boiler Plant Equipment	177,260,037	924,241	547,439			177,636,839
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	65,129,400					65,129,400
13	(315) Accessory Electric Equipment	25,289,588	19,069	7,225			25,301,432
14	(316) Misc. Power Plant Equipment	7,201,391	32,914	4,676			7,229,629
15	(317) Asset Retirement Costs for Steam Production	20,417,918					20,417,918
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	350,721,070	2,070,664	714,246			352,077,488
17	B. Nuclear Production Plant
18	(320) Land and Land Rights
19	(321) Structures and Improvements
20	(322) Reactor Plant Equipment
21	(323) Turbogenerator Units
22	(324) Accessory Electric Equipment
23	(325) Misc. Power Plant Equipment
24	(326) Asset Retirement Costs for Nuclear Production
25	TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26	C. Hydraulic Production Plant
27	(330) Land and Land Rights
28	(331) Structures and Improvements
29	(332) Reservoirs, Dams, and Waterways
30	(333) Water Wheels, Turbines, and Generators
31	(334) Accessory Electric Equipment
32	(335) Misc. Power Plant Equipment
33	(336) Roads, Railroads, and Bridges
34	(337) Asset Retirement Costs for Hydraulic Production
35	TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)
36	D. Other Production Plant
37	(340) Land and Land Rights
38	(341) Structures and Improvements
39	(342) Fuel Holders, Products, and Accessories
40	(343) Prime Movers
41	(344) Generators
42	(345) Accessory Electric Equipment
43	(346) Misc. Power Plant Equipment
44	(347) Asset Retirement Costs for Other Production
44.1	(348) Energy Storage Equipment - Production
45	TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	350,721,070	2,070,664	714,246			352,077,488
47	3. Transmission Plant
48	(350) Land and Land Rights	88,165,125	19,046,806			3,944	107,215,875
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	26,458,672	31,266,871	258,834		345,971	57,812,680
50	(353) Station Equipment	1,571,251,725	243,376,164	9,862,775		163,586	1,804,601,528
51	(354) Towers and Fixtures	52,731,813	153,905	1,499,864		1,386,731	49,999,123
52	(355) Poles and Fixtures	709,012,095	236,613,093	10,151,637		1,549,245	937,022,796
53	(356) Overhead Conductors and Devices	578,557,288	124,106,182	5,518,560		88,500	697,056,410
54	(357) Underground Conduit	1,474,545	3,466,969	104,737			4,836,777
55	(358) Underground Conductors and Devices	25,504,173	122,047	537,246			25,088,974
56	(359) Roads and Trails	400,347				345,971	54,376
57	(359.1) Asset Retirement Costs for Transmission Plant
58	TOTAL Transmission Plant (Enter Total of lines 49 thru 59)	3,053,555,783	658,152,037	27,933,653		85,628	3,683,688,539
59	4. Distribution Plant
60	(360) Land and Land Rights	15,082,467	8,017,044			1	23,099,512
61	(361) Structures and Improvements	11,649,961	8,352,213	293,358		8,713	19,700,103
62	(362) Station Equipment	478,712,692	81,876,036	7,269,661			553,319,067
63	(363) Energy Storage Equipment – Distribution
64	(364) Poles, Towers, and Fixtures	765,944,187	96,709,572	10,342,645			852,311,114
65	(365) Overhead Conductors and Devices	678,372,476	78,267,950	7,570,487			749,069,939
66	(366) Underground Conduit	74,533,713	6,614,669	72,299			81,076,083
67	(367) Underground Conductors and Devices	320,001,339	30,117,072	1,820,396			348,298,015
68	(368) Line Transformers	666,273,054	53,792,808	20,379,542			699,686,320
69	(369) Services	288,525,299	16,356,218	1,064,560			303,816,957
70	(370) Meters	244,677,552	11,693,106	26,563,543			229,807,115
71	(371) Installations on Customer Premises	69,793,185	1,359,562	769,591			70,383,156
72	(372) Leased Property on Customer Premises	86,896					86,896
73	(373) Street Lighting and Signal Systems	100,444,698	9,777,684	2,627,200			107,595,182
74	(374) Asset Retirement Costs for Distribution Plant
75	TOTAL Distribution Plant (Enter Total of lines 62 thru 76)	3,714,097,519	402,933,934	78,773,282		8,712	4,038,249,459
76	5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77	(380) Land and Land Rights
78	(381) Structures and Improvements
79	(382) Computer Hardware
80	(383) Computer Software
81	(384) Communication Equipment
82	(385) Miscellaneous Regional Transmission and Market Operation Plant
83	(386) Asset Retirement Costs for Regional Transmission and Market Oper
84	TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85	6. General Plant
86	(389) Land and Land Rights	14,944,911		1,250		1	14,943,660
87	(390) Structures and Improvements	116,826,730	218,945,125	2,244,160			333,527,695
88	(391) Office Furniture and Equipment	4,033,045	3,432,097	319,399		16,188	7,161,931
89	(392) Transportation Equipment	283,186					283,186
90	(393) Stores Equipment	1,277,458	117,541	78,579			1,316,420
91	(394) Tools, Shop and Garage Equipment	44,649,539	4,280,614	165,217		85,628	48,850,564
92	(395) Laboratory Equipment	2,366,781					2,366,781
93	(396) Power Operated Equipment	225,097					225,097
94	(397) Communication Equipment	112,228,730	26,235,044	13,515,810			124,947,964
95	(398) Miscellaneous Equipment	4,898,367	268,664	3,216			5,163,815
96	SUBTOTAL (Enter Total of lines 86 thru 95)	301,733,844	253,279,085	16,327,631		101,815	538,787,113
97	(399) Other Tangible Property
98	(399.1) Asset Retirement Costs for General Plant	1,328,665	68,774	24,867			1,372,572
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	303,062,509	253,347,859	16,352,498		101,815	540,159,685
100	TOTAL (Accounts 101 and 106)	7,541,654,424	1,353,381,344	136,893,034		8,713	8,758,134,021
101	(102) Electric Plant Purchased (See Instr. 8)
102	(Less) (102) Electric Plant Sold (See Instr. 8)
103	(103) Experimental Plant Unclassified
104	TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)	7,541,654,424	1,353,381,344	136,893,034		8,713	8,758,134,021

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Line No.	LesseeName Name of Lessee (a)	IndicationOfAssociatedCompany * (Designation of Associated Company) (b)	LeaseDescription Description of Property Leased (c)	CommissionAuthorization Commission Authorization (d)	ExpirationDateOfLease Expiration Date of Lease (e)	ElectricPlantLeasedToOthers Balance at End of Year (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47	TOTAL

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.	ElectricPlantHeldForFutureUseDescription Description and Location of Property (a)	ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate Date Originally Included in This Account (b)	ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate Date Expected to be used in Utility Service (c)	ElectricPlantHeldForFutureUse Balance at End of Year (d)
1	Land and Rights:
2	James Rowe Substation, Hidalgo County, TX	(a) 08/01/2010	(e)	1,004,575
3	1.9 Acres (5132)
4	Marina 138/12kV Substation, Nueces County, TX	(b) 12/01/2015	(f)	272,883
5	1.962 Acres (5195)
6	Pantera 138kV Substation, Hidalgo County, TX	(c) 11/01/2017	(g)	287,810
7	6.480 Acres (5213)
8	Valadez 138kV Substation	(d) 04/01/2017	(h)	3,023,997
9	(5187)
10	Items under $250,000			352,327
21	Other Property:
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47	TOTAL			4,941,592

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate

Original value: 08/1/2010

(b) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate

Original value: 12/1/2015

Original value: 11/1/2017

(d) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate

Original value: 4/1/2017

(e) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate

Original value: 2021

(f) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate

Original value: 2019

(g) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate

Original value: 2023

(h) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate

Original value: 2019

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Report below descriptions and balances at end of year of projects in process of construction (107). Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts). Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line No.	ConstructionWorkInProgressProjectDescription Description of Project (a)	ConstructionWorkInProgress Construction work in progress - Electric (Account 107) (b)
1	Corpus Christi DDC - Fac Resil	1,557,159
2	Hebbronville SC - (New)	6,101,360
3	Purchase Office for Abilene T	1,078,176
4	Del Rio Service Ctr Relocation	1,232,719
5	Aransas Pass Service Center	5,388,327
6	Purch Land-Kingsville Laydown	2,081,676
7	Corpus Phase 0 D Station	1,664,234
8	Corpus Christi Network Remed	7,316,647
9	Victoria Network Remediation	1,129,317
10	Young - Property Purchase	1,847,854
11	Heines Sub-Purchase Property	1,147,333
12	Closner Sub - D-Station	1,363,286
13	Reading Sub D-Station	1,334,399
14	Stafford Hill D-Station	1,692,575
15	Asherton Sub D-Station	1,048,069
16	McColl Rd Sub - D-Station	3,070,268
17	Heines Sub- Dstation	1,159,246
18	Del Mar Sub - D-station	3,296,846
19	Valadez Sub - D-Station	2,318,564
20	Dustdevil Sub Purchase Propert	3,311,136
21	TCC Distr Pre Eng Parent	7,352,802
22	TCC Distr Pre Eng Parent	1,047,973
23	TCC/Network Monitor Design	2,623,681
24	Maximo Imp - TN - D	1,139,757
25	Maximo Imp - TC - T	2,893,011
26	Maximo Imp - TN - T	1,300,393
27	Maximo Imp - TC - D	3,894,908
28	TNC Next Generation Radio Sys	24,844,820
29	TCC Next Generation Radio Sys	19,419,537
30	Laredo Phase 0 D Station	1,984,756
31	RGV Phase 0 D Station	1,282,341
32	T/TCC/Transmission Work	1,281,427
33	TCC SCADA Upgrades	1,150,439
34	TCC SCADA Upgrades	1,364,574
35	TNC SCADA Upgrades	1,980,089
36	T/TCC/NERC Physical Security	11,308,135
37	T/TNC/NERC Physical Security	1,421,718
38	Trans station Renew-Refurb TCC	30,233,989
39	Trans station Renew-Refurb TNC	14,020,268
40	Trans Line Renew-Refurb TNC	1,092,223
41	T/TC/Telecom Modernization Pro	13,289,636
42	T/TN/Telecom Modernization Pro	1,946,804
43	D/TC/Telecom Modernization Pro	2,434,963
44	TNC Line Rebuild	65,154,303
45	TCC Line Rebuild	3,760,269
46	Fort Stockton to Rio Pecos 69	12,857,001
47	Concho to Miles 69 kV Line Reb	5,756,260
48	Cedar Hill to Miles 69 kV Line	23,222,363
49	Alice to Falfurrias 69 kV Line	12,098,890
50	Turtle Creek to Uvalde 69 kV L	16,968,275
51	Refugio to Tatton 69 kV Line R	20,528,525
52	Calallen to Stadium 69 kV Line	12,670,785
53	Sabinal to Uvalde 69 kV Line R	3,225,515
54	Blessing to Port Lavaca 69 kV	25,792,047
55	Pleasanton to Three Rivers 69	18,295,808
56	Childress to Quanah 69 kV Line	16,912,311
57	Cross Plains to Santa Anna 69	11,529,237
58	Concho to Live Oak 69 kV Line	7,466,991
59	Refugio to Rincon Line Rebuild	14,545,491
60	Lake Pauline to Vernon 69 kV L	4,748,257
61	Yellowjacket to Junction 69 kV	18,643,188
62	Ballinger to Eden 69kV Line Re	9,369,095
63	Friend Ranch to Sonora 69 kV L	14,995,002
64	Gregory to Rincon 69 kV Line R	4,358,221
65	Project Yosemite, Relocate lin	2,794,698
66	TCC Major Eq/Spares-Trans	1,729,111
67	TCC Major Eq/Spares- Distr	9,135,215
68	TNC Major Eq/Spares-Distr	2,516,506
69	Storm Recovery-Harvey	2,717,869
70	Storm Recovery-Harvey- DISTR	6,817,472
71	T/TCC/RTU Reliability	1,305,337
72	Trans station Renew-Refurb TCC	18,742,109
73	Trans station Renew-Refurb TNC	5,313,742
74	Dist station Renew-Refurb TCC	2,041,261
75	Dist Station renew-refurb TNC	1,650,925
76	TCC-T BlnktProj Under $3M	8,082,348
77	TNC-T-BlnktProj Under $3M	1,671,776
78	TCC-D BlnktProj Under $3M	1,550,940
79	T/TC/Capital Blanket - TCC	8,710,009
80	T/TN/Capital Blanket - TNC	1,283,990
81	D/TC/Capital Blanket - TCC	2,600,699
82	Whitepoint Station: Relay	1,961,337
83	TNC Transmission Work	5,196,440
84	TCC Transmission Work	51,317,010
85	TNC Transmission Work	3,337,054
86	TCC Transmission Work	1,282,200
87	Tortuga	3,069,592
88	TCC Transmission Work	1,175,376
89	Uvalde - Campwood 69kV line	4,356,081
90	Rose Rock Interconnection Perm	3,913,301
91	TCC Transmission Work	3,120,727
92	TCC Trans Work	1,610,202
93	Barrilla Improvements	16,455,713
94	Solstice - Bakersfield 345kV	1,711,221
95	Lynx: New 6bk station	8,143,796
96	Rebuild Lynx-Rio Pecos	2,123,879
97	Katz area improvements	8,810,307
98	TNC Transmission Work2	1,113,617
99	TNC Transmission Work	8,815,357
100	TCC Station Work	2,248,614
101	TNC Transmission Work	3,218,039
102	TCC Transmission Work	2,744,318
103	TNC Transmission	3,459,821
104	TNC Transmission	2,996,231
105	TCC Transmission Work	3,458,406
106	AEPTCC Transmission Work	2,169,534
107	AEPTN Trans Pre Eng Parent	7,322,192
108	SS-CI-CPLCo-D GEN PLT	3,754,304
109	TC-Reliability Improvement Blk	7,743,772
110	TC-Service Restoration Blkt	1,330,433
111	TC-Small Capacity Blkt	3,348,242
112	TN-Customer Service Blkt	2,582,428
113	TN-Reliability Improvement Blk	1,737,810
114	AEPTC-D Telecom	3,772,284
115	Other Minor Projects Which is under $1,000,000	72,629,120
43		836,188,274

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Explain in a footnote any important adjustments during year. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Line No.	Item (a)	Total (c + d + e) (b)	Electric Plant in Service (c)	Electric Plant Held for Future Use (d)	Electric Plant Leased To Others (e)
Section A. Balances and Changes During Year
1	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance Beginning of Year	2,126,347,537	2,126,347,537
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	247,316,811	247,316,811
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs	2,878,158	2,878,158
5	ExpensesOfElectricPlantLeasedToOthers (413) Exp. of Elec. Plt. Leas. to Others
6	TransportationExpensesClearing Transportation Expenses-Clearing
7	OtherClearingAccounts Other Clearing Accounts
8	OtherAccounts Other Accounts (Specify, details in footnote):
9.1		4,848,186	(a) 4,848,186
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	245,346,783	245,346,783
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	123,773,679	123,773,679
13	CostOfRemovalOfPlant Cost of Removal	40,617,514	(b) 40,617,514
14	SalvageValueOfRetiredPlant Salvage (Credit)	9,933,376	(c) 9,933,376
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	154,457,817	154,457,817
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1		16,188	(d) 16,188
18	BookCostOfAssetRetirementCosts Book Cost or Asset Retirement Costs Retired
19	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)	2,217,252,691	2,217,252,691
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	218,600,051	218,600,051
21	AccumulatedDepreciationNuclearProduction Nuclear Production
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage
24	AccumulatedDepreciationOtherProduction Other Production
25	AccumulatedDepreciationTransmission Transmission	560,797,069	560,797,069
26	AccumulatedDepreciationDistribution Distribution	1,293,435,868	1,293,435,868
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	144,419,703	144,419,703
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	2,217,252,691	2,217,252,691

FOOTNOTE DATA

(a) Concept: OtherAccounts

Depreciation expense on meters replaced by AMI meters. ($4,848,186)

(b) Concept: CostOfRemovalOfPlant

Includes ($8,941,547) of removal cost in retirement work in progress (RWIP).

Includes ($5,697,038) of salvage in retirement work in progress (RWIP).

(d) Concept: OtherAdjustmentsToAccumulatedDepreciation

Investment transferred between accounts. $16,188

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Report below investments in Account 123.1, Investments in Subsidiary Companies. Provide a subheading for each company and list thereunder the information called for below. Sub-TOTAL by company and give a TOTAL in columns (e), (f), (g) and (h). (a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity, and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number. Report column (f) interest and dividend revenues from investments, including such revenues from securities disposed of during the year. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost) and the selling price thereof, not including interest adjustment includible in column (f). Report on Line 42, column (a) the TOTAL cost of Account 123.1.
Line No.	DescriptionOfInvestmentsInSubsidiaryCompanies Description of Investment (a)	DateOfAcquisitionInvestmentsInSubsidiaryCompanies Date Acquired (b)	DateOfMaturityInvestmentsInSubsidiaryCompanies Date of Maturity (c)	InvestmentInSubsidiaryCompanies Amount of Investment at Beginning of Year (d)	EquityInEarningsOfSubsidiaryCompanies Equity in Subsidiary Earnings of Year (e)	InterestAndDividendRevenueFromInvestments Revenues for Year (f)	InvestmentInSubsidiaryCompanies Amount of Investment at End of Year (g)	InvestmentGainLossOnDisplosal Gain or Loss from Investment Disposed of (h)
1	AEP Texas Central Transition Funding, LLC.	(a)		4,499,680			4,499,680
2	SUBTOTAL			4,499,680			4,499,680
3	AEP Texas Central Transition Funding II, LLC.	(b)		9,630,093	98,309		9,728,402
4	SUBTOTAL			9,630,093	98,309		9,728,402
5	AEP Texas Central Transition Funding III, LLC.	(c)		4,041,016	62,164		4,103,179
6	SUBTOTAL			4,041,016	62,164		4,103,179
7	AEP Texas North Generation Company, LLC	(d)		7,320,453	215,082		7,105,371
8	SUBTOTAL			7,320,453	215,082		7,105,371
42	Total Cost of Account 123.1 $		Total	25,491,242	54,609		25,436,632

FOOTNOTE DATA

(a) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies

Original value: 02/2002

(b) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies

Original value: 10/2006

Original value: 02/2012

(d) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies

Original value: 08/2006

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

MATERIALS AND SUPPLIES
For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a); estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if applicable.
Line No.	Account (a)	Balance Beginning of Year (b)	Balance End of Year (c)	Department or Departments which Use Material (d)
1	Fuel Stock (Account 151)	3,438,722	8,667,188	Electric
2	Fuel Stock Expenses Undistributed (Account 152)	142,942	158,854	Electric
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	44,244,907	45,607,378	Electric
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	3,850,140	3,875,783	Electric
8	Transmission Plant (Estimated)	1,760,493	981,670	Electric
9	Distribution Plant (Estimated)	2,059,391	2,161,107	Electric
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)	(a) 129,807	170,397	Electric
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	52,044,738	52,796,335	Electric
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)
15	Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16	Stores Expense Undistributed (Account 163)
17
18
19
20	TOTAL Materials and Supplies	55,626,402	61,622,377

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: PlantMaterialsAndOperatingSuppliesOther

This footnote applies to both current and prior year.

Assigned to - Other: Includes Customer Accounts and Administrative and General Expenses.

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	SO2 Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)
5	Returned by EPA
6
7
8	Purchases/Transfers:
9
10
11
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509
19	Other:
20	Allowances Used
20.1
20.2
21	Cost of Sales/Transfers:
22
23
24
25
26
27
28	Total
29	Balance-End of Year
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)
34	Gains
35	Losses
	Allowances Withheld (Acct 158.2)
36	Balance-Beginning of Year	30		30		30		30		2,996		3,116
37	Add: Withheld by EPA									30		30
38	Deduct: Returned by EPA
39	Cost of Sales	30								15		45
40	Balance-End of Year			30		30		30		3,011		3,101
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)			1								1
44	Net Sales Proceeds (Other)			1								1
45	Gains
46	Losses

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	NOx Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year	7,477										7,477
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	7,477										7,477
5	Returned by EPA
6
7
8	Purchases/Transfers:
9
10
11
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509
19	Other:
20	Allowances Used
20.1
20.2
21	Cost of Sales/Transfers:
22
23
24
25
26
27
28	Total
29	Balance-End of Year	14,954										14,954
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)
34	Gains
35	Losses
	Allowances Withheld (Acct 158.2)
36	Balance-Beginning of Year
37	Add: Withheld by EPA
38	Deduct: Returned by EPA
39	Cost of Sales
40	Balance-End of Year
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfExtraordinaryPropertyLoss Description of Extraordinary Loss [Include in the description the date of Commission Authorization to use Acc 182.1 and period of amortization (mo, yr to mo, yr).] (a)	ExtraordinaryPropertyLossesNotYetRecognized Total Amount of Loss (b)	ExtraordinaryPropertyLossesRecognized Losses Recognized During Year (c)	ExtraordinaryPropertyLossesWrittenOffAccountCharged Account Charged (d)	ExtraordinaryPropertyLossesWrittenOff Amount (e)	ExtraordinaryPropertyLosses Balance at End of Year (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
20	TOTAL

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfUnrecoveredPlantAndRegulatoryStudyCosts Description of Unrecovered Plant and Regulatory Study Costs [Include in the description of costs, the date of COmmission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)] (a)	UnrecoveredPlantAndRegulatoryStudyCostsNotYetRecognized Total Amount of Charges (b)	UnrecoveredPlantAndRegulatoryStudyCostsRecognized Costs Recognized During Year (c)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOffAccountCharged Account Charged (d)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOff Amount (e)	UnrecoveredPlantAndRegulatoryStudyCosts Balance at End of Year (f)
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49	TOTAL

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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	Electric Reliability Council of
3	(a) Texas (ERCOT) - 11AEPSC001	14,869	186
4	11INR0054	55,017	186	80,000	186
5	11INR0062	126,961	186
6	11INR0062(a1)	5,716	186	60,000	186
7	12INR0045	37,306	186
8	13INR0055	256	186
9	14INR0013			1,701	186
10	14INR0040	11,862	186
11	14INR0041	162	186
12	15INR0021	28,150	186
13	15INR0034	624	186
14	15INR0045	768	186
15	15INR0054	40,485	186
16	15INR0059	8,703	186
17	15INR0061	256	186
18	15INR0069	24,665	186
19	16INR0048	256	186
20	16INR0052	256	186
21	16INR0086	1,537	186
22	16INR0101	256	186
23	16INR0105	256	186
24	17INR0031	1,024	186
25	17INR0035	39,162	186	80,000	186
26	17INR0045	2,891	186
27	17INR0052	1,459	186
28	18INR0014	22,165	186	80,000	186
29	18INR0027	801	186
30	18INR0035	6,770	186
31	18INR0058	12,100	186
32	18INR0059	11,906	186	80,000	186
33	18INR0060	4,899	186
34	18INR0061	6,937	186
35	18INR0079	12,564	186	125,000	186
36	19INR0006	1,832	186
37	19INR0014	10,002	186
38	19INR0022	12,634	186
39	19INR0035			65,000	186
40	19INR0045	5,525	186
41	19INR0049			65,000	186
42	19INR0057	3,744	186	65,000	186
43	19INR0073	4,995	186
44	19INR0074	10,789	186	145,000	186
45	19INR0108	4,998	186	145,000	186
46	19INR0111			65,000	186
47	19INR0122	22,558	186	145,000	186
48	19INR0138			65,000	186
49	19INR0150			65,000	186
50	19INR0171	5,578	186	65,000	186
51	19INR0177			65,000	186
52	19INR0113	256	186	62,500	186
53	20INR0012	256	186	65,000	186
54	20INR0013	807	186	65,000	186
55	20INR0014	276	186	65,000	186
56	20INR0016	256	186	65,000	186
57	20INR0036			65,000	186
58	20INR0042	21,076	186	65,000	186
59	20INR0053			65,000	186
60	20INR0054	16,445	186	70,000	186
61	20INR0055			65,000	186
20	Total
21	Generation Studies
39	Total
40	Grand Total

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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 Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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	SFAS 109 Deferred FIT	14,749,162	3,858,531	282 / 283		18,607,693
2	SFAS 109 Deferred SIT	27,161,048	68,011	282 / 283		27,229,059
3	SFAS 106 Medicare Subsidy (Amortization
4	period Jan 2013 - Dec 2024)	4,873,828		926	696,261	4,177,567
5	Under-recovery of Energy Efficiency
6	Program Expenses - as approved by PUCT
7	Docket (updated annually)	3,685,219	6,342,992	456 / 907	7,578,177	2,450,034
8	Various Rate Case Expenses pending
9	future PUCT (Public Utility Commission of Texas)
10	approval for collection from customers.	149,525	11,123			160,648
11	SFAS 158 Employers' Accounting for Defined Benefit			129 / 165
12	Pension and Other Postretirement Plans	151,160,454	33,366,488	& 2283	7,659,404	176,867,538
13	Deferred Equity Return and other Competition
14	Transition Charge (CTC) items relating to TCC's
15	Securitization filing - Amortized over 14 years
16	beginning October 2006. Various Dockets
17	including TCC's Securitization Docket #32475
18	and CTC Docket #32758	21,694,308	23,643,420	4073	33,014,322	12,323,406
19	Reserve for Catastrophe for storm recovery.
20	Currently funded at an annual rate of
21	$1.3M per yar. Updated last on
22	PUCT Docket #33309.	123,298,991	30,450,600	924	1,300,000	152,449,591
23	Advanced Metering Systems O&M expenses to be
24	recovered over 11 years beginning in 2010
25	as approved in PUCT Docket #36928	629,150		586	209,616	419,534
26	Advanced Metering Systems Existing Meter Investment
27	of "old meters retired" and replaced by "Advanced
28	Meters" as approved in PUCT Docket #36928	44,926,765		403	4,848,186	40,078,579
29	Under-recovery of Transmission Cost
30	Recovery Factor - as approved by
31	PUCT Dockey (updated semiannually)	9,460,892	12,792,059	565	20,527,562	1,725,389
32	Under-recovery of Advanced Metering Systems
33	Expense as approved in PUCT Docket #36928	32,863,914	12,044,297			44,908,211
34	Restructuring Costs - Unamortized Loss on
35	Reacquired Long-Term Debt - Amortized over
36	15 years beginning July 2002
37	Docket # 22352 (Central)	89,118		4073	70,880	18,238
38	Unrealized Gain/Loss on Forward
39	Commitments		728,659			728,659
44	TOTAL	434,742,374	123,306,180		75,904,408	482,144,146

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

MISCELLANEOUS DEFFERED DEBITS (Account 186)
Report below the particulars (details) called for concerning miscellaneous deferred debits. For any deferred debit being amortized, show period of amortization in column (a) Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by classes.
				CREDITS
Line No.	Description of Miscellaneous Deferred Debits (a)	Balance at Beginning of Year (b)	Debits (c)	Credits Account Charged (d)	Credits Amount (e)	Balance at End of Year (f)
1	Associated Business Development	517,186	11,422,607	Various	10,878,540	1,061,253
2	Unamortized Credit Line Fees
3	Amortization period through
4	June 2022	524,407	510,250	431	202,023	832,634
5	Deferred Lease Assets	347,850	1,409,910	Various	1,185,640	572,120
6	Death Benefits Paid Related to
7	CSW's Memorial Paired Program
8	Minor Items < $100,000 or 1%	12,155	11,222	Various	21,733	1,644
47	Miscellaneous Work in Progress
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49	TOTAL	1,401,598				2,467,651

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Report the information called for below concerning the respondent’s accounting for deferred income taxes. At Other (Specify), include deferrals relating to other income and deductions.
Line No.	DescriptionOfAccumulatedDeferredIncomeTax Description and Location (a)	AccumulatedDeferredIncomeTaxes Balance at Beginning of Year (b)	AccumulatedDeferredIncomeTaxes Balance at End of Year (c)
1	Electric
2	Deferred Revenues - Oklaunion Lease	18,181,032	4,637,124
3	Accrd Book ARO Expense - SFAS 143	9,147,808	5,743,220
4	O/U Recovery Securitization Revenue	16,113,714	9,652,252
5	Defd Revenues - Defd Equity Return - SEC	21,142,303	7,777,131
6	Securitization Defd Equity Income - Long Term	18,882,156	9,804,914
7
8
7	Other	20,635,536	17,424,812
8	TOTAL Electric (Enter Total of lines 2 thru 7)	62,831,477	55,039,453
9	Other (Specify)
10
11
12
13
14
15	Other
16	TOTAL Gas (Enter Total of lines 10 thru 15)
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	220,717,834	207,916,285

Notes

Footnote Page 234, Line 17 - Columns (b) & (c) Beg of Year End of Year Accumulated Deferred Income Taxes - Federal - Hdg-CF-Int Rate 1,450,350 1,169,637 Non Utility Items - 190.2 1,530,348 (401,711) SFAS 109 - Regulatory Assets - 190.3 & 190.4 152,269,223 149,251,923 Accumulated Deferred Income Taxes - Federal - Pension - OCI 2,636,436 2,850,984 ------------- -------------- Total Other 157,886,357 152,876,832

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

CAPITAL STOCKS (Account 201 and 204)
Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year. Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative. State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purpose of pledge.
Line No.	Class and Series of Stock and Name of Stock Series (a)	Number of Shares Authorized by Charter (b)	Par or Stated Value per Share (c)	Call Price at End of Year (d)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Shares (e)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Amount (f)	Held by Respondent As Reacquired Stock (Acct 217) Shares (g)	Held by Respondent As Reacquired Stock (Acct 217) Cost (h)	Held by Respondent In Sinking and Other Funds Shares (i)	Held by Respondent In Sinking and Other Funds Amount (j)
1	Common Stock (Account 201)
2
3
4
5	Total
6	Preferred Stock (Account 204)
7
8
9
10	Total
1	Capital Stock (Accounts 201 and 204) - Data Conversion
2
3
4
5	Total

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

Other Paid-in Capital
1. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change. Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation. Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class and series of stock to which related. Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210) - Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related. Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts.
Line No.	Item (a)	Amount (b)
1	DonationsReceivedFromStockholdersAbstract Donations Received from Stockholders (Account 208)
2	DonationsReceivedFromStockholders Beginning Balance Amount
3	IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders Increases (Decreases) from Sales of Donations Received from Stockholders
4	DonationsReceivedFromStockholders Ending Balance Amount
5	ReductionInParOrStatedValueOfCapitalStockAbstract Reduction in Par or Stated Value of Capital Stock (Account 209)
6	ReductionInParOrStatedValueOfCapitalStock Beginning Balance Amount
7	IncreasesDecreasesDueToReductionsInParOrStatedValueOfCapitalStock Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
8	ReductionInParOrStatedValueOfCapitalStock Ending Balance Amount
9	GainOrResaleOrCancellationOfReacquiredCapitalStockAbstract Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
10	GainOnResaleOrCancellationOfReacquiredCapitalStock Beginning Balance Amount
11	IncreasesDecreasesFromGainOrResaleOrCancellationOfReacquiredCapitalStock Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12	GainOnResaleOrCancellationOfReacquiredCapitalStock Ending Balance Amount
13	MiscellaneousPaidInCapitalAbstract Miscellaneous Paid-In Capital (Account 211)
14	MiscellaneousPaidInCapital Beginning Balance Amount
15	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital
16	MiscellaneousPaidInCapital Ending Balance Amount
17	OtherPaidInCapitalAbstract Histrocal Data - Other Paid in Capital
18	OtherPaidInCapitalDetail Beginning Balance Amount
19.1	IncreasesDecreasesInOtherPaidInCapital Donations Received from Stockholders (Account 208)
19.2	IncreasesDecreasesInOtherPaidInCapital Beginning Balance	1,058,164,804
19.3	IncreasesDecreasesInOtherPaidInCapital Capital Contribution from Parent	200,000,000
19.4	IncreasesDecreasesInOtherPaidInCapital Subtotal - Account 208	1,258,164,804
19.5	IncreasesDecreasesInOtherPaidInCapital Reduction In Par or Stated Value of Capital Stock (Account 209) - None
19.6	IncreasesDecreasesInOtherPaidInCapital Gain on Resale or Cancellation of Reaquired Capital Stock (Acct 210)
19.7	IncreasesDecreasesInOtherPaidInCapital Reacquired Capital StocK (Account 210)	13,116
19.8	IncreasesDecreasesInOtherPaidInCapital Reacquired Preferred Stock (Account 210)	230,126
19.9	IncreasesDecreasesInOtherPaidInCapital Subtotal - Account 210	217,010
19.10	IncreasesDecreasesInOtherPaidInCapital Miscellaneous Paid-In Capital (Account 211)
20	OtherPaidInCapitalDetail Ending Balance Amount
40	OtherPaidInCapital Total	1,257,947,794

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

CAPITAL STOCK EXPENSE (Account 214)
Report the balance at end of the year of discount on capital stock for each class and series of capital stock. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line No.	NameOfClassAndSeriesOfStock Class and Series of Stock (a)	CapitalStockExpense Balance at End of Year (b)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22	TOTAL

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

LONG-TERM DEBT (Account 221, 222, 223 and 224)
Report by Balance Sheet Account the details concerning long-term debt included in Account 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other Long-Term Debt. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds. For Advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued. In a supplemental statement, give explanatory details for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a)principal advanced during year (b) interest added to principal amount, and (c) principal repaid during year. Give Commission authorization numbers and dates. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (f). Explain in a footnote any difference between the total of column (f) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line No.	ClassAndSeriesOfObligationCouponRateDescription Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates) (a)	RelatedAccountNumber Related Account Number (b)	Principal Amount of Debt Issued (c)	LongTermDebtIssuanceExpensePremiumOrDiscount Total Expense, Premium or Discount (d)	LongTermDebtIssuanceExpenses Total Expense (e)	LongTermDebtPremium Total Premium (f)	LongTermDebtDiscount Total Discount (g)	NominalDateOfIssue Nominal Date of Issue (h)	DateOfMaturity Date of Maturity (i)	AmortizationPeriodStartDate AMORTIZATION PERIOD Date From (j)	AmortizationPeriodEndDate AMORTIZATION PERIOD Date To (k)	Outstanding (Total amount outstanding without reduction for amounts held by respondent) (l)	Interest for Year Amount (m)
1	Bonds (Account 221)
2
3
4
5	Subtotal
6	Reacquired Bonds (Account 222)
7
8
9
10	Subtotal
11	Advances from Associated Companies (Account 223)
12
13
14
15	Subtotal
16	Other Long Term Debt (Account 224)
17
18
19
20	Subtotal											3,114,186,630
Long Term Debt (Historical Data)
1	Total Account 221
2	Total Account 222
3	Account 223 - Advances from Associated Companies - None
4	Account 224 - Other Long-Term Debt
5	Pollution Control Bonds:
6	Series 1996, 4.45% - (Red River) (Issued 06-2007)		6,330,000	95,403				(l) 06/07/2007	(ap) 06/01/2020	(bt) 06/07/2007	(cx) 06/01/2020	6,330,000	281,685
7	(a) Series 1996, Matagorda Remarketing, 1.75% (Issued 08-21-2017)		60,000,000	439,654				(m) 08/21/2017	(aq) 05/01/2030	(bu) 08/21/2017	(cy) 09/01/2020	60,000,000	1,050,000
8				1,200,000
9	(b) Series 2001A, 6.3% - (Matagorda)		100,635,000	845,451				(n) 07/01/2009	(ar) 11/01/2029	(bv) 07/01/2009	(cz) 11/01/2029	100,635,000	6,340,005
10	(c) Series 2005A, 4.4% - (Matagorda)		111,700,000	1,277,849				(o) 12/06/2006	(as) 05/01/2030	(bw) 03/16/2005	(da) 05/01/2030	111,700,000	4,914,800
11	(d) Series 2005B, 4.55% - (Matagorda)		50,000,000	552,686				(p) 12/06/2006	(at) 05/01/2030	(bx) 03/16/2005	(db) 05/01/2030	50,000,000	2,275,000
12	(e) Series 2008 - 1&2, Matagorda Remarketing, 4.0% (Issued 6-3-2013)		120,265,000	776,485				(q) 06/03/2013	(au) 06/01/2030	(by) 06/03/2013	(dc) 06/01/2030	120,265,000	4,810,600
13	Red River, 4.45% (Issued 06-2007)		44,310,000	673,131				(r) 06/07/2007	(av) 06/01/2020	(bz) 06/07/2007	(dd) 06/01/2020	44,310,000	1,971,795
14	(f)
15	Private Placement Notes:
16	Series B, 6.76%		1,600,000	(j) 457,765				(s) 04/01/2008	(aw) 04/01/2038	(ca) 04/01/2008	(de) 04/01/2038	1,600,000	108,160
17	Series B, 6.76%		12,700,000					(t) 04/01/2008	(ax) 04/01/2038	(cb) 04/01/2008	(df) 04/01/2038	12,700,000	858,520
18	Series B, 6.76%		13,700,000					(u) 04/01/2008	(ay) 04/01/2038	(cc) 04/01/2008	(dg) 04/01/2038	13,700,000	926,120
19	Series B, 6.76%		35,000,000					(v) 04/01/2008	(az) 04/01/2038	(cd) 04/01/2008	(dh) 04/01/2038	35,000,000	2,366,000
20	Series B, 6.76%		7,000,000					(w) 04/01/2008	(ba) 04/01/2038	(ce) 04/01/2008	(di) 04/01/2038	7,000,000	473,200
21	(g) Series A, 5.89%		30,000,000	196,185				(x) 04/01/2008	(bb) 04/02/2018	(cf) 04/01/2008	(dj) 04/02/2018		441,750
22	Other Long-Term Debt:
23	Texas Local Revolving Credit Facility		125,000,000	495,556				(y) 07/25/2016	(bc) 07/31/2019	(cg) 08/01/2016	(dk) 07/31/2019	125,000,000	4,482,639
24	Texas Local Revolving Credit Facility		75,000,000	285,761				(z) 07/25/2016	(bd) 07/31/2019	(ch) 08/01/2016	(dl) 07/31/2019	75,000,000	2,689,583
25	(h) Goodfellow Air Force Base - 4.5%		946,630					(aa) 12/01/2009	(be) 11/01/2059	(ci) 12/01/2009	(dm) 11/01/2059	946,630	42,791
26	Senior Unsecured Notes:
27	Series C, 3.09%		125,000,000	597,741				(ab) 02/28/2013	(bf) 02/28/2023	(cj) 02/28/2013	(dn) 02/28/2023	125,000,000	3,862,500
28	Series C - Financial Hedges												1,336,728
29	Series D, 4.48%		75,000,000	358,644				(ac) 02/27/2013	(bg) 02/27/2043	(ck) 02/27/2013	(do) 02/27/2043	75,000,000	3,360,000
30	Series E, 3.27%		25,000,000	126,464				(ad) 09/30/2015	(bh) 09/30/2022	(cl) 09/30/2015	(dp) 09/30/2022	25,000,000	817,500
31	Series F, 3.75%		50,000,000	252,928				(ae) 09/30/2015	(bi) 09/30/2025	(cm) 09/30/2015	(dq) 09/30/2025	50,000,000	1,875,000
32	Series G, 4.71%		50,000,000	252,928				(af) 12/15/2015	(bj) 12/15/2035	(cn) 12/15/2015	(dr) 12/15/2035	50,000,000	2,355,000
33	Series E (formerly B) 6.65% Notes		275,000,000	2,504,241				(ag) 02/18/2003	(bk) 02/15/2033	(co) 03/01/2003	(ds) 02/15/2033	275,000,000	18,287,500
34				1,342,000
35	Series A, 2.61%		50,000,000					(ah) 04/30/2014	(bl) 04/30/2019	(cp) 04/30/2014	(dt) 04/30/2019	50,000,000	1,305,000
36	Series B, 3.81%		50,000,000					(ai) 04/30/2014	(bm) 04/30/2026	(cq) 04/30/2014	(du) 04/30/2026	50,000,000	1,905,000
37	Series C, 4.67%		100,000,000					(aj) 04/30/2014	(bn) 04/30/2044	(cr) 04/30/2014	(dv) 04/30/2044	100,000,000	4,670,000
38	Series D, 4.77%		100,000,000	(k) 1,454,317				(ak) 10/30/2014	(bo) 10/30/2044	(cs) 10/30/2014	(dw) 10/30/2044	100,000,000	4,770,000
39	Series G, 3.85%		250,000,000	1,864,770				(al) 09/18/2015	(bp) 10/01/2025	(ct) 09/18/2015	(dx) 10/01/2025	250,000,000	9,625,000
40				2,447,500
41	Series A, 2.4%		400,000,000	3,047,760				(am) 09/22/2017	(bq) 10/01/2022	(cu) 09/22/2017	(dy) 10/01/2022	400,000,000	9,600,000
42	(FERC Authority ES16-47-000)			696,000
43	Series B, 3.8%		300,000,000	3,129,449				(an) 09/22/2017	(br) 10/01/2047	(cv) 09/22/2017	(dz) 10/01/2047	300,000,000	11,400,000
44	(FERC Authority ES16-47-000)			3,450,000
45	(i) Series E, 3.95%		500,000,000	3,922,721				(ao) 05/17/2018	(bs) 06/01/2028	(cw) 05/17/2018	(ea) 06/01/2028	500,000,000	12,288,890
46	(FERC Authority ES18-22-000)			1,650,000
33	TOTAL		3,144,186,630	31,993,389								3,114,186,630	121,490,766

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: ClassAndSeriesOfObligationCouponRateDescription

In August 2017, AEP Texas remarketed its Series 1996 Matagorda Pollution Control Revenue Bonds (PCRBs) from 5.20% to 1.75% fixed rate. Column (C) amount includes remarketing issuance costs. There was $992,572 of unamortized issuance costs and discount when remarketed.

(b) Concept: ClassAndSeriesOfObligationCouponRateDescription

In July 2009, TCC remarketed its Series 2001A Matagorda Pollution Control Bonds (PCRBs) from 4.55% to 6.30% fixed rate. Column ( C ) amount includes remarketing issuance costs.

In December 2006, TCC remarketed its Series 2005A Matagorda Pollution Control Bonds (PCRBs) from a vraiable rate to 4.40% fixed rate. Column ( C ) amount includes remarketing issuance costs.

(d) Concept: ClassAndSeriesOfObligationCouponRateDescription

In December 2006, TCC remarketed its Series 2005B Matagorda Pollution Control Bonds (PCRBs) from a variable rate to 4.55% fixed rate. Column ( C ) amount includes remarketing issuance costs.

(e) Concept: ClassAndSeriesOfObligationCouponRateDescription

In July 2013, TCC remarketed its Series 2008 Matagorda Pollution Control Bonds (PCRBs) from a variable weekly rate to a 4.00% fixed rate. Column ( C ) amount includes remarketing issuance costs.

(f) Concept: ClassAndSeriesOfObligationCouponRateDescription

The Series 2008, 5.625% (Guadalupe/Blanco) was retired on 10/2/2017. There were no unamortized amounts related to this issuance.

(g) Concept: ClassAndSeriesOfObligationCouponRateDescription

The Series A, 5.89% was retired on 4/01/2018. There were no unamortized amounts related to this issuance.

(h) Concept: ClassAndSeriesOfObligationCouponRateDescription

This is long term debt related to AEP Texas North Company's purchase of the Goodfellow Air Force Base Electric Distribution System, to be paid over a 50 year period.

(i) Concept: ClassAndSeriesOfObligationCouponRateDescription

In May 2018, new Issuance for AEP Texas Series E Unsecured Notes 3.95% for $500,000,000 with maturity date June 2028.

(j) Concept: LongTermDebtIssuanceExpensePremiumOrDiscount

The issuance expense amount of $457,765 is the total expense amount for all five Series B Private Placement Notes. The total principal for the five Series B placement notes total $70,000,000. The issuance expenses are not kept separate for each individual private placement holder.

(k) Concept: LongTermDebtIssuanceExpensePremiumOrDiscount

The "Issuance Costs" reported in Column ( C ) for Series D Unsecured Notes, issued in 2014, are actually for "all four Series Notes issued in 2014" (including Series A 2.61%, Series B 3.81%, Series C 4.67%, and Series D 4.77%).

(l) Concept: NominalDateOfIssue

Original value: 06/07/2007

(m) Concept: NominalDateOfIssue

Original value: 08/21/2017

(n) Concept: NominalDateOfIssue

Original value: 07/01/2009

(o) Concept: NominalDateOfIssue

Original value: 12/06/2006

(p) Concept: NominalDateOfIssue

Original value: 12/06/2006

(q) Concept: NominalDateOfIssue

Original value: 06/03/2013

(r) Concept: NominalDateOfIssue

Original value: 06/07/2007

(s) Concept: NominalDateOfIssue

Original value: 04/01/2008

(t) Concept: NominalDateOfIssue

Original value: 04/01/2008

(u) Concept: NominalDateOfIssue

Original value: 04/01/2008

(v) Concept: NominalDateOfIssue

Original value: 04/01/2008

(w) Concept: NominalDateOfIssue

Original value: 04/01/2008

(x) Concept: NominalDateOfIssue

Original value: 04/01/2008

(y) Concept: NominalDateOfIssue

Original value: 07/25/2016

(z) Concept: NominalDateOfIssue

Original value: 07/25/2016

(aa) Concept: NominalDateOfIssue

Original value: 12/01/2009

(ab) Concept: NominalDateOfIssue

Original value: 02/28/2013

(ac) Concept: NominalDateOfIssue

Original value: 02/27/2013

(ad) Concept: NominalDateOfIssue

Original value: 09/30/2015

(ae) Concept: NominalDateOfIssue

Original value: 09/30/2015

(af) Concept: NominalDateOfIssue

Original value: 12/15/2015

(ag) Concept: NominalDateOfIssue

Original value: 02/18/2003

(ah) Concept: NominalDateOfIssue

Original value: 04/30/2014

(ai) Concept: NominalDateOfIssue

Original value: 04/30/2014

(aj) Concept: NominalDateOfIssue

Original value: 04/30/2014

(ak) Concept: NominalDateOfIssue

Original value: 10/30/2014

(al) Concept: NominalDateOfIssue

Original value: 09/18/2015

(am) Concept: NominalDateOfIssue

Original value: 09/22/2017

(an) Concept: NominalDateOfIssue

Original value: 09/22/2017

(ao) Concept: NominalDateOfIssue

Original value: 05/17/2018

(ap) Concept: DateOfMaturity

Original value: 06/01/2020

(aq) Concept: DateOfMaturity

Original value: 05/01/2030

(ar) Concept: DateOfMaturity

Original value: 11/01/2029

(as) Concept: DateOfMaturity

Original value: 05/01/2030

(at) Concept: DateOfMaturity

Original value: 05/01/2030

(au) Concept: DateOfMaturity

Original value: 06/01/2030

(av) Concept: DateOfMaturity

Original value: 06/01/2020

(aw) Concept: DateOfMaturity

Original value: 04/01/2038

(ax) Concept: DateOfMaturity

Original value: 04/01/2038

(ay) Concept: DateOfMaturity

Original value: 04/01/2038

(az) Concept: DateOfMaturity

Original value: 04/01/2038

(ba) Concept: DateOfMaturity

Original value: 04/01/2038

(bb) Concept: DateOfMaturity

Original value: 04/02/2018

(bc) Concept: DateOfMaturity

Original value: 07/31/2019

(bd) Concept: DateOfMaturity

Original value: 07/31/2019

(be) Concept: DateOfMaturity

Original value: 11/01/2059

(bf) Concept: DateOfMaturity

Original value: 02/28/2023

(bg) Concept: DateOfMaturity

Original value: 02/27/2043

(bh) Concept: DateOfMaturity

Original value: 09/30/2022

(bi) Concept: DateOfMaturity

Original value: 09/30/2025

(bj) Concept: DateOfMaturity

Original value: 12/15/2035

(bk) Concept: DateOfMaturity

Original value: 02/15/2033

(bl) Concept: DateOfMaturity

Original value: 04/30/2019

(bm) Concept: DateOfMaturity

Original value: 04/30/2026

(bn) Concept: DateOfMaturity

Original value: 04/30/2044

(bo) Concept: DateOfMaturity

Original value: 10/30/2044

(bp) Concept: DateOfMaturity

Original value: 10/01/2025

(bq) Concept: DateOfMaturity

Original value: 10/01/2022

(br) Concept: DateOfMaturity

Original value: 10/01/2047

(bs) Concept: DateOfMaturity

Original value: 06/01/2028

(bt) Concept: AmortizationPeriodStartDate

Original value: 06/07/2007

(bu) Concept: AmortizationPeriodStartDate

Original value: 08/21/2017

(bv) Concept: AmortizationPeriodStartDate

Original value: 07/01/2009

(bw) Concept: AmortizationPeriodStartDate

Original value: 03/16/2005

(bx) Concept: AmortizationPeriodStartDate

Original value: 03/16/2005

(by) Concept: AmortizationPeriodStartDate

Original value: 06/03/2013

(bz) Concept: AmortizationPeriodStartDate

Original value: 06/07/2007

(ca) Concept: AmortizationPeriodStartDate

Original value: 04/01/2008

(cb) Concept: AmortizationPeriodStartDate

Original value: 04/01/2008

(cc) Concept: AmortizationPeriodStartDate

Original value: 04/01/2008

(cd) Concept: AmortizationPeriodStartDate

Original value: 04/01/2008

(ce) Concept: AmortizationPeriodStartDate

Original value: 04/01/2008

(cf) Concept: AmortizationPeriodStartDate

Original value: 04/01/2008

(cg) Concept: AmortizationPeriodStartDate

Original value: 08/01/2016

(ch) Concept: AmortizationPeriodStartDate

Original value: 08/01/2016

(ci) Concept: AmortizationPeriodStartDate

Original value: 12/01/2009

(cj) Concept: AmortizationPeriodStartDate

Original value: 02/28/2013

(ck) Concept: AmortizationPeriodStartDate

Original value: 02/27/2013

(cl) Concept: AmortizationPeriodStartDate

Original value: 09/30/2015

(cm) Concept: AmortizationPeriodStartDate

Original value: 09/30/2015

(cn) Concept: AmortizationPeriodStartDate

Original value: 12/15/2015

(co) Concept: AmortizationPeriodStartDate

Original value: 03/01/2003

(cp) Concept: AmortizationPeriodStartDate

Original value: 04/30/2014

(cq) Concept: AmortizationPeriodStartDate

Original value: 04/30/2014

(cr) Concept: AmortizationPeriodStartDate

Original value: 04/30/2014

(cs) Concept: AmortizationPeriodStartDate

Original value: 10/30/2014

(ct) Concept: AmortizationPeriodStartDate

Original value: 09/18/2015

(cu) Concept: AmortizationPeriodStartDate

Original value: 09/22/2017

(cv) Concept: AmortizationPeriodStartDate

Original value: 09/22/2017

(cw) Concept: AmortizationPeriodStartDate

Original value: 05/17/2018

(cx) Concept: AmortizationPeriodEndDate

Original value: 06/01/2020

(cy) Concept: AmortizationPeriodEndDate

Original value: 09/01/2020

(cz) Concept: AmortizationPeriodEndDate

Original value: 11/01/2029

(da) Concept: AmortizationPeriodEndDate

Original value: 05/01/2030

(db) Concept: AmortizationPeriodEndDate

Original value: 05/01/2030

(dc) Concept: AmortizationPeriodEndDate

Original value: 06/01/2030

(dd) Concept: AmortizationPeriodEndDate

Original value: 06/01/2020

(de) Concept: AmortizationPeriodEndDate

Original value: 04/01/2038

(df) Concept: AmortizationPeriodEndDate

Original value: 04/01/2038

(dg) Concept: AmortizationPeriodEndDate

Original value: 04/01/2038

(dh) Concept: AmortizationPeriodEndDate

Original value: 04/01/2038

(di) Concept: AmortizationPeriodEndDate

Original value: 04/01/2038

(dj) Concept: AmortizationPeriodEndDate

Original value: 04/02/2018

(dk) Concept: AmortizationPeriodEndDate

Original value: 07/31/2019

(dl) Concept: AmortizationPeriodEndDate

Original value: 07/31/2019

(dm) Concept: AmortizationPeriodEndDate

Original value: 11/01/2059

(dn) Concept: AmortizationPeriodEndDate

Original value: 02/28/2023

(do) Concept: AmortizationPeriodEndDate

Original value: 02/27/2043

(dp) Concept: AmortizationPeriodEndDate

Original value: 09/30/2022

(dq) Concept: AmortizationPeriodEndDate

Original value: 09/30/2025

(dr) Concept: AmortizationPeriodEndDate

Original value: 12/15/2035

(ds) Concept: AmortizationPeriodEndDate

Original value: 02/15/2033

(dt) Concept: AmortizationPeriodEndDate

Original value: 04/30/2019

(du) Concept: AmortizationPeriodEndDate

Original value: 04/30/2026

(dv) Concept: AmortizationPeriodEndDate

Original value: 04/30/2044

(dw) Concept: AmortizationPeriodEndDate

Original value: 10/30/2044

(dx) Concept: AmortizationPeriodEndDate

Original value: 10/01/2025

(dy) Concept: AmortizationPeriodEndDate

Original value: 10/01/2022

(dz) Concept: AmortizationPeriodEndDate

Original value: 10/01/2047

(ea) Concept: AmortizationPeriodEndDate

Original value: 06/01/2028

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line No.	Particulars (Details) (a)	Amount (b)
1	Net Income for the Year (Page 117)	211,345,402
2	Reconciling Items for the Year
3
4	Taxable Income Not Reported on Books
5
6
7
8
9	Deductions Recorded on Books Not Deducted for Return
10
11
12
13
14	Income Recorded on Books Not Included in Return
15
16
17
18
19	Deductions on Return Not Charged Against Book Income
20
21
22
23
24
25
26
27	Federal Tax Net Income	214,924,796
28	Show Computation of Tax:
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (g) and (h). The balancing of this page is not affected by the inclusion of these taxes. Include in column (g) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying the year in column (d). Enter all adjustments of the accrued and prepaid tax accounts in column (i) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. Report in columns (l) through (o) how the taxes were distributed. Report in column (o) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (o) the amounts charged to Accounts 408.1 and 409.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (o) the taxes charged to utility plant or other balance sheet accounts. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
					BALANCE AT BEGINNING OF YEAR					BALANCE AT END OF YEAR		DISTRIBUTION OF TAXES CHARGED
Line No.	DescriptionOfTaxesAccruedPrepaidAndCharged Kind of Tax (See Instruction 5) (a)	TypeOfTax Type of Tax (b)	TaxJurisdiction State (c)	TaxYear Tax Year (d)	TaxesAccrued Taxes Accrued (Account 236) (e)	PrepaidTaxes Prepaid Taxes (Include in Account 165) (f)	TaxesCharged Taxes Charged During Year (g)	TaxesPaid Taxes Paid During Year (h)	TaxAdjustments Adjustments (i)	TaxesAccrued Taxes Accrued (Account 236) (j)	PrepaidTaxes Prepaid Taxes (Included in Account 165) (k)	TaxesAccruedPrepaidAndCharged Electric (Account 408.1, 409.1) (l)	IncomeTaxesExtraordinaryItems Extraordinary Items (Account 409.3) (m)	AdjustmentsToRetainedEarnings Adjustment to Ret. Earnings (Account 439) (n)	TaxesIncurredOther Other (o)
1	Federal Taxes
2	Income Taxes				40,286,768		1,123,955	2,667,773		44,078,496		3,470,591			2,346,636
3	Federal Fin 48				380,499		380,499								380,499
4	IRS Audit				433,656		37,779,778		(a) 38,213,434			38,213,434			433,656
5	FICA - 2018				1,024,993		11,181,987	10,730,519		1,476,460		5,872,645			5,309,342
6	Unemployment - 2018				28,259		74,317	69,039		33,537		41,111			33,206
7	State of Texas
8	TX Income Taxes - 2015
9	TX Income Taxes - 2016
10	TX Income Taxes - 2017				4,581,953		1,202,037	3,379,916				1,202,037
11	TX Income Taxes - 2017						2,968,179			2,968,179		2,968,179
12	Unemployment - TX 2018				54,887		154,920	157,684		52,123		53,453			101,467
13	TX Local Franchise - 2017				3,932,089		56,120	3,875,969							56,120
14	TX Local Franchise - 2018						51,643,875	47,790,236		3,853,639		51,587,755			56,120
15	TX Sales\Use Tax 2016						3,938,937	3,938,937				194,747			3,744,190
16	TX Sales\Use Tax 2017				15,114,198		1,675,009	13,439,189							1,675,009
17	TX Sales\Use Tax 2018						31,700,036	27,650,926		4,049,110		7,824			31,692,212
18	TX Use Tax-Audit Provisions				137,500		137,500					137,500
19	Texas Ad Valorem - 2013						136	136				136
20	Texas Ad Valorem - 2014						386	386				386
21	Texas Ad Valorem - 2015						137	137				137
22	Texas Ad Valorem - 2016						2,296	2,296				2,296
23	Texas Ad Valorem - 2017				51,712,770		377,875	51,334,895				377,875
24	Texas Ad Valorem - 2018						77,275,850	15,528,542		61,747,308		73,340,860			3,934,990
25	Texas Lsd PP Taxes - 2017				590,014		459,532	1,043,541		6,005		470,185			10,653
26	Texas Lsd PP Taxes - 2018						1,434,086	121,591		1,312,495		1,434,086
27	TX Gross Margins - 2015
28	TX Gross Margins - 2016
29	TX Gross Margins - 2017
30	State of Oklahoma
31	State Registration Fee				26		26								26
32	Unemployment - OK 2018											27			27
33	State of Delaware
34	State Registration Fee						825	825				1,125			300
35	Ohio State Taxes
36	OH CAT- 2015
37	OH CAT- 2017						2	2				2
38	OH CAT- 2018						8	8				8
39	Other
40	State Income Tax - FIN48				1,566,650			268,641		1,835,291		4			4
40	TOTAL				35,376,376					29,585,069

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: TaxAdjustments

This adjustment is for FIN 48 deferred taxes in the payable account that had an offset to accounts 410.1 and 411.1 in the amount of -$38,213,434

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i) the average period over which the tax credits are amortized.
			Deferred for Year		Allocations to Current Year's Income
Line No.	Account Subdivisions (a)	Balance at Beginning of Year (b)	Account No. (c)	Amount (d)	Account No. (e)	Amount (f)	Adjustments (g)	Balance at End of Year (h)	Average Period of Allocation to Income (i)	ADJUSTMENT EXPLANATION (j)
1	Electric Utility
2	10%	12,305,570			411.4	1,462,070		10,843,500
8	TOTAL	12,305,570				1,462,070		10,843,500
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
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	TOTAL

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

OTHER DEFERRED CREDITS (Account 253)
Report below the particulars (details) called for concerning other deferred credits. For any deferred credit being amortized, show the period of amortization. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
			DEBITS
Line No.	Description and Other Deferred Credits (a)	Balance at Beginning of Year (b)	Contra Account (c)	Amount (d)	Credits (e)	Balance at End of Year (f)
1	Pole Attachments	1,337,097	Various	3,943,702	3,948,068	1,341,463
2	Power Purchase and
3	Sale Agreement Deferral	51,945,805	Various	5,586,200		46,359,605
4	Security Deposits	11,328,745	232	1,071,109	8,613,318	18,870,954
5	Deferred Equity Income relating to
6	Supreme Court of Texas July 2011
7	Reversal of 2006 Capacity Auction
8	True-up Disallowance (PUCT
9	Docket #39722)	53,949,017	456	7,258,952		46,690,065
10	Contributions in Aid
11	of Construction	7,535,734			16,673,375	24,209,109
12	Associated Business Development	1,794,325	186	1,794,325	3,590,785	3,590,785
13	Environmental Liabilities	530,225	242	267,347		262,878
14	Texas Reliability Entity -
15	Audit Assessment	360,000			516,500	876,500
16	Asbestos Litigation Contingency	1,250,000				1,250,000
17	Minor Items < $100,000	129,562			63,470	193,032
47	TOTAL	130,160,510		19,921,635	33,405,516	143,644,391

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)

Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property.
For other (Specify),include deferrals relating to other income and deductions.
Use footnotes as required.

CHANGES DURING YEAR

ADJUSTMENTS

Debits

Credits

Line No.

Account

(a)

Balance at Beginning of Year

(b)

Amounts Debited to Account 410.1

(c)

Amounts Credited to Account 411.1

(d)

Amounts Debited to Account 410.2

(e)

Amounts Credited to Account 411.2

(f)

Account Credited

(g)

Amount

(h)

Account Debited

(i)

Amount

(j)

Balance at End of Year

(k)

Accelerated Amortization (Account 281)

Electric

Defense Facilities

Pollution Control Facilities

Other

5.1

Other

5.2

Other

TOTAL Electric (Enter Total of lines 3 thru 7)

Gas

Defense Facilities

Pollution Control Facilities

Other

12.1

Other

12.2

Other

TOTAL Gas (Enter Total of lines 10 thru 14)

Other

16.1

Other

16.2

Other

TOTAL (Acct 281) (Total of 8, 15 and 16)

Classification of TOTAL

Federal Income Tax

State Income Tax

Local Income Tax

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization. For other (Specify),include deferrals relating to other income and deductions. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 282
2	Electric	1,248,004,017	1,529,937,353	1,449,951,729							1,327,989,641
3	Gas
4	Other (Specify)
5	Total (Total of lines 2 thru 4)	1,248,004,017	1,529,937,353	1,449,951,729							1,327,989,641
6	Regulatory Assets - SFAS109	487,132,667					1823/254	1,059,266,200	1823/254	1,063,085,732	483,313,135
9	TOTAL Account 282 (Total of Lines 5 thru 8)	760,871,350	1,529,937,353	1,449,951,729				1,059,266,200		1,063,085,732	844,676,506
10	Classification of TOTAL
11	Federal Income Tax	760,871,350	1,529,937,353	1,449,951,729				1,059,266,200		1,063,085,732	844,676,506
12	State Income Tax
13	Local Income Tax

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
Report the information called for below concerning the respondent’s accounting for deferred income taxes relating to amounts recorded in Account 283. For other (Specify),include deferrals relating to other income and deductions. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 283
2	Electric
3	Accrued BK Pension Expense	60,565,308	469,311	25,984,133							35,050,486
4	Provision for Damages	43,154,647	7,064,394	18,204,627							32,014,414
5	Defd Tax Gain Securitized Reg	323,222,870		179,697,333							143,525,537
6	Reg Asset Advanced Metering	27,446,941	9,951,188	19,462,801							17,935,328
7	Reg Asset-Loss on Reacquired D	2,652,003		1,386,980							1,265,023
8	Other	134,891,516	262,666,209	96,519,775							31,254,918
9	TOTAL Electric (Total of lines 3 thru 8)	322,150,253	280,151,102	341,255,649							261,045,706
10	Gas
11
12
13
14
15
16
17	TOTAL Gas (Total of lines 11 thru 16)
18	TOTAL Other	(a) 12,958,335	11,592,108	18,525,115			1823/254	128,727,832	1823/254	138,219,280	15,516,776
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	335,108,588	291,743,210	359,780,764				128,727,832		138,219,280	276,562,482
20	Classification of TOTAL
21	Federal Income Tax	307,642,917	291,719,405	359,637,919				125,699,936		135,123,373	249,147,840
22	State Income Tax	27,465,671	23,805	142,845				3,027,896		3,095,907	27,414,642
23	Local Income Tax
NOTES

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOther

Description Beg Bal DR 410 CR 411 Debits Credits End Bal

Non-Utility 17,388,163 11,592,108 18,525,115 0 0 10,455,156

SFAS 109 -4,429,828 0 0 128,727,832 138,219,280 5,061,620

----------------------------------------------------------------------------

Total 12,958,335 11,592,108 18,525,115 128,727,832 138,219,280 15,516,776

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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	685,741,928	190 / 282	12,454,362		673,287,566
2	Earnings Subject to Refund under
3	State of Texas Restructuring Legislation
4	Amortization @ 3.361% or approximately 30 years
5	per Docket No. 22354	6,821,679	4074	496,012		6,325,667
6	FERC System Integration Agreement (SIA)
7	Refund to be applied as a reduction to
8	Advanced Metering System
9	Investment - PUCT Docket #36924 and 36928	12,749,261	4074	4,249,751		8,499,510
10	Other Comprehensive Income (OCI) Excess
11	Deferred Income Tax Adjustment - for
12	2018 Tax Reform Act	966,900			1,019,522	52,622
13	Unrealized Gain/Loss on Forward
14	Commitments	511,815	175 / 456	511,815
41	TOTAL	704,857,783		17,711,940	1,019,522	688,165,365

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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 pages 108-109, 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	103,602,490	63,599,506	1,654,639	923,791
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	103,602,490	63,599,506	1,654,639	923,791
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds	31,295,250	1,080,257
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Net of Prov. for Refunds	72,307,240	62,519,249	1,654,639	923,791
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	198,351	201,077
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(a) 1,863,484	1,874,717
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	20,931,813	20,601,626
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(b) 913,671,775	884,531,881
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	313,423,362	293,788,617
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	1,250,088,785	1,200,997,918
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	1,322,396,025	1,263,517,167

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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:	2018	2017
Wires Revenue (Billed & Unbilled)*	903,747,320	875,124,484
Demand-Side Management Program	(1,340,319)	(1,531,501)
Electric Operations - Nonaffiliated	1,328,633	1,347,953
Third Party Plant Operations including related overhead	1,207,339	980,349
Amortization of Deferred Equity Income - Transition
Funding III	7,258,952	7,140,746
Electric Operations - Affiliated	1,469,850	1,469,850
Total	913,671,775	884,531,881

*AEP Texas sells wire services through Retail Electric Providers in Texas and therefore, records both "Billed and Unbilled Revenues" in account 4560 - Other Electric Revenues.

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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 Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41	TOTAL Billed - All Accounts
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts
43	TOTAL - All Accounts

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

SALES FOR RESALE (Account 447)
Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327). Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (g) through (k). In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,line 24. Footnote entries as required and provide explanations following all required data.
					ACTUAL DEMAND (MW)			REVENUE
Line No.	Name of Company or Public Authority (Footnote Affiliations) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Average Monthly Billing Demand (MW) (d)	Average Monthly NCP Demand (e)	Average Monthly CP Demand (f)	Megawatt Hours Sold (g)	Demand Charges ($) (h)	Energy Charges ($) (i)	Other Charges ($) (j)	Total ($) (h+i+j) (k)
1	(a) AEP Energy Partners, Inc.	OS	N/A	(b)	(c)	(d)	1,654,639		59,923,218	43,679,272	103,602,490
15	Subtotal - RQ
16	Subtotal-Non-RQ						(e)(f) 1,654,639		59,923,218	43,679,272	103,602,490
17	Total						1,654,639		59,923,218	43,679,272	103,602,490

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

AEP Energy Partners (AEPEP), an affiliated company, Oklaunion Power Purchase and Sales Agreement.

(b) Concept: AverageMonthlyBillingDemand

Original value: N/A

(d) Concept: AverageMonthlyCoincidentPeakDemand

Original value: N/A

(e) Concept: MegawattHoursSoldNonRequirementsSales

Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 24, Column: b, Value: 1788559

(f) Concept: MegawattHoursSoldNonRequirementsSales

Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 24, Column: b, Value: 0

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line No.	Account (a)	Amount for Current Year (b)	Amount for Previous Year (c) (c)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION EXPENSES
2	SteamPowerGenerationAbstract A. Steam Power Generation
3	SteamPowerGenerationOperationAbstract Operation
4	OperationSupervisionAndEngineeringSteamPowerGeneration (500) Operation Supervision and Engineering	2,343,027	2,179,461
5	FuelSteamPowerGeneration (501) Fuel	37,803,384	20,343,982
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	1,535,775	1,312,179
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	1,162,016	1,028,382
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	5,547,411	1,821,163
11	RentsSteamPowerGeneration (507) Rents
12	Allowances (509) Allowances
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	48,391,613	26,685,167
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	718,758	679,693
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	935,180	776,061
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	3,952,645	3,775,128
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	640,063	559,905
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	364,169	252,470
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	6,610,815	6,043,257
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	55,002,428	32,728,424
22	NuclearPowerGenerationAbstract B. Nuclear Power Generation
23	NuclearPowerGenerationOperationAbstract Operation
24	OperationSupervisionAndEngineeringNuclearPowerGeneration (517) Operation Supervision and Engineering
25	NuclearFuelExpense (518) Fuel
26	CoolantsAndWater (519) Coolants and Water
27	SteamExpensesNuclearPowerGeneration (520) Steam Expenses
28	SteamFromOtherSourcesNuclearPowerGeneration (521) Steam from Other Sources
29	SteamTransferredCreditNuclearPowerGeneration (Less) (522) Steam Transferred-Cr.
30	ElectricExpensesNuclearPowerGeneration (523) Electric Expenses
31	MiscellaneousNuclearPowerExpenses (524) Miscellaneous Nuclear Power Expenses
32	RentsNuclearPowerGeneration (525) Rents
33	NuclearPowerGenerationOperationsExpense TOTAL Operation (Enter Total of lines 24 thru 32)
34	NuclearPowerGenerationMaintenanceAbstract Maintenance
35	MaintenanceSupervisionAndEngineeringNuclearPowerGeneration (528) Maintenance Supervision and Engineering
36	MaintenanceOfStructuresNuclearPowerGeneration (529) Maintenance of Structures
37	MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration (530) Maintenance of Reactor Plant Equipment
38	MaintenanceOfElectricPlantNuclearPowerGeneration (531) Maintenance of Electric Plant
39	MaintenanceOfMiscellaneousNuclearPlant (532) Maintenance of Miscellaneous Nuclear Plant
40	NuclearPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 35 thru 39)
41	PowerProductionExpensesNuclearPower TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)
42	HydraulicPowerGenerationAbstract C. Hydraulic Power Generation
43	HydraulicPowerGenerationOperationAbstract Operation
44	OperationSupervisionAndEngineeringHydraulicPowerGeneration (535) Operation Supervision and Engineering
45	WaterForPower (536) Water for Power
46	HydraulicExpenses (537) Hydraulic Expenses
47	ElectricExpensesHydraulicPowerGeneration (538) Electric Expenses
48	MiscellaneousHydraulicPowerGenerationExpenses (539) Miscellaneous Hydraulic Power Generation Expenses
49	RentsHydraulicPowerGeneration (540) Rents
50	HydraulicPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 44 thru 49)
51	HydraulicPowerGenerationContinuedAbstract C. Hydraulic Power Generation (Continued)
52	HydraulicPowerGenerationMaintenanceAbstract Maintenance
53	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration (541) Mainentance Supervision and Engineering
54	MaintenanceOfStructuresHydraulicPowerGeneration (542) Maintenance of Structures
55	MaintenanceOfReservoirsDamsAndWaterways (543) Maintenance of Reservoirs, Dams, and Waterways
56	MaintenanceOfElectricPlantHydraulicPowerGeneration (544) Maintenance of Electric Plant
57	MaintenanceOfMiscellaneousHydraulicPlant (545) Maintenance of Miscellaneous Hydraulic Plant
58	HydraulicPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 53 thru 57)
59	PowerProductionExpensesHydraulicPower TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)
60	OtherPowerGenerationAbstract D. Other Power Generation
61	OtherPowerGenerationOperationAbstract Operation
62	OperationSupervisionAndEngineeringOtherPowerGeneration (546) Operation Supervision and Engineering
63	Fuel (547) Fuel	7
64	GenerationExpenses (548) Generation Expenses
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses
66	RentsOtherPowerGeneration (550) Rents
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	7
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering
70	MaintenanceOfStructures (552) Maintenance of Structures
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant
71.1	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration (553.1) Maintenance of Energy Storage Equipment
72	MaintenanceOfMiscellaneousOtherPowerGenerationPlant (554) Maintenance of Miscellaneous Other Power Generation Plant
73	OtherPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 69 thru 72)
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	7
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	191,913	162,262
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	614	208
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	192,527	162,470
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	55,194,962	32,890,894
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	16,511,096	10,395,930
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability		4,860
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	2,432,894	1,775,400
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	1,746	12,665
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	47,794	63,672
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	344,550	247,754
90	TransmissionServiceStudies (561.6) Transmission Service Studies	35	22
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services
93	StationExpensesTransmissionExpense (562) Station Expenses	818,962	822,612
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	339,705	380,969
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	297,238,078	288,349,435
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	6,618,645	4,862,806
98	RentsTransmissionElectricExpense (567) Rents		3,385
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	324,353,505	306,894,180
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	77,816	165,865
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	50,781	31,307
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	13,292	(a) 7,873
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	1,008,897	923,659
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	434,925	300,491
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	6,596,559	3,686,772
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	11,547,919	6,857,619
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	2,102	1,291
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	24,488	94,094
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	19,707,803	12,068,971
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	344,061,308	318,963,151
113	RegionalMarketExpensesAbstract 3. REGIONAL MARKET EXPENSES
114	RegionalMarketExpensesOperationAbstract Operation
115	OperationSupervision (575.1) Operation Supervision
116	DayAheadAndRealTimeMarketAdministration (575.2) Day-Ahead and Real-Time Market Facilitation
117	TransmissionRightsMarketAdministration (575.3) Transmission Rights Market Facilitation
118	CapacityMarketAdministration (575.4) Capacity Market Facilitation
119	AncillaryServicesMarketAdministration (575.5) Ancillary Services Market Facilitation
120	MarketMonitoringAndCompliance (575.6) Market Monitoring and Compliance
121	MarketFacilitationMonitoringAndComplianceServices (575.7) Market Facilitation, Monitoring and Compliance Services
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)
124	RegionalMarketExpensesMaintenanceAbstract Maintenance
125	MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses (576.1) Maintenance of Structures and Improvements
126	MaintenanceOfComputerHardware (576.2) Maintenance of Computer Hardware
127	MaintenanceOfComputerSoftware (576.3) Maintenance of Computer Software
128	MaintenanceOfCommunicationEquipmentRegionalMarketExpenses (576.4) Maintenance of Communication Equipment
129	MaintenanceOfMiscellaneousMarketOperationPlant (576.5) Maintenance of Miscellaneous Market Operation Plant
130	RegionalMarketMaintenanceExpense Total Maintenance (Lines 125 thru 129)
131	RegionalMarketExpenses TOTAL Regional Transmission and Market Operation Expenses (Enter Total of Lines 123 and 130)
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	7,732,452	7,258,361
135	LoadDispatching (581) Load Dispatching	3,452,163	3,221,370
136	StationExpensesDistribution (582) Station Expenses	1,572,942	1,374,181
137	OverheadLineExpenses (583) Overhead Line Expenses	6,065,648	4,168,308
138	UndergroundLineExpenses (584) Underground Line Expenses	1,264,211	1,368,913
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	102,722	107,982
140	MeterExpenses (586) Meter Expenses	7,384,636	8,777,477
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	1,216,737	1,204,954
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	27,943,070	24,825,585
143	RentsDistributionExpense (589) Rents	1,948,928	1,774,149
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	58,683,509	54,081,280
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	155,020	132,269
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	23,147	21,600
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	2,665,397	2,834,173
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	37,955,120	36,985,465
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	1,987,925	1,145,884
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	1,152,140	765,787
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	889,423	624,476
153	MaintenanceOfMeters (597) Maintenance of Meters	456,416	387,816
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	225,093	341,929
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	45,509,681	43,239,399
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	104,193,190	97,320,679
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision	684,430	629,303
160	MeterReadingExpenses (902) Meter Reading Expenses	432,431	376,050
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	10,360,283	9,891,753
162	UncollectibleAccounts (904) Uncollectible Accounts	750,907	157,400
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	120,030	99,174
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	12,348,081	11,153,680
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision	17,473,565	15,806,190
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	1,559,077	1,567,026
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses	286	20
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	9,638	238,033
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	19,042,566	17,611,269
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision	14	2,241
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses	318,124	295,574
176	AdvertisingExpenses (913) Advertising Expenses
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	318,138	297,815
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	30,862,490	26,993,029
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	3,020,246	2,672,895
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	9,515,991	3,849,034
184	OutsideServicesEmployed (923) Outside Services Employed	8,412,198	5,036,037
185	PropertyInsurance (924) Property Insurance	2,686,581	2,591,626
186	InjuriesAndDamages (925) Injuries and Damages	4,720,125	5,073,129
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	1,600,491	8,682,060
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	1,672,980	326,093
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	480,021	427,004
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	1,895,241	936,383
193	RentsAdministrativeAndGeneralExpense (931) Rents	925,647	931,218
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	43,559,047	49,820,440
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	17,601,556	14,553,934
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	61,160,603	64,374,374
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	596,318,848	542,611,862

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: MaintenanceOfComputerHardwareTransmission

This footnote applies to both current and prior year.

Allocated maintenance expenses for joint use computer hardware, computer software and

communication equipment are determined by using various factors, which include number

of remote terminal units, number of radios, number of employees and other factors

assigned to each function.

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

PURCHASED POWER (Account 555)
Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier’s service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (i) and (j) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. Report demand charges in column (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m). Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. The data in column (g) through (n) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13. Footnote entries as required and provide explanations following all required data.
					Actual Demand (MW)				POWER EXCHANGES		COST/SETTLEMENT OF POWER
Line No.	NameOfCompanyOrPublicAuthorityProvidingPurchasedPower Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	RateScheduleTariffNumber Ferc Rate Schedule or Tariff Number (c)	AverageMonthlyBillingDemand Average Monthly Billing Demand (MW) (d)	AverageMonthlyNonCoincidentPeakDemand Average Monthly NCP Demand (e)	AverageMonthlyCoincidentPeakDemand Average Monthly CP Demand (f)	MegawattHoursPurchasedOtherThanStorage MegaWatt Hours Purchased (Excluding for Energy Storage) (g)	MegawattHoursPurchasedForEnergyStorage MegaWatt Hours Purchased for Energy Storage (h)	EnergyReceivedThroughPowerExchanges MegaWatt Hours Received (i)	EnergyDeliveredThroughPowerExchanges MegaWatt Hours Delivered (j)	DemandChargesOfPurchasedPower Demand Charges ($) (k)	EnergyChargesOfPurchasedPower Energy Charges ($) (l)	OtherChargesOfPurchasedPower Other Charges ($) (m)	SettlementOfPower Total (k+l+m) of Settlement ($) (n)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15	TOTAL

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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 (11011) 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)

American Electric Power

(a)

Service Corporation (1,2)

Various

SFP

N/A

Various

Austin Energy (2)

Various

SFP

N/A

Various

13,082,697

Bandera Electric Coop (2)

Various

SFP

N/A

Various

712,620

Bartlett, City of (2)

Various

SFP

N/A

Various

13,242

Bastrop, City of (2)

Various

SFP

N/A

Various

84,330

Bellville, City of (2)

Various

SFP

N/A

Various

66,352

Bluebonnet Electric Coop (2)

Various

SFP

N/A

Various

2,237,919

Boerne, City of (2)

Various

SFP

N/A

Various

163,146

Brady, City of (2)

Various

SFP

N/A

Various

73,042

Brazos Electric Coop (2)

Various

SFP

N/A

Various

16,300,041

Brenham, City of (2)

Various

SFP

N/A

Various

287,296

Bridgeport, City of (2)

Various

SFP

N/A

Various

71,417

Brownsville Public Utilities Board (2)

Various

SFP

N/A

Various

1,337,889

Bryan Texas Utilities (2)

Various

SFP

N/A

Various

1,262,777

Burnet, City of (2)

Various

SFP

N/A

Various

92,076

Calpine Power Service Company (3)

ERCOT

SPP

N/A

Various

34,483

45,802

Canadian Wood Products Energy (3)

ERCOT

SPP

N/A

Various

120,304

94,939

Cargill Power Marketing LLC (2)

Various

SFP

N/A

Various

Centerpoint Energy Houston Electric, LLC (2)

Various

SFP

N/A

Various

85,355,978

Central Texas Electric Coop (2)

Various

SFP

N/A

Various

653,215

Coleman, City of (2)

Various

SFP

N/A

Various

50,057

College Station, City of (2)

Various

SFP

N/A

Various

996,319

Constellation Energy Commodities (2)

ERCOT

Various

SFP

N/A

Various

Cuero, City of (2)

Various

SFP

N/A

Various

105,935

Denton Municipal Electric (2)

Various

SFP

N/A

Various

1,145,419

Dynasty Power (3)

ERCOT

SPP

N/A

Various

25,070

36,841

EDF TRADING N A, LLC (2)

Various

SFP

N/A

Various

Endure Energy LLC (3)

ERCOT

SPP

N/A

Various

135,328

95,176

Farmersville, City of (2)

Various

SFP

N/A

Various

35,502

Fayette Electric Cooperative (2)

Various

SFP

N/A

Various

306,372

Flatonia, City of (2)

Various

SFP

N/A

Various

27,804

Floresville Electric Power System (2)

Various

SFP

N/A

Various

390,374

Fredericksburg, City of (2)

Various

SFP

N/A

Various

167,600

Garland Power and Light (2)

Various

SFP

N/A

Various

1,019,774

Georgetown, City of (2)

Various

SFP

N/A

Various

734,641

GEUS (2)

Various

SFP

N/A

Various

293,279

Giddings, City of (2)

Various

SFP

N/A

Various

64,731

Golden Spread Electric Cooperative, Inc (2)

Various

SFP

N/A

Various

561,542

Goldsmith, City of (2)

Various

SFP

N/A

Various

4,314

Goldthwaite, City of (2)

Various

SFP

N/A

Various

24,663

Gonzales, City of (2)

Various

SFP

N/A

Various

94,535

Granbury Municipal Utilities (2)

Various

SFP

N/A

Various

100,901

Greenbelt Electric Coop (2)

Various

SFP

N/A

Various

Guadalupe Valley Electric Coop (2)

Various

SFP

N/A

Various

1,966,555

Hallettsville, City of (2)

Various

SFP

N/A

Various

46,755

Hamilton County Electric Coop (2)

Various

SFP

N/A

Various

180,357

Hearne, City of (2)

Various

SFP

N/A

Various

60,890

Hempstead, City of (2)

Various

SFP

N/A

Various

60,790

J. Aron & Company LLC (3)

ERCOT

SPP

Various

243,288

298,514

Kerrville Public Utility Board (2)

Various

SFP

N/A

Various

560,091

LaGrange Utilities (2)

Various

SFP

N/A

Various

81,072

Lamar County Electric Cooperative (2)

Various

SFP

N/A

Various

226,493

Lampasas, City of (2)

Various

SFP

N/A

Various

117,087

Lexington, City of (2)

Various

SFP

N/A

Various

14,105

Lighthouse Electric Cooperative Inc (2)

Various

SFP

N/A

Various

Llano, City of (2)

Various

SFP

N/A

Various

52,621

Lockhart, City of (2)

Various

SFP

N/A

Various

132,327

Luling, City of (2)

Various

SFP

N/A

Various

63,228

Lyntegar Electric Coop (2)

Various

SFP

N/A

Various

152,681

Macquarie Energy LLC (3)

ERCOT

SPP

N/A

Various

27,918

23,031

MAG Energy Solutions. Inc. (3)

ERCOT

SPP

N/A

Various

2,944

1,910

Mason, City of (2)

Various

SFP

N/A

Various

27,234

Mercuria Energy America, Inc. (2)

Various

SFP

N/A

Various

Moulton, City of (2)

Various

SFP

N/A

Various

11,947

New Braunfels Utilities (2)

Various

SFP

N/A

Various

1,429,044

Oncor Electric Delivery (2)

Various

SFP

N/A

Various

122,841,531

Pedernales Electric Cooperative, Inc (2)

Various

SFP

N/A

Various

6,929,648

Rainbow Energy Marketing (3)

ERCOT

SPP

N/A

Various

444,025

440,863

Rayburn Country Electric Cooperative, Inc (2)

Various

SFP

N/A

Various

3,614,878

Rio Grande Electric Coop (2)

Various

SFP

N/A

Various

271,528

Robstown Utility System, City of (2)

Various

SFP

N/A

Various

118,737

San Antonio City Public Service (2)

Various

SFP

N/A

Various

23,825,136

San Bernard Electric Coop (2)

Various

SFP

N/A

Various

695,697

San Marcos, City of (2)

Various

SFP

N/A

Various

636,563

San Saba, City of (2)

Various

SFP

N/A

Various

46,561

Sanger, City of (2)

Various

SFP

N/A

Various

81,961

Schulenberg, City of (2)

Various

SFP

N/A

Various

68,049

Seguin, City of (2)

Various

SFP

N/A

Various

324,032

Sempra Energy Solutions, LLC (3)

ERCOT

SPP

N/A

Various

27,041

16,059

Seymour, City of (2)

Various

SFP

N/A

Various

40,404

Sharyland Utilities, LP (2)

Various

SFP

N/A

Various

Shell Energy North America

ERCOT

SPP

N/A

Various

2,984

4,685

Shiner, City of (2)

Various

SFP

N/A

Various

47,792

Smithville, City of (2)

Various

SFP

N/A

Various

50,078

South Texas Electric Cooperative, Inc (2)

Various

SFP

N/A

Various

6,519,775

Southwest Rural Electric Association INC (2)

Various

SFP

N/A

Various

756

Southwest Texas Electric Cooperative, Inc (2)

Various

SFP

N/A

Various

202,601

Taylor Electric Cooperative, Inc (2)

Various

SFP

N/A

Various

311,927

Tenaska Power Service Company (3)

ERCOT

SPP

N/A

Various

111,303

99,331

Texas Municipal Power Agency (2)

Various

SFP

N/A

Various

2,334,291

Texas-New Mexico Power Company (2)

Various

SFP

N/A

Various

8,427,385

Tex-La Electric Coop (2)

Various

SFP

N/A

Various

570,128

The Energy Authority (3)

ERCOT

SPP

N/A

Various

13,551

8,319

Twin Eagle Resource Management LLC (3)

ERCOT

SPP

N/A

Various

257,669

180,402

Vitol, Inc (3)

ERCOT

SPP

N/A

Various

246,091

323,098

Waelder, City of (2)

Various

SFP

N/A

Various

23,402

Weatherford, City of (2)

Various

SFP

N/A

Various

458,107

Weimer, City of (2)

Various

SFP

N/A

Various

39,504

100

Westar Energy Inc. (3)

ERCOT

SPP

N/A

Various

84,751

71,995

101

Western Farmers Electric Cooperative (2)

Various

SFP

N/A

Various

3,970

102

Yoakum, City of (2)

Various

SFP

N/A

Various

96,880

TOTAL

1,776,750

313,423,362

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: PaymentByCompanyOrPublicAuthority

(1) Respondent is an affiliated company of American Electric Power Service Corporation and American Electric Power Energy Partners, Inc.

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

(3) High Voltage Direct Current Tie

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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 Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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
2	Service
3	(a) Corporation (1, 2, 3)	SFP					505,815	505,815
4	Austin Energy (2)	SFP					7,083,644	7,083,644
5	Bandera Electric
6	Cooperative (2)	SFP					279,295	279,295
7	Brazos Electric
8	Cooperative (2)	SFP					11,232,414	11,232,414
9	Brownsville Public
10	Utilities Board (2)	SFP					585,480	585,480
11	Bryan Texas
12	Utilities (2)	SFP					2,629,241	2,629,241
13	Centerpoint Energy
14	Houston Electric (2)	SFP					33,967,601	33,967,601
15	Cherokee County
16	Electric Cooperative(2)	SFP					30,240	30,240
17	College Station,
18	City of (2)	SFP					333,521	333,521
19	Cross Texas
20	Transmission (2, 4)	SFP					6,238,715	6,238,715
21	Deep East Texas
22	Cooperative (2)	SFP					10,321	10,321
23	Denton Municipal
24	Electric (2)	SFP					3,342,961	3,342,961
25	East Texas Electric
26	Cooperative (2)	SFP					9,693	9,693
27	(b) Electric Transmission
28	Tx, LLC (2)	SFP					27,423,937	27,423,937
29	Fannin Electric
30	Cooperative (2)	SFP					14,795	14,795
31	Farmers Electric
32	Cooperative (2)	SFP					64,296	64,296
33	Floresville Electric
34	Power System (2)	SFP					34,468	34,468
35	Garland Power
36	and Light (2)	SFP					3,173,955	3,173,955
37	GEUS (2)	SFP					217,473	217,473
38	Golden Spread Electric
39	Cooperative (2)	SFP					83,902	83,902
40	Grayson-Collin Electric						126,535	126,535
41	Cooperative (2)	SFP
42	Houston County Electric
43	Cooperative (2)	SFP					22,956	22,956
44	Lamar County Electric
45	Cooperative (2)	SFP					9,921	9,921
46	Lone Star Transmission,
47	LLC (2, 4)	SFP					8,305,116	8,305,116
48	Lower Colorado River
49	Authority (LCRA) (2)	SFP					38,042,651	38,042,651
50	Lyntegar Electric
51	Cooperative (2)	SFP					49,669	49,669
52	Oncor
53	Electric Delivery (2)	SFP					78,550,050	78,550,050
54	Rayburn
55	Country Electric
56	Cooperative (2)	SFP					360,143	360,143
57	Rio Grande Electric
58	Cooperative (2)	SFP					26,739	26,739
59	San Antonio City
60	Public Service (2)	SFP					15,675,726	15,675,726
61	San Bernard Electric
62	Cooperative (2)	SFP					229,701	229,701
63	San Miguel Electric
64	Cooperative (2)	SFP					236,667	236,667
65	Sharyland
66	Utilities, LP (2, 4)	SFP					22,885,490	22,885,490
67	South Texas Electric
68	Cooperative (2)	SFP					7,213,708	7,213,708
69	Southwest Texas
70	Electric
71	Cooperative (2)	SFP					2,424	2,424
72	Taylor Electric
73	Cooperative (2)	SFP					63,739	63,739
74	Texas Municipal
75	Power Agency (2)	SFP					4,003,399	4,003,399
76	Texas-New Mexico
77	Power Company (2)	SFP					6,133,265	6,133,265
78	Transmission Cost
79	Recovery Factor (5)	SFP					7,735,503	7,735,503
80	Trinity Valley Electric
81	Cooperative (2)	SFP					165,978	165,978
82	Wind Energy
83	Transmission Texas(2,4)	SFP					10,121,322	10,121,322
84	Wood County Electric
85	Cooperative (2)	SFP					15,609	15,609
	TOTAL						297,238,078	297,238,078

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers

(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

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

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.	Description (a)	Amount (b)
1	IndustryAssociationDues Industry Association Dues	527,258
2	NuclearPowerResearchExpenses Nuclear Power Research Expenses
3	OtherExperimentalAndGeneralResearchExpenses Other Experimental and General Research Expenses
4	PublicationAndDistributionExpensesForSecuritiesToStockholders Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities	86,997
5	OtherMiscellaneousGeneralExpenses Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000	40,060
6	Associated Business Development	947,409
7	Misc. General Service & Affiliated Companies Billing	255,891
8	Chamber of Commerce	37,626
46	MiscellaneousGeneralExpenses TOTAL	1,895,241

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405). Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year. Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used. In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used. For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column (a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related.
	A. Summary of Depreciation and Amortization Charges
Line No.	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			24,054,567		24,054,567
2	Steam Production Plant	22,375,773	2,795,553			25,171,326
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant
7	Transmission Plant	63,266,753				63,266,753
8	Distribution Plant	133,593,752				133,593,752
9	Regional Transmission and Market Operation
10	General Plant	16,036,234	82,605			16,118,839
11	Common Plant-Electric
12	TOTAL	235,272,512	2,878,158	24,054,567		262,205,237

B. Basis for Amortization Charges
Section A Line 1 Column D represents amortization of capitalized software development costs over a 5 year life and costs associated with the Oracle strategic partnership which are over a 10 year life.

	C. Factors Used in Estimating Depreciation Charges
Line No.	AccountNumberFactorsUsedInEstimatingDepreciationCharges Account No. (a)	DepreciablePlantBase Depreciable Plant Base (in Thousands) (b)	UtilityPlantEstimatedAverageServiceLife Estimated Avg. Service Life (c)	UtilityPlantNetSalvageValuePercentage Net Salvage (Percent) (d)	UtilityPlantAppliedDepreciationRate Applied Depr. Rates (Percent) (e)	MortalityCurveType Mortality Curve Type (f)	UtilityPlantWeightedAverageRemainingLife Average Remaining Life (g)
12	STEAM -- COAL/LIGNITE		0 years				0 years
13	TNC		0 years				0 years
14	311-316	327,050	0 years				0 years
15	COAL/LIGNITE SUM	327,050	0 years				0 years
16	TRANSMISSION PLANT		0 years				0 years
17	TCC		0 years				0 years
18	350 (Rights)	56,951	(b) 75 years		1.02	R5	0 years
19	352	27,345	(c) 55 years	1	1.33	L1	0 years
20	353	1,191,126	(d) 62 years	1	1.38	L0.5	0 years
21	353.16	2,656	(e) 62 years	1	1.38	L0.5	0 years
22	354	46,652	(f) 81 years	2	0.8	S3	0 years
23	355	542,814	(g) 70 years	68	2.18	R1	0 years
24	356	478,720	(h) 75 years	29	1.52	R3	0 years
25	356.16	6,641	(i) 75 years	29	1.52	R3	0 years
26	357	2,243	(j) 65 years	5	0.59	R2	0 years
27	358	24,960	(k) 50 years		1.66	R3	0 years
28	358.16	31	(l) 50 years		1.66	R3	0 years
29	359	54	(m) 65 years		1.15	R4	0 years
30	TCC SUM	2,380,193	0 years				0 years
31	TNC		0 years				0 years
32	350 (Rights)	25,668	(n) 75 years		0.92	R3	0 years
33	352	15,595	(o) 50 years		1.52	L4	0 years
34	353-Dist & Trans	532,061	(p) 54 years	25	1.86	R0.5	0 years
35	353.16	1,674	(q) 54 years	25	1.86	R0.5	0 years
36	353-Gen	238	0 years				0 years
37	354	3,771	(r) 65 years	10	1.79	R3	0 years
38	355	335,897	(s) 45 years	80	4.62	R5	0 years
39	356	157,208	(t) 50 years	45	3.32	S6	0 years
40	356.16	15,256	(u) 50 years	45	3.32	S6	0 years
41	357	2,183	(v) 65 years		0.83	R2	0 years
42	358.16	58	(w) 50 years		1.66	R3	0 years
43	TNC SUM	1,089,609	0 years				0 years
44	TRANSMISSION SUM	3,469,802	0 years				0 years
45	DISTRIBUTION		0 years				0 years
46	TCC		0 years				0 years
47	360 (Rights)	1,313	(x) 60 years		1.44	R5	0 years
48	361	13,992	(y) 64 years	21	0.88	R2.5	0 years
49	362	395,862	(z) 61 years	28	1.07	L0.5	0 years
50	362.16	517	(aa) 61 years	28	1.07	L0.5	0 years
51	364	649,489	(ab) 39 years	48	3.67	S0.5	0 years
52	365	599,062	(ac) 54 years	88	3.37	R0.5	0 years
53	366	57,316	(ad) 60 years	56	2.51	R3	0 years
54	367	286,005	(ae) 50 years	35	2.6	R1	0 years
55	368	541,327	(af) 40 years	13	2.55	S0	0 years
56	369	217,463	(ag) 35 years	41	3.83	SC	0 years
57	370	31,792	(ah) 22 years	15	5.56	R0.5	0 years
58	370.16	149,552	0 years		14.29		0 years
59	371	55,063	(ai) 35 years	12	2.19	L0	0 years
60	373	85,326	(aj) 35 years	30	3.22	SC	0 years
61	TCC SUM	3,084,079	0 years				0 years
62	TNC		0 years				0 years
63	360 (Rights)	2,163	(ak) 55 years		1.37	R2.5	0 years
64	361	5,421	(al) 52 years	15	2.24	R3	0 years
65	362	146,702	(am) 37 years	29	3.45	R0.5	0 years
66	362.16	457	(an) 37 years	29	3.45	R0.5	0 years
67	364	198,071	(ao) 35 years	15	3.6	L5	0 years
68	365	145,570	(ap) 50 years	40	2.72	R0.5	0 years
69	366	23,197	(aq) 70 years	40	1.79	R1.5	0 years
70	367	60,016	(ar) 36 years	20	3.03	R1.5	0 years
71	368	156,208	(as) 39 years	5	2.7	L2	0 years
72	369	86,456	(at) 30 years	50	6.41	S6	0 years
73	370	11,491	(au) 40 years	40	3.49	R0.5	0 years
74	370.16	38,792	0 years		14.29		0 years
75	371	15,280	(av) 28 years	56	5.77	R0.5	0 years
76	372	87	(aw) 50 years		2.89	R3	0 years
77	373	21,868	(ax) 30 years	10	4.56	S6	0 years
78	TNC SUM	911,779	0 years				0 years
79	DISTRIBUTION SUM	3,995,858	0 years				0 years
80	GENERAL PLANT		0 years				0 years
81	TCC		0 years				0 years
82	390	168,036	(ay) 40 years	19	1.1	R0.5	0 years
83	391	3,564	(az) 15 years	2	2.77	SQ	0 years
84	392	186	0 years		5		0 years
85	393	1,140	(ba) 22 years		8.52	SQ	0 years
86	394	31,609	(bb) 35 years		3.31	SQ	0 years
87	395	441	(bc) 33 years		0.58	SQ	0 years
88	396	192	(bd) 15 years	3	0.94	SQ	0 years
89	397	64,543	(be) 20 years		6.49	SQ	0 years
90	397.16	22,943	0 years		14.29		0 years
91	398	3,110	(bf) 20 years	2	8.62	SQ	0 years
92	TCC SUM	295,764	0 years				0 years
93	TNC		0 years				0 years
94	389 (Rights)	18	(bg) 50 years		1.83	R3	0 years
95	390-Dist & Trans	49,829	(bh) 36 years	14	4.69	S3	0 years
96	390-Gen	3	0 years				0 years
97	391-Dist & Trans	2,821	(bi) 25 years	1	5.21	SQ	0 years
98	391-Gen	185	0 years				0 years
99	391.11	3	(bj) 15 years		19.82	SQ	0 years
100	392-Dist & Trans	57	(bk) 15 years	1	6.39	SQ	0 years
101	392 (trailers)	18	0 years				0 years
102	392.11	22	(bl) 20 years	1	5	SQ	0 years
103	392.11-Gen	1	0 years				0 years
104	393-Dist & Trans	146	(bm) 20 years	3	5.66	SQ	0 years
105	393-Gen	29	0 years				0 years
106	394-Dist & Trans	15,972	(bn) 25 years		3.54	SQ	0 years
107	394-Gen	51	0 years				0 years
108	395-Gen	1,926	0 years				0 years
109	396-Gen	33	0 years				0 years
110	397-Dist & Trans	21,328	(bo) 15 years	1	6.58	SQ	0 years
111	397-Gen	238	0 years				0 years
112	397.12	11	(bp) 10 years		9.91	SQ	0 years
113	397.13	73	(bq) 22 years	2	3.97	SQ	0 years
114	397.16	13,237	0 years		14.29		0 years
115	398	1,997	(br) 28 years		3.52	SQ	0 years
116	398-Gen	52	0 years				0 years
117	TNC SUM	108,050	0 years				0 years
118	GENERAL PLANT SUM	403,814	0 years				0 years
119	DEPRECIABLE SUM	(a) 8,196,524	0 years				0 years

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: DepreciablePlantBase

The depreciable plant base is the November 30, 2018 total company depreciable plant.

(b) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 75

Original value: 55

(d) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 62

(e) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 62

(f) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 81

(g) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 70

(h) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 75

(i) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 75

(j) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 65

(k) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 50

(l) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 50

(m) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 65

(n) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 75

(o) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 50

(p) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 54

(q) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 54

(r) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 65

(s) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 45

(t) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 50

(u) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 50

(v) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 65

(w) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 50

(x) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 60

(y) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 64

(z) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 61

(aa) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 61

(ab) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 39

(ac) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 54

(ad) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 60

(ae) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 50

(af) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 40

(ag) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 35

(ah) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 22

(ai) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 35

(aj) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 35

(ak) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 55

(al) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 52

(am) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 37

(an) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 37

(ao) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 35

(ap) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 50

(aq) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 70

(ar) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 36

(as) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 39

(at) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 30

(au) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 40

(av) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 28

(aw) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 50

(ax) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 30

(ay) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 40

(az) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 15

(ba) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 22

(bb) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 35

(bc) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 33

(bd) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 15

(be) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 20

(bf) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 20

(bg) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 50

(bh) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 36

(bi) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 25

(bj) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 15

(bk) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 15

(bl) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 20

(bm) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 20

(bn) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 25

(bo) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 15

(bp) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 10

(bq) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 22

(br) Concept: UtilityPlantEstimatedAverageServiceLife

Original value: 28

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

REGULATORY COMMISSION EXPENSES
Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts. Minor items (less than $25,000) may be grouped.
						EXPENSES INCURRED DURING YEAR				AMORTIZED DURING YEAR
						EXPENSES INCURRED DURING YEAR
Line No.	RegulatoryCommissionDescription Description (Furnish name of regulatory commission or body the docket or case number and a description of the case) (a)	RegulatoryExpensesAssessedByRegulatoryCommission Assessed by Regulatory Commission (b)	RegulatoryExpensesOfUtility Expenses of Utility (c)	RegulatoryCommissionExpensesAmount Total Expenses for Current Year (d)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 at Beginning of Year (e)	NameOfDepartmentRegulatoryCommissionExpensesCharged Department (f)	AccountNumberRegulatoryCommissionExpensesCharged Account No. (g)	RegulatoryCommissionExpenses Amount (h)	RegulatoryCommissionExpensesDeferredToOtherRegulatoryAssets Deferred to Account 182.3 (i)	DeferredRegulatoryCommissionExpensesAmortizedInContraAccount Contra Account (j)	DeferredRegulatoryCommissionExpensesAmortized Amount (k)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred to Account 182.3 End of Year (l)
1	Various Rate Case Expenses pending
2	future PUCT (Public Utility Commission of
3	Texas) approval for collection from
4	customers				149,525				11,123			160,648
6	Expenses incurred relating to 2018 Texas Rate
7	Case		538,901	538,901		Electric	928	538,901
9	Expenses incurred related to Distribution
10	Cost Recovery Factor Filings -
11	PUCT Docket No.s. 45787, 45788, 47015
12	and 48222		176,161	176,161		Electric	928	176,161
14	Expenses incurred in Interim Transmission Cost
15	Cases and other Regulatory/Legislative
16	actions relating to Transmission -
17	PUCT Docket Nos 48507 and 48931		124,568	124,568		Electric	928	124,568
19	Expenses incurred related to managing
20	Formula Rates for AEP's West Operating
21	Companies and Transco's		33,016	33,016		Electric	928	33,016
23	Expenses incurred relating to Determination
24	of System Restoration Costs - Hurricane
25	Harvey - PUCT Docket No. 48577		706,392	706,392		Electric	928	706,392
27	Expenses incurred in Energy Efficiency Cost
28	Recovery Factor filings		29,411	29,411		Electric	928	29,411
30	Minor Items (less than $25,000)		64,531	64,531		Electric	928	64,531
46	TOTAL		1,672,980	1,672,980	149,525			1,672,980	11,123			160,648

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D and D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts). Indicate in column (a) the applicable classification, as shown below: Classifications: Electric R, D and D Performed Internally: Generation hydroelectric Recreation fish and wildlife Other hydroelectric Fossil-fuel steam Internal combustion or gas turbine Nuclear Unconventional generation Siting and heat rejection Transmission Overhead Underground Distribution Regional Transmission and Market Operation Environment (other than equipment) Other (Classify and include items in excess of $50,000.) Total Cost Incurred Electric, R, D and D Performed Externally: Research Support to the electrical Research Council or the Electric Power Research Institute Research Support to Edison Electric Institute Research Support to Nuclear Power Groups Research Support to Others (Classify) Total Cost Incurred Include in column (c) all R, D and D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D and D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D and D activity. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e). Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year. If costs have not been segregated for R, D and D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by ""Est."" Report separately research and related testing facilities operated by the respondent.
					AMOUNTS CHARGED IN CURRENT YEAR
Line No.	ResearchDevelopmentAndDemonstrationClassification Classification (a)	ResearchDevelopmentAndDemonstrationDescription Description (b)	ResearchDevelopmentAndDemonstrationCostsIncurredInternally Costs Incurred Internally Current Year (c)	ResearchDevelopmentAndDemonstrationCostsIncurredExternally Costs Incurred Externally Current Year (d)	AccountNumberForResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Account (e)	ResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Amount (f)	ResearchDevelopmentAndDemonstrationExpenditures Unamortized Accumulation (g)
1	A. (2) Transmission	Transmission RD&D Program Mgmt	24,686		566	24,686
2	A. (3) Distribution	2 Items < $50,000	12,386		588	12,386
3		Distribution Program Management
4	A. (6) Other	3 Items < $50,000	10,840		566	10,840
5			11,208		588	11,208
6	A. (6)(f) Metering	Advanced Metering Equipment	6,810		588	6,810
7	A. (6)(g) Research General	DTC Walnut Test Facility	5,388		566	5,388
8			5,667		588	5,667
9	A. (7) Total Cost Incurred Intermally		76,985			76,985
10	B. Electric R&D External	6 Items < $50,000		18,027	566	18,027
11				58,461	588	58,461
12	B. (1) Electric Power Research Institute	EPRI Research Portfolio		383,671	566	383,671
13				79,347	588	79,347
14		Information Technology EPRI Annual Research Portfolio		13,018	566	13,018
15				65,584	588	65,584
16		9 Items < $50,000		14,259	566	14,259
17				6,826	588	6,826
18	B. (4) Research Support to Others	2 Items < $50,000		7,006	566	7,006
19	B. (5) Total Cost Incurred Externally			646,199		646,199
20		Total	76,985	646,199		723,184

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used.
Line No.	Classification (a)	Direct Payroll Distribution (b)	Allocation of Payroll Charged for Clearing Accounts (c)	Total (d)
1	SalariesAndWagesElectricAbstract Electric
2	SalariesAndWagesElectricOperationAbstract Operation
3	SalariesAndWagesElectricOperationProduction Production	5,953,806
4	SalariesAndWagesElectricOperationTransmission Transmission	4,147,670
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	22,223,509
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	4,782,023
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	2,606,049
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	1,462,609
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	41,175,666
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	2,228,140
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	3,182,857
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	19,538,226
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	3,999,485
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	28,948,708
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	8,181,946
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	7,330,527
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	41,761,735
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	4,782,023
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	2,606,049
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	5,462,094
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	70,124,374	3,854,051	73,978,425
29	SalariesAndWagesGasAbstract Gas
30	SalariesAndWagesGasOperationAbstract Operation
31	SalariesAndWagesGasOperationProductionManufacturedGas Production - Manufactured Gas
32	SalariesAndWagesGasOperationProductionNaturalGas Production-Nat. Gas (Including Expl. And Dev.)
33	SalariesAndWagesGasOperationOtherGasSupply Other Gas Supply
34	SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing Storage, LNG Terminaling and Processing
35	SalariesAndWagesGasOperationTransmission Transmission
36	SalariesAndWagesGasOperationDistribution Distribution
37	SalariesAndWagesGasCustomerAccounts Customer Accounts
59	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational
39	SalariesAndWagesGasSales Sales
40	SalariesAndWagesGasOperationAdministrativeAndGeneral Administrative and General
41	SalariesAndWagesGasOperation TOTAL Operation (Enter Total of lines 31 thru 40)
42	SalariesAndWagesGasMaintenanceAbstract Maintenance
43	SalariesAndWagesGasMaintenanceProductionManufacturedGas Production - Manufactured Gas
44	SalariesAndWagesGasMaintenanceProductionNaturalGas Production-Natural Gas (Including Exploration and Development)
45	SalariesAndWagesGasMaintenanceOtherGasSupply Other Gas Supply
46	SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing
47	SalariesAndWagesGasMaintenanceTransmission Transmission
48	SalariesAndWagesGasMaintenanceDistribution Distribution
49	SalariesAndWagesGasMaintenanceAdministrativeAndGeneral Administrative and General
50	SalariesAndWagesGasMaintenance TOTAL Maint. (Enter Total of lines 43 thru 49)
51	SalariesAndWagesGasOperationAndMaintenanceAbstract Total Operation and Maintenance
52	SalariesAndWagesGasProductionManufacturedGas Production-Manufactured Gas (Enter Total of lines 31 and 43)
53	SalariesAndWagesGasProductionNaturalGas Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54	SalariesAndWagesGasOtherGasSupply Other Gas Supply (Enter Total of lines 33 and 45)
55	SalariesAndWagesGasStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing (Total of lines 31 thru
56	SalariesAndWagesGasTransmission Transmission (Lines 35 and 47)
57	SalariesAndWagesGasDistribution Distribution (Lines 36 and 48)
37	SalariesAndWagesGasCustomerAccounts Customer Accounts (Line 37)
59	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational (Line 38)
60	SalariesAndWagesGasSales Sales (Line 39)
61	SalariesAndWagesGasAdministrativeAndGeneral Administrative and General (Lines 40 and 49)
62	SalariesAndWagesGasOperationAndMaintenance TOTAL Operation and Maint. (Total of lines 52 thru 61)
63	SalariesAndWagesOtherUtilityDepartmentsAbstract Other Utility Departments
64	SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance Operation and Maintenance
65	SalariesAndWagesOperationsAndMaintenance TOTAL All Utility Dept. (Total of lines 28, 62, and 64)	70,124,374	3,854,051	73,978,425
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	68,129,501	3,744,413	71,873,914
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	68,129,501	3,744,413	71,873,914
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	12,997,841	714,364	13,712,205
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	12,997,841	714,364	13,712,205
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription 152 - Fuel Stock Undistributed	197,770		197,770
79	SalariesAndWagesOtherAccountsDescription 122 - Depr and Amortization	3,684		3,684
80	SalariesAndWagesOtherAccountsDescription 188 - Research & Development	3,103		3,103
81	SalariesAndWagesOtherAccountsDescription 186 - Misc Deferred Debits	3,503,287		3,503,287
82	SalariesAndWagesOtherAccountsDescription 163 - Stores Expense Undistributed	5,411,313	5,411,313
83	SalariesAndWagesOtherAccountsDescription 426 - Political Activities	177,615		177,615
84	SalariesAndWagesOtherAccountsDescription 183 - Prelim Survey	7,044	7,044
85	SalariesAndWagesOtherAccountsDescription 184 - Clearing Accounts	2,894,471	2,894,471
86	SalariesAndWagesOtherAccountsDescription 185 - ODD Temporary Facilities	386,557		386,557
87	SalariesAndWagesOtherAccountsDescription
88	SalariesAndWagesOtherAccountsDescription
89	SalariesAndWagesOtherAccountsDescription
90	SalariesAndWagesOtherAccountsDescription
91	SalariesAndWagesOtherAccountsDescription
92	SalariesAndWagesOtherAccountsDescription
93	SalariesAndWagesOtherAccountsDescription
94	SalariesAndWagesOtherAccountsDescription
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	12,578,638	8,312,828	4,265,810
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	163,830,354		163,830,354

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

COMMON UTILITY PLANT AND EXPENSES
Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other authorization.

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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 Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff. In columns for usage, report usage-related billing determinant and the unit of measure. On line 1 columns (b), (c), (d), and (e) report the amount of ancillary services purchased and sold during the year. On line 2 columns (b), (c), (d), and (e) report the amount of reactive supply and voltage control services purchased and sold during the year. On line 3 columns (b), (c), (d), and (e) report the amount of regulation and frequency response services purchased and sold during the year. On line 4 columns (b), (c), (d), and (e) report the amount of energy imbalance services purchased and sold during the year. On lines 5 and 6, columns (b), (c), (d), and (e) report the amount of operating reserve spinning and supplement services purchased and sold during the period. On line 7 columns (b), (c), (d), and (e) report the total amount of all other types ancillary services purchased or sold during the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
		Amount Purchased for the Year			Amount Sold for the Year
		Usage - Related Billing Determinant			Usage - Related Billing Determinant
Line No.	Type of Ancillary Service (a)	Number of Units (b)	Unit of Measure (c)	Dollar (d)	Number of Units (e)	Unit of Measure (f)	Dollars (g)
1	Scheduling, System Control and Dispatch
2	Reactive Supply and Voltage
3	Regulation and Frequency Response
4	Energy Imbalance
5	Operating Reserve - Spinning
6	Operating Reserve - Supplement
7	Other
8	Total (Lines 1 thru 7)

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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	(a)
2	February
3	March
4	Total for Quarter 1
5	April
6	May
7	June
8	Total for Quarter 2
9	July
10	August
11	September
12	Total for Quarter 3
13	October
14	November
15	December
16	Total for Quarter 4
17	Total

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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 Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

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: Enter System
1	January
2	February
3	March
4	Total for Quarter 1
5	April
6	May
7	June
8	Total for Quarter 2
9	July
10	August
11	September
12	Total for Quarter 3
13	October
14	November
15	December
16	Total for Quarter 4
17	Total Year to Date/Year

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line No.	Item (a)	MegaWatt Hours (b)	Line No.	Item (a)	MegaWatt Hours (b)
1	SOURCES OF ENERGY		21	DISPOSITION OF ENERGY
2	Generation (Excluding Station Use):		22	Sales to Ultimate Consumers (Including Interdepartmental Sales)
3	Steam	(a)(b) 1,786,978	23	Requirements Sales for Resale (See instruction 4, page 311.)
4	Nuclear		24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	(c)(d) 1,654,639
5	Hydro-Conventional		25	Energy Furnished Without Charge
6	Hydro-Pumped Storage		26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)
7	Other	(e) 1,581	27	Total Energy Losses
8	Less Energy for Pumping		27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	(f) 1,788,559	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	1,788,559
10	Purchases (other than for Energy Storage)
10.1	Purchases for Energy Storage
11	Power Exchanges:
12	Received
13	Delivered
14	Net Exchanges (Line 12 minus line 13)
15	Transmission For Other (Wheeling)
16	Received	(g) 1,776,750
17	Delivered	(h) 1,776,750
18	Net Transmission for Other (Line 16 minus line 17)
19	Transmission By Others Losses
20	TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)	(i) 1,788,559

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: SteamGeneration

Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 3, Column: b, Value: 0

(b) Concept: SteamGeneration

AEP Texas' remaining generating capacity output that is not deactivated has

been transferred to an affiliated company at AEP Texas' cost pursuant to

a 20-year agreement.

Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 24, Column: b, Value: 1788559

(d) Concept: MegawattHoursSoldNonRequirementsSales

Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 24, Column: b, Value: 0

(e) Concept: OtherEnergyGeneration

Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 7, Column: b, Value: 0

(f) Concept: NetEnergyGeneration

Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 9, Column: b, Value: 0

(g) Concept: ElectricPowerWheelingEnergyReceived

Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 16, Column: b, Value: 0

(h) Concept: ElectricPowerWheelingEnergyDelivered

Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 17, Column: b, Value: 0

(i) Concept: SourcesOfEnergy

Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 20, Column: b, Value: 0

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

MONTHLY PEAKS AND 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)	EnergyActivity Total Monthly Energy (b)	NonRequiredSalesForResaleEnergy Monthly Non-Requirement Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak - Megawatts (d)	DayOfMonthlyPeak Monthly Peak - Day of Month (e)	HourOfMonthlyPeak Monthly Peak - Hour (f)
	NAME OF SYSTEM: 0
29	January	178,476	180,725	(a)		(b)
30	February	151,178	153,083			(c)
31	March	141,863	143,650			(d)
32	April	86,248	87,335			(e)
33	May	156	158			(f)
34	June	161,988	164,029			(g)
35	July	194,133	196,579			(h)
36	August	194,153	196,599			(i)
37	September	186,126	188,471			(j)
38	October	202,269	204,818			(k)
39	November	79,186	80,184			(l)
40	December	212,783	215,464			(m)
41	Total

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: MonthlyPeakLoad

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

Texas (ERCOT).

(b) Concept: HourOfMonthlyPeak

Original value: na

(d) Concept: HourOfMonthlyPeak

Original value: na

(e) Concept: HourOfMonthlyPeak

Original value: na

(f) Concept: HourOfMonthlyPeak

Original value: na

(g) Concept: HourOfMonthlyPeak

Original value: na

(h) Concept: HourOfMonthlyPeak

Original value: na

(i) Concept: HourOfMonthlyPeak

Original value: na

(j) Concept: HourOfMonthlyPeak

Original value: na

(k) Concept: HourOfMonthlyPeak

Original value: na

(l) Concept: HourOfMonthlyPeak

Original value: na

(m) Concept: HourOfMonthlyPeak

Original value: na

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

Steam Electric Generating Plant Statistics

1. Report data for plant in Service only.
2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.
3. Indicate by a footnote any plant leased or operated as a joint facility.
4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.
5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant.
6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.
7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.
8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.
10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants.
11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.
12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.

Line No.	Item (a)	Plant Name: (a) Oklaunion
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)	Steam
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)	Outdoor Boiler
3	YearPlantOriginallyConstructed Year Originally Constructed	1986
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	1986
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)	393.77
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)	360
7	PlantHoursConnectedToLoad Plant Hours Connected to Load	7,396
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water	366
11	PlantAverageNumberOfEmployees Average Number of Employees
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - KWh	1,788,559,000
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights	6,241,381
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements	50,120,891
15	CostOfEquipmentSteamProduction Equipment Costs	275,297,299
16	AssetRetirementCostsSteamProduction Asset Retirement Costs	20,417,918
17	CostOfPlant Total cost (total 13 thru 20)	352,077,489
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including	894.1196
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr	2,368,252
20	FuelSteamPowerGeneration Fuel	37,803,384
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)
22	SteamExpensesSteamPowerGeneration Steam Expenses	1,535,775
23	SteamFromOtherSources Steam From Other Sources
24	SteamTransferredCredit Steam Transferred (Cr)
25	ElectricExpensesSteamPowerGeneration Electric Expenses	1,162,016
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses	5,522,205
27	RentsSteamPowerGeneration Rents
28	Allowances Allowances
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering	720,663
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures	935,181
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant	3,952,644
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant	640,078
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant	364,160
34	PowerProductionExpensesSteamPower Total Production Expenses	55,004,358
35	ExpensesPerNetKilowattHour Expenses per Net KWh	0.0308

35	FuelKindAxis Plant Name	Oklaunion	Oklaunion	Oklaunion
36	FuelKind Fuel Kind	Coal	Composite	Oil
37	FuelUnit Fuel Unit	TONS		BBLS
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned	127,328		312
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)	8,428		136,520
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year	37.233		95.209
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned	34.226		91.914
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	2.03		38.49
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per KWh Net Gen	0.02
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per KWh Net Generation	10,090	5,046	10,090

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: PlantName

AEP Texas's Oklaunion generating capacity output has been transferred to an affiliate at AEPTX's cost pursuant to a 20-year agreement.

Oklaunion Power Plant is jointly owned in the percentages shown below:

AEP Texas 54.69%

Public Service Company of Oklahoma (AEP Subsidiary) 15.62%

Oklahoma Municipal Power Authority 11.72%

Brownsville Public Utilities Board 17.97%

100.00%

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

Hydroelectric Generating Plant Statistics

Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings).
If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number.
If net peak demand for 60 minutes is not available, give that which is available specifying period.
If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant.
The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.

Line No.	Item (a)	FERC Licensed Project No. Plant Name:	FERC Licensed Project No. Plant Name:	FERC Licensed Project No. Plant Name:	FERC Licensed Project No. Plant Name:	FERC Licensed Project No. Plant Name:
1	PlantKind Kind of Plant (Run-of-River or Storage)
2	PlantConstructionType Plant Construction type (Conventional or Outdoor)
3	YearPlantOriginallyConstructed Year Originally Constructed
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed
5	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)
6	NetPeakDemandOnPlant Net Peak Demand on Plant-Megawatts (60 minutes)
7	PlantHoursConnectedToLoad Plant Hours Connect to Load
8	NetPlantCapabilityAbstract Net Plant Capability (in megawatts)
9	NetPlantCapabilityUnderMostFavorableOperatingConditions (a) Under Most Favorable Oper Conditions
10	NetPlantCapabilityUnderMostAdverseOperatingConditions (b) Under the Most Adverse Oper Conditions
11	PlantAverageNumberOfEmployees Average Number of Employees
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - Kwh
13	CostOfPlantAbstract Cost of Plant
14	CostOfLandAndLandRightsHydroelectricProduction Land and Land Rights
15	CostOfStructuresAndImprovementsHydroelectricProduction Structures and Improvements
16	CostOfReservoirsDamsAndWaterwaysHydroelectricProduction Reservoirs, Dams, and Waterways
17	EquipmentCostsHydroelectricProduction Equipment Costs
18	CostOfRoadsRailroadsAndBridgesHydroelectricProduction Roads, Railroads, and Bridges
19	AssetRetirementCostsHydroelectricProduction Asset Retirement Costs
20	CostOfPlant Total cost (total 13 thru 20)
21	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 20 / 5)
22	ProductionExpensesAbstract Production Expenses
23	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering
24	WaterForPower Water for Power
25	HydraulicExpenses Hydraulic Expenses
26	ElectricExpensesHydraulicPowerGeneration Electric Expenses
27	MiscellaneousHydraulicPowerGenerationExpenses Misc Hydraulic Power Generation Expenses
28	RentsHydraulicPowerGeneration Rents
29	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration Maintenance Supervision and Engineering
30	MaintenanceOfStructuresHydraulicPowerGeneration Maintenance of Structures
31	MaintenanceOfReservoirsDamsAndWaterways Maintenance of Reservoirs, Dams, and Waterways
32	MaintenanceOfElectricPlantHydraulicPowerGeneration Maintenance of Electric Plant
33	MaintenanceOfMiscellaneousHydraulicPlant Maintenance of Misc Hydraulic Plant
34	PowerProductionExpensesHydraulicPower Total Production Expenses (total 23 thru 33)
35	ExpensesPerNetKilowattHour Expenses per net KWh

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

Pumped Storage Generating Plant Statistics
Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings). If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number. If net peak demand for 60 minutes is not available, give the which is available, specifying period. If a group of employees attends more than one generating plant, report on line 8 the approximate average number of employees assignable to each plant. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses." Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
Line No.	Item (a)	FERC Licensed Project No. Plant Name:	FERC Licensed Project No. Plant Name:	FERC Licensed Project No. Plant Name:	FERC Licensed Project No. Plant Name:
1	PlantConstructionType Type of Plant Construction (Conventional or Outdoor)
2	YearPlantOriginallyConstructed Year Originally Constructed
3	YearLastUnitOfPlantInstalled Year Last Unit was Installed
4	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)
5	NetPeakDemandOnPlant Net Peak Demaind on Plant-Megawatts (60 minutes)
6	PlantHoursConnectedToLoad Plant Hours Connect to Load While Generating
7	NetContinuousPlantCapability Net Plant Capability (in megawatts)
8	PlantAverageNumberOfEmployees Average Number of Employees
9	NetGenerationExcludingPlantUse Generation, Exclusive of Plant Use - Kwh
10	EnergyUsedForPumping Energy Used for Pumping
11	NetOutputForLoad Net Output for Load (line 9 - line 10) - Kwh
12	CostOfPlantAbstract Cost of Plant
13	CostOfLandAndLandRightsPumpedStoragePlant Land and Land Rights
14	CostOfStructuresAndImprovementsPumpedStoragePlant Structures and Improvements
15	CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant Reservoirs, Dams, and Waterways
16	CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant Water Wheels, Turbines, and Generators
17	CostOfAccessoryElectricEquipmentPumpedStoragePlant Accessory Electric Equipment
18	CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant Miscellaneous Powerplant Equipment
19	CostOfRoadsRailroadsAndBridgesPumpedStoragePlant Roads, Railroads, and Bridges
20	AssetRetirementCostsPumpedStoragePlant Asset Retirement Costs
21	CostOfPlant Total cost (total 13 thru 20)
22	CostPerKilowattOfInstalledCapacity Cost per KW of installed cap (line 21 / 4)
23	ProductionExpensesAbstract Production Expenses
24	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering
25	WaterForPower Water for Power
26	PumpedStorageExpenses Pumped Storage Expenses
27	ElectricExpensesPumpedStoragePlant Electric Expenses
28	MiscellaneousPumpedStoragePowerGenerationExpenses Misc Pumped Storage Power generation Expenses
29	RentsPumpedStoragePlant Rents
30	MaintenanceSupervisionAndEngineeringPumpedStoragePlant Maintenance Supervision and Engineering
31	MaintenanceOfStructuresPumpedStoragePlant Maintenance of Structures
32	MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant Maintenance of Reservoirs, Dams, and Waterways
33	MaintenanceOfElectricPlantPumpedStoragePlant Maintenance of Electric Plant
34	MaintenanceOfMiscellaneousPumpedStoragePlant Maintenance of Misc Pumped Storage Plant
35	PowerProductionExpenseBeforePumpingExpenses Production Exp Before Pumping Exp (24 thru 34)
36	PumpingExpenses Pumping Expenses
37	PowerProductionExpensesPumpedStoragePlant Total Production Exp (total 35 and 36)
38	ExpensesPerNetKilowattHour Expenses per KWh (line 37 / 9)
39	ExpensesPerNetKilowattHourGenerationAndPumping Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

GENERATING PLANT STATISTICS (Small Plants)
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give project number in footnote. 3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
									Production Expenses
Line No.	PlantName Name of Plant (a)	YearPlantOriginallyConstructed Year Orig. Const. (b)	InstalledCapacityOfPlant Installed Capacity Name Plate Rating (MW) (c)	Net Peak Demand MW (60 min) (d)	NetGenerationExcludingPlantUse Net Generation Excluding Plant Use (e)	Cost of Plant (f)	PlantCostPerMw Plant Cost (Incl Asset Retire. Costs) Per MW (g)	OperatingExpensesExcludingFuel Operation Exc'l. Fuel (h)	Fuel Production Expenses (i)	MaintenanceProductionExpenses Maintenance Production Expenses (j)	FuelKind Kind of Fuel (k)	FuelCostPerMmbtus Fuel Costs (in cents (per Million Btu) (l)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

ENERGY STORAGE OPERATIONS (Large Plants)
Large Plants are plants of 10,000 KW or more. In columns (a) (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location. In column (d), report Megawatt hours (MWH) purchased, generated, or received in exchange transactions for storage. In columns (e), (f) and (g) report MWHs delivered to the grid to support production, transmission and distribution. The amount reported in column (d) should include MWHs delivered/provided to a generator’s own load requirements or used for the provision of ancillary services. In columns (h), (i), and (j) report MWHs lost during conversion, storage and discharge of energy. In column (k) report the MWHs sold. In column (l), report revenues from energy storage operations. In a footnote, disclose the revenue accounts and revenue amounts related to the income generating activity. In column (m), report the cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. In columns (n) and (o), report fuel costs for storage operations associated with self-generated power included in Account 501 and other costs associated with self-generated power. In columns (q), (r) and (s) report the total project plant costs including but not exclusive of land and land rights, structures and improvements, energy storage equipment, turbines, compressors, generators, switching and conversion equipment, lines and equipment whose primary purpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property accounts listed.
Line No.	Name of the Energy Storage Project (a)	Functional Classification (b)	Location of the Project (c)	MWHs (d)	MWHs delivered to the grid to support Production (e)	MWHs delivered to the grid to support Transmission (f)	MWHs delivered to the grid to support Transmission (g)	MWHs Lost During Conversion, Storage and Discharge of Energy Production (h)	MWHs Lost During Conversion, Storage and Discharge of Energy Transmission (i)	MWHs Lost During Conversion, Storage and Discharge of Energy Distribution (j)	MWHs Sold (k)	Revenues from Energy Storage Operations (l)	Power Purchased for Storage Operations (555.1) (Dollars) (m)	Fuel Costs from associated fuel accounts for Storage Operations Associated with Self- Generated Power (Dollars) (n)	Other Costs Associated with Self-Generated Power (Dollars) (o)	Project Costs included in (p)	Production (Dollars) (q)	Transmission (Dollars) (r)	Distribution (Dollars) (s)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35	TOTAL

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

TRANSMISSION LINE STATISTICS
Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. Report data by individual lines for all voltages if so required by a State commission. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g). Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
	DESIGNATION		VOLTAGE (KV) - (Indicate where other than 60 cycle, 3 phase)			LENGTH (Pole miles) - (In the case of underground lines report circuit miles)				COST OF LINE (Include in column (j) Land, Land rights, and clearing right-of-way)			EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	OperatingVoltageOfTransmissionLine Operating	DesignedVoltageOfTransmissionLine Designated	SupportingStructureOfTransmissionLineType Type of Supporting Structure	LengthForStandAloneTransmissionLines On Structure of Line Designated	LengthForTransmissionLinesAggregatedWithOtherStructures On Structures of Another Line	NumberOfTransmissionCircuits Number of Circuits	SizeOfConductorAndMaterial Size of Conductor and Material	CostOfLandAndLandRightsTransmissionLines Land	ConstructionAndOtherCostsTransmissionLines Construction Costs	OverallCostOfTransmissionLine Total Costs	OperatingExpensesOfTransmissionLine Operation Expenses	MaintenanceExpensesOfTransmissionLine Maintenance Expenses	RentExpensesOfTransmissionLine Rents	OverallExpensesOfTransmissionLine Total Expenses
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)
1	AEP TEXAS CENTRAL
2	TL1083 NORTH EDINBURG	RIO HONDO	345	345	1	15.38		1	2x795.0 ACSR
3					2	22.92
4	TL1098 LA PALMA	RIO HONDO	345	345	1	0.17		1	795.0 ACSR
5					2	0.13		1	795.0 ACSR
6	TL3113A BLESSING	STP	345	345	2	13.23		1	2x795.0 ACSR
7	(a) TL3131 STP	WA PARRISH	345	345	2	14.22		1	2x795.0 ACSR
8	TL5109 LON C HILL	CPSB TIE (SAN ANTONIO)	345	345	1	1.81		1	2x795.0 ACSR
9					2	55.54			2x795.0 ACSR
10	TL5114 LON HILL	WHITEPOINT CKT #1	345	345	1	9.78		2	2x795.0 ACSR
11	TL5114 LON HILL	WHITEPOINT CKT #1	345	345	2	11		1	2x795.0 ACSR
12	TL5115 WHITEPOINT	STP	345	345	1	9.75		1	2x795.0 ACSR
13					2	87.11		1	2x795.0 ACSR
14					2	27		1	2x1025.4 ACCC
15	TL5138 AJO	RIO HONDO	345	345	1	1		1	2x1590.0 ACSR
16					2	65.71			1026 KCM ACCC
17	TL5138A LON HILL	NELSON SHARPE	345	345	2	20.81		1	2x795.0 ACSR
18	TL5138B AJO	NELSON SHARPE	345	345	1	0.84		1	2x1590.0 ACSR
19					2	36.2			2x795.0 ACSR
20	TL5138E LA PALMA	RIO HONDO CKT #2	345	345	2	9.75		1	2x795.0 ACSR
21	TL5139 COLETO CREEK	LON HILL	345	345	1	20.33		1	2x795.0 ACSR
22					2	59.02
23	TL5145 LON HILL	NORTH EDINBURG	345	345	1	0.3		1	2x1026 ACCC
24	TL5145 LON HILL	NORTH EDINBURG	345	345	2	111.65		1	2x1026 ACCC
25	TL3131 STP	HL&P CORRIDOR	345	345	2		19.35	5	2x795 ACSR
26	TL1001 BATES	GARZA	138	138	1	30.42	3.38	1	795.0 ACSR
27	TL1002A GARZA	ROMA TAP	138	138	1	16.39	1.56	1	795.0 ACSR
28	TL1002B FALCON SWITCHING	ROMA TAP	138	138	1	4.87		1	795.0 ACSR
29	TL1002C FALCON SWITCHING	FALCON DAM (US) CKT#1	138	138	2	4.5		1	4/0 ACSR
30	TL1004 BATES	NORTH EDINBURG CKT#1	138	138	1	22.17		1	1272.0 ACSR
31	TL1005 FALFURIAS	NORTH EDINBURG	138	138	1	37.8		1	795.0 ACSR
32	TL1006 JL BATES	SHARYLAND	138	138	1	0.31		1	1272.0 ACSS
33	TL1008 LA PALMA	WESMER	138	138	1	16.03		1	795.0 ACSR
34					2			1	795.0 ACSR
35					2	0.03		1	795.0 ACSS/AW
36	TL1019 FRONTERA	NORTH MCALLEN	138	138	1	12.8		1	1272.0 ACSR
37					1	0.33		2	1272.0 ACSR
38	TL1009A HARLINGEN SS	RIO HONDO	138	138	1	1.76		1	795.0 ACSR/AW
39	TL1009A HARLINGEN SS	RIO HONDO	138	138	2	12.16		1	795.0 ACSR/AW
40	TL1009B RAYMONDVILLE #2	RIO HONDO	138	138	2	23.89		1	795.0 ACSR
41	TL1010 LOYOLA	RAYMONDVILLE #2	138	138	2	31.99		1	795.0 ACSR
42	TL1011 FRONTERA	RIO GRANDE CITY	138	138	1	3.54		1	795.0 ACSR
43	TL1029B LA PALMA	STEWART ROAD	69	138	1		2.2	1	4/0 ACSR
44					2	20.64			795.0 ACSS
45	TL1054 HARLINGEN SS	ACSR	138	138	2	1.71		1	795.0 ACSR
46	TL1059 SOUTHEAST EDINBURG	MVEC PHARR	138	138	1	1.63		1	795.0 ACSS
47	TL1060 POLK	SOUTH MCALLEN	138	138	1	2.71		1	795.0 ACSS
48	TL1061 HEC	NORTH EDINBURG CKT #1	138	138	1	1.06		1	2x795.0 ACSR
49	TL1062 HEC	WESLACO SS	138	138	1	4.4		1	795.0 ACSR
50	TL1070 PORT ISABEL	PORT ISABEL	138	138	1	6.74		1	336.0 ACSR
51	TL1071 PORT ISABEL	PORT ISABEL	138	138	1	6.89		1	336.0 ACSR
52	TL1072 NORTH EDINBURG	SOUTH EDINBURG	138	138	1	7.3		1	795.0 ACSS
53	TL1072A HEC EXTENSION		138	138	1	0.8		2	795.0 ACSS
54	TL1073 STEWART ROAD	WESLACO UNIT	138	138	2	14.66		1	477.0 ACSR
55									795.0 ACSR
56	TL1073C SOUTH MCALLEN	STEWART ROAD	138	138	2	10.06		1	795.0 ACSR
57	TL1074B LA PALMA	LAURELES	138	138	1	9.4		1	795.0 ACSR
58	TL1074C LAURELES	PORT ISABEL	138	138	1	7.62		1	795.0 ACSR
59	TL1074C LAURELES	PORT ISABEL			2	6.87			795.0 ACSR
60	TL1075 LA PALMA	PUB LOMA ALTA	138	138	1	12.22		1	795.0 AAAC
61					2	10.14			795.0 ACSR
62	TL1076 UNION CARBIDE	PUB LOMA ALTA	138	138	2	1.14		1	795.0 ACSR
63	TL1077 PORT ISABEL	UNION CARBIDE BROWNSVILLE	138	138	2	12.85		1	477.0 ACSR
64									795.0 ACSR
65	TL1079 LA PALMA	WESLACO UNIT	138	138	1	5.33		1	477.0 AAC
66	TL1080 LA PALMA	MILITARY HIGHWAY	138	138	1	2.03		1	795.0 ACSR
67					2	19.01
68	TL1081 NORTH MCALLEN	SOUTH MCALLEN	138	138	1	4.71		1	795.0 ACSS
69	TL1082 PHARR (MVEC)	PHARR	138	138	1	3.61		1	795.0 ACSS
70	TL1084 POLK	SOUTH MCALLEN	138	138	1	3.66		1	795.0 ACSR
71	TL1085 PALMHURST TAP		138	138	1	1.7		1	1270.0 ACSR
72	TL1086A NORTH EDINBURG	MVG (CALPINE) GT1	138	138	1	0.18		1	1590.0 ACSR
73	TL1086B NORTH EDINBURG	MVG (CALPINE) GT2	138	138	1	0.18		1	1590.0 ACSR
74	TL1086C NORTH EDINBURG	MVG (CALPINE) ST1	138	138	1	0.17		1	1590.0 ACSR
75	TL1091 MILITARY HIGHWAY	UNION CARBIDE	138	138	1	4.75		1	795.0 ACSR
76	TL1092 NORTH EDINBURG	NORTH MCALLEN	138	138	1	9.6		2	795.0 ACSS
77	TL1093 NORTH MCALLEN	SOUTH MCALLEN	138	138	1	2.63		1	795.0 ACSS
78					2	0.65
79	TL1094 LAS MILPAS	SOUTH MCCALLEN	138	138	1	0.3		1	959 ACSS
80	TL1095 MILITARY HIGHWAY	CFE TIE	138	138	1	0.14		1	795.0 ACSR
81	TL1096 PORT ISABEL	PORT ISABEL	138	138	4	8.56		1	750.0 MCM CU
82	TL1097 LA PALMA	RIO HONDO CKT #1	138	138	1	10.09		1	2x795.0 ACSS
83	TL1117 FRONTERA	SOUTH MCALLEN	138	138	1	14.66		1	1272.0 ACSR
84	TL1117A AGAVE	SLU TAYLOR	138	138	1	0.15		1	1272.0 ACSR
85	TL1119 RIO GRANDE CITY	ROMA TAP	138	138	1	7.61		1	795.0 ACSR
86	TL1121 PHARR	POLK AVENUE	138	138	1	3.57		1	795.0 ACSS
87	TL1122 HEC	WESLACO SS	138	138	1	11.52		1	795.0 ACSR
88	TL3001 VICTORIA	MEDIO CREEK	138	138	2	46.56		1	336.4 ACSR
89			138	138	2	0.34		1	795.0 ACSR
90			138	138	2	0.35		1	4/0 ACSR
91	TL3146 MEDIO CREEK	LON C HILL	138	138	1	0.3		1	959.6 ACSS/TW
92			138	138	1	24.5		1	336.4 ACSR
93			138	138	1	1.2		1	795 ACSR
94	TL3002 COLETO	KENEDY SS	138	138	2	45.14		1	795.0 ACSR
95	TL3003 KENEDY SS	CPSB V.H. BRAUNIG	138	138	2	13.71		1	477.0 ACSR
96	TL3004 KENEDY SS	PLEASANTON	138	138	2	40.14		1	266.8 ACSR
97	TL3005 VICTORIA	EDNA	138	138	2	21.57		1	795.0 ACSR
98	TL3006 EDNA	GANADO	138	138	2	9.72		1	795.0 ACSR
99	TL3007 GANADO	EL CAMPO	138	138	1	2.09		1	795.0 AAAC
100			138	138	2	17.93			795.0 ACSR
101	TL3008 EL CAMPO	LANE CITY	138	138	1	1.43		1	795.0 AAC
102					2	15.81			795.0 ACSR
103	TL3009 EL CAMPO	LANE CITY	138	138	2	1.41		1	795.0 ACSR
104	TL3010 LOLITA	VICTORIA	138	138	2	23.96		1	795.0 ACSR
105					3	4.36		2	795.0 ACSR
106	TL3011 BLESSING	LOLITA	138	138	2	22.51		1	795.0 ACSR
107	TL3012 BLESSING	LANE CITY	138	138	2	25.5		1	477.0 ACSR
108	TL3013 DUPONT SS	VICTORIA NORTH	138	138	3	7.77		2	795.0 ACSR
109	TL3014 BIG THREE	DUPONT SS	138	138	2	3.39		1	477.0 ACSR
110			138	138	2	0.62			795.0 ACSR
111	TL3015 FORMOSA	LOLITA	138	138	2	11.84		1	795.0 ACSR
112	TL3016 JOSLIN	ALCOA (1)	138	138	1	1	0.09	1	1590.0 ACSR
113	TL3017 JOSLIN	ALCOA (2)	138	138	3	0.09	1	1	1590.0 ACSR
114	TL3018 E S JOSLIN	UNION CARBIDE	138	138	3	0.43		2	795.0 ACSR & 4/0
115					3	14.64		1	795.0 ACSR
116					1	3.48		2	795.0 ACSR & 4/0
117					1	1.92		1	795.0 ACSR
118	TL3019 AIRCO	RINCON	138	138	2	51.3		1	477.0 ACSR
119	TL3021 DUPONT SS	DUPONT # 1	138	138	1	2.09		1	795.0 AAC
120	TL3022 CELANESE	CONOCO	138	138	1	0.06		1	795.0 ACSR
121	TL3026 DUPONT SS	DUPONT # 2	138	138	1	2.08		1	795.0 AAC
122	TL3027 DUPONT SS	VICTORIA SOUTH	138	138	3	7.65		1	795.0 ACSR
123	TL3034 BLESSING	CELANESE BAY CITY	138	138	2	5.74		1	795.0 ACSR
124	TL3035 BAY CITY	CONOCO	138	138	1	0.84		1	795.0 ACSR
125					2	18.68
126	TL3036 BAY CITY	LANE CITY	138	138	1	0.14		1	795.0 ACSR
127					2	14.9
128	TL3044 SIGMOR	THREE RIVERS	138	138	2	0.42		1	959.6 ACSS
129					2	3.17		1	795 ACSR/AW
130	TL3045 SIGMOR	STEC ORANGE GROVE	138	138	2	1.83		1	795.0 ACSR
131	TL3046 SIGMOR	STEC SAN MIGUEL	138	138	1	2.41		1	1/0 ACSR
132					2	1.83			795.0 ACSR
133	TL3077 GOLIAD	BERCLAIR	69	138	1	0.02		1	477ACSR/AW
134	TL3084 VICTORIA	LCRA CUERO	138	138	1	4.04		1	795.0 ACSR
135					2	13.82
136	TL3085 VICTORIA	LCRA CUERO	138	138	2	10.88		1	795.0 ACSR
137	TL3111 DUPONT SS	JOSLIN	138	138	2	17.36		1	795.0 ACSR
138					3	0.95
139	TL3112 DUPONT SS	JOSLIN	138	138	1	0.42		1	795.0 ACSR
140					2	13.68
141	TL3112 DUPONT SS	JOSLIN			3	0.18
142	TL3113B BLESSING	CELANESE BAY CITY	138	138	2	5.8		1	795.0 ACSR
143	TL3114 STP PUMP TAP	STP CONSTRUCTION	138	138	3	6.4		1	795.0 ACSR
144	TL3115 STP CONSTRUCTION	STP RIVER PUMP	138	138	1	4.36		1	4/0 ACSR
145	TL3118 COLETO CREEK NORTH	VICTORIA	138	138	2	11.1		1	1590.0 ACSR
146					3	4.81
147	TL3119 COLETO CREEK SOUTH	VICTORIA	138	138	2	6.76		1	1590.0 ACSR
148					3	8.84
149	TL3122 CARBIDE SEADRIFT	VISTRON	138	138	2	6.13		1	477.0 ACSR
150									795.0 ACSR
151	TL3124 FORMOSA	JOSLIN	138	138	2	0.69		1	795.0 ACSR
152					3	1.84
153	TL3125 BIG THREE	VISTRON	138	138	2	10.52		1	477.0 ACSR
154									795.0 ACSR
155	TL3126 CELANESE	CONOCO	138	138	2	10.37		1	795.0 ACSR
156	TL3127 AIRCO	CARBIDE	138	138	2	1.43		1	477.0 ACSR
157	TL3128 FANNIN	GOLIAD	69	138	1	0.04		1	477 ACSR/AW
158	TL3139 CHASEFIELD TAP#2	CHASEFIELD	69	138	1	4.58		1	795.0 ACSR
159	TL3151 VICTORIA	(STEC) FANNIN	69	138	3	15.32		1	1025 ACCC
160	TL5001 KINGSVILLE	LON HILL	138	138	1	37.29		1	795.0 ACSR
161			138	138	1	0.5		1	477 ACSR
162					2	29.07
163					3	6.87
164	TL5002 KINGSVILLE	KLEBERG	138	138	1	1.37		1	795.0 ACSR
165					2	4.13
166	TL5003A KLEBERG	LOYOLA	138	138	2	13.5		1	795.0 ACSR
167	TL5003B LOYOLA	RAYMONDVILLE #2	138	138	2	26.06		1	795.0 ACSR
168	TL5004 LON HILL	STRATTON	138	138	2	27.8		1	795.0 ACSR
169	TL5005A DAVIS	NELSON SHARPE	138	138	2	10.1		1	795.0 ACSR
170	TL5005B CELANESE	NELSON SHARPE	138	138	2	10.18		1	795.0 ACSR
171	TL5006A FALFURIAS	KING RANCH GAS PLANT	138	138	2	20.48		1	795.0 ACSR
172	TL5006B KING RANCH GAS	STRATTON	138	138	2	15.76		1	795.0 ACSR
173	TL5007 HIGHWAY9	JAVELINA	138	138	1		1.5	1	1272.0 ACSR
174	TL5008 JAVELINA	WESTSIDE	138	138	1	1.14	1.52	1	1272.0 ACSR
175					3	0.13
176	TL5009 LON C HILL	WHITEPOINT	138	138	3	0.72		2	2x795.0 ACSR & 7
177					3	0.33		1	2x795.0 ACSR
178					1	15.21		1	2x795.0 ACSR
179					1	2.9		2	2x795.0 ACSR & 7
180					2	0.26
181	TL5011 CITGO WEST	LON HILL	138	138	2	6.12		1	795.0 ACSR
182	TL5013 WESTSIDE	HOLLY	138	138	1	2.68		1	1590.0 ACSR
183					1	1.28		2	1590.0 ACSR
184	TL5016 B M DAVIS	RODD FIELD	138	138	1	0.06	2.8	1	T2 795
185					1	0.06		1	1590.0 ACSR
186	TL5017 HIGHWAY 9	NUECES BAY CKT #2	138	138	4	0.41	0.18	1	1272.0 ACSR
187									2500.0 CU
188	TL5017 NUECES BAY	CABLE TERMINAL	138	138	4	0.02		1	3500kcmil XLPE
189	TL5019 HIGHWAY 9	NUECES BAY CKT #2	138	138	1	0.35	0.35	1	1272.0 ACSR
190	TL5020 MORRIS STREET	NUECES BAY	138	138	1	2.65		1	795.0 AAC
191					1	1.13		1	795.0 ACSR
192					1	1.13		1	795.0 ACSR
193	TL5021 MORRIS STREET	WESTSIDE	138	138	1	3.74		1	795.0 AAAC
194					1	1.39		2	795.0 ACSR/ 1590
195					1	0.14		1	477 ACSR
196	TL5022 HIGHWAY 9	NUECES BAY CKT #1	138	138	3	0.18		1	1272.0 ACSR
197					4	0.41			2500.0 CU
198	TL5022 NUECES	CABLE TERMINAL #2	138	138	4	0.02		1	3500kcmil XLPE
199	TL5025 AS&R	WEIL TRACT	69	138	1	0.06		1	795ACSR
200	TL5027 B M DAVIS	PHARAOH	138	138	1	0.06	2.76	1	T2 795
201					1	0.07	0.15	1	1590.0 ACSR
202	TL5029 ALICE	KINGSVILLE	138	138	2	22.48		1	477.0 ACSR
203									795.0 ACSR
204	TL5031 LON HILL	CITY OF ROBSTOWN	69	138	1	0.74		1	795.0 ACSR
205	TL5032 PHARAOH	AIRLINE	138	138	1	1.43		2	1590.0 ACSR
206					3	0.12		2	1590.0 ACSR
207					1	0.33		1	1590.0 ACSR
208	TL5058A DUPONT SS	WHITEPOINT CKT#1	138	138	1	0.15	8	1	795.0 ACSR
209	TL5058B DUPONT SS	WHITEPOINT CKT#2	138	138	1	0.15		1	795.0 ACSR
210					3	8
211	TL5058C NUECES BAY	WHITEPOINT CKT #1	138	138	1	0.46		1	795.0 ACSR
212					2	12.25
213	TL5061A RINCON	WHITEPOINT CKT #1	69	138	1	3.26	0.75	1	795.0 ACSR
214	TL5061B SINTON	WHITEPOINT	69	138	1	3.82		1	795.0 ACSR
215	TL5062 SINTON	WHITEPOINT	69	138	1	9.5		1	795.0 ACSR
216	TL5072A ARANSAS PASS	DUPONT SS	138	138	1	0.91		1	795.0 ACSR
217					2	2.29
218	TL5072B DUPONT SS	RINCON CKT#2	138	138	3	0.06	10.5	1	795.0 ACSR
219	TL5073 DUPONT SS	RINCON CKT#1	138	138	1	0.19		1	795.0 ACSR
220					3	10.5
221	TL5077 ARANSAS PASS	DUPONT SS	138	138	1	0.91		1	795.0 ACSR
222					2	3.96
223	TL5078 NUECES BAY	WHITEPOINT CKT #2	138	138	1	0.21	2.65	1	795.0 ACSR
224					2	7.63
225	TL5079 DUPONT SW.	PORTLAND	138	138	1	7.62		1	2x795.0 ACSR
226	TL5082 ARANSAS PASS	ROCKPORT	69	138	1	0.15		1	795ACSR/AW
227	TL5086 HIGHWAY 9	NUECES BAY	69	138	1	1.33		1	795.0 AAC
228	TL5087A ARCADIA	HIGHWAY 9	138	138	1	5.09	0.9	1	1590.0 ACSR
229	TL5087B ARCADIA	WESTSIDE	138	138	1	2.82		1	1590.0 ACSR
230	TL5092C QUALITECH DUMMY TO		138	138	1	0.46		1	795.0 ACSR
231	TL5092D NUECES BAY	UPRIVER	138	138	1	8		1	2x795.0 ACSR
232	TL5097 HIGHWAY 9	NUECES BAY CKT #2	138	138	1		2.04	1	1272.0 ACSR
233	TL5099 ARCADIA	SOUTHSIDE	138	138	1	2.58	0.31	1	795.0 AAC
234									795.0 ACSR
235	TL5100 LGE/GPP	REYNOLDS SHERWIN	138	138	1	0.5		1	795.0 ACSR
236	TL5101 HOLLY	SOUTHSIDE	138	138	1	0.31		1	795.0 ACSR
237					2	1.49
238	TL5105 DUPONT SS	ICP CKT#1	138	138	1	0.63		1	795.0 AAC
239	TL5106 FALFURIAS	NORTH EDINBURG	138	138	1	25.1		1	795.0 ACSR
240	TL5111 B M DAVIS	AIRLINE (WEST)	138	138	1	2.87		1	T2 795
241					1	2.77		2	1590.0 ACSR
242					3	3.05		2	1590.0 ACSR
243					1	1.59		1	1590.0 ACSR
244	TL5112 B M DAVIS	AIRLINE (EAST)	138	138	1	2.82		1	T2 795
245					3	1.92		2	1590.0 ACSR
246					1	4.78		2	1590.0 ACSR
247					1	0.32		1	1590.0 ACSR
248	TL5116 WEST OSO	WESTSIDE	138	138	1	2.42		1	1272.0 ACSR
249	TL5119 CELANESE	KLEBERG	138	138	1	6.09		1	795.0 ACSR
250	TL5120A DUPONT SS	OXY CHEM PP2	138	138	1	1.95		1	795.0 ACSR
251	TL5120B AIR LIQUID TAP	AIR LIQUID	138	138	1	0.01		1	795.0 ACSR
252	TL5123 DUPONT SS	ICP CKT#2	138	138	1	1.45		1	795.0 ACSR
253	TL5124 DUPONT SS	ICP CKT#1	138	138	1	0.91		1	795.0 AAC
254	TL5125 WEIL TRACT	WESTSIDE	138	138	1	5.11		1	1590.0 ACSR
255	TL5126 EQUISTAR	LON HILL	138	138	1	3.54		1	795.0 ACSR
256	TL5127 HIGHWAY 9	NUECES BAY CKT #1	138	138	1	2.39		1	1272.0 ACSR
257	TL5127B GILA	HIGHWAY 9 CKT #1	138	138	1	2.39		1	1272.0 ACSR
258	TL5127B HIGHWAY 9	NUECES BAY CKT #2	138	138	1	0.13		1	1272.0 ACSR
259	TL5127C HIGHWAY 9	MORRIS STREET	138	138	1	3.69		1	1272.0 ACSR
260									795.0 AAAC
261	TL5128 NUECES BAY	CITGO	138	138	1	1.06		1	795.0 AAC
262					3	0.67			795.0 ACSR
263	TL5135 CITGO WEST	LON HILL	138	138	1	0.66		1	795.0 ACSR
264					2	2.19
265	TL5136 DAVIS	NELSON SHARPE	138	138	2	12.24		1	795.0 ACSR
266	TL5141 AIRLINE	HOLLY	138	138	1	1.89	0.09	1	1590.0 ACSR
267					1	0.01		1	1590.0 ACSS
268					1	0.2		2	1949 ACCC
269	TL5142 RODD FIELD	CABANISS	138	138	1			1	1590.0 ACSR/AW
270					2	1.47		1	1590.0 ACSR/AW
271					2	2.8		1	1590 ACSS
272					2	1.8		1	1949 ACCC
273	TL5143A CABANISS	WESTSIDE	138	138	2			1	1590.0 ACSR/AW
274					1			1	1590.0 ACSR/AW
275	TL5143 CABANISS	WESTSIDE	138	138	2	1.19		1	1590 ACSS
276					1	0.46		1	1590 ACCC
277	TL5143B EQUISTAR	WESTSIDE	138	138	1	0.46		1	1590.0 ACSR
278	TL5149 LON C HILL	ORANGE GROVE	138	138	1	2.1		1	795.0 ACSR
279			138	138	2	11.48			1020 ACCC
280			138	138	3	11.27		2	1026 ACCC
281	TL5150 HOMEPORT	INGLESIDE	138	138	1	3.69		1	795.0 AAC
282									795.0 ACSR
283	TL5155 DUPONT SS	GPP CKT#2	138	138	1	0.04	1.29	1	2x795.0 ACSR
284	TL5156 DUPONT SS	GPP CKT#1	138	138	1	1.29		1	2x795.0 ACSR
285	TL5160 WHITEPOINT	DUPONT SW	138	138	1	1.34		2	795ACSS
286					1	0.81		2	795 ACSR/AW
287	TL5165 RINCON	WHITEPOINT CKT #2	138	138	1	3.14		1	795.0 ACSR
288					2	4.56
289	TL5166 DUPONT SS	WHITEPOINT CKT#3	138	138	1	5.2		1	2x795.0 ACSR
290	TL5178 JARDIN SUBSTATION	JARDIN SUBSTATION	138	138	1	0.03		1	795.0 ACSR
291	TL5179 LA PALMA	PALO ALTO (PUB)	138	138
292	TL5187 HECKER	EXTENSION #1	138	138	2	0.52		2	795.0 ACSR
293	TL5188 BUNSEN	EXTENSION	138	138	2	0.73		2	959.6 ACSS
294	TL5194 KEPLER	EF 90	69	138	3	0.04		1	477ACSR/AW
295	TL5195 TORTUGA	M&G 138kV EXTENSION	138	138	1	0.4		1	477 ACSR
296	TL5199 PHARR 138kV LOOP		138	138	1	2.2		2	959.6 ACSS/TW SUW
297	TL5202 HECKER	ALPINE	138	138	1	0.06		2	795.0 ACSR
298	TL5203 HECKER	CHENIERE (CUSTOMER STATION)	138	138	1	0.09		2	1590 ACSR Falcon
299	TL5205 CRYSTAL CITY	LA PRYOR EXTENTION	69	138	2	0.04		1	795ACSR
300	TL5206 MARCONI	SAN ROMAN	138	138	1	0.7		1	959ACSS/TW
301	TL5207 MELON CREEK EXTENSIO		138	138	1	0.82		2	795 ACSS/AW
302	TL5208 LA PRYOR	UVALDE EXTENTION	69	138	1	0.06		1	795ACSR
303		TEXISLE	138	138	1	0.5		1	477.0 ACSR
304	TL5222 HARLINGEN SS	RAYMONDVILLE #2	69	138	1	23.06		1	959.6 ACSS/TW
305	TL5226 JOSLIN POI (IPP)		138	138	1	0.03		1	795ACSR
306	TL5231 BISHOP	STRATTON	69	138	1	4.8		1	795 ACSS/AW
307					2	0.03		1	795 ACSS/AW
308	TL5242 CARANCAHUA	PALACIOS	69	138	2	0.08		1	795 ACSS/AW
309	TL5243 POINT COMFORT	CARANCAHUA	69	138	1	0.06		1	795 ACSS/AW
310	TL5248 COY CITY	THREE RIVERS	69	138	1	6.98		1	795 ACSS
311	TL5249 SEAWALL	PORT ARANSAS	69	138	1	8.02		1	795 ACSS/AW
312					2	0.1		1	795 ACSS/AW
313	TL5251 GOLIAD	FANNIN	69	138	1	5.1		1	795 ACSS/AW
314	TL5253 HEARD TAP	REFUGIO	69	138	1	2.65		1	795 ACSS
315	TL5254 WOODSBORO	HEARD TAP	69	138	1	3.33		1	795 ACSS/AW
316	TL5258 PHARR BUS TIE #1		138	138	1	0.18		1	795 ACSS
317	TL5259 PHARR BUS TIE #2		138	138	1	0.11		1	795 ACSS
318	TL5260 RINCON	GREGORY	69	138	1	3.04		1	795 ACSS/AW
319	TL7001 LAREDO	MILO ROAD	138	138	1	8.81	2.83	1	795.0 ACSR
320	TL7003 CONOCO TAP	CONOCO	138	138	2	4.8		1	4/0 ACSR
321	TL7005A EAGLE PASS	ESCONDIDO CKT#2	138	138	2	1.37		1	336.0 ACSR
322	TL7005B ESCONDIDO	HAMILTON ROAD	138	138	2	10.13		1	336.0 ACSR
323	TL7006 EAGLE PASS HYDRO TAP	EAGLE PASS HYDRO	138	138	2	0.31		1	336.0 ACSR
324	TL7007 ESCONDIDO	HAMILTON ROAD	138	138	2	2.38		1	336.0 ACSR
325	TL7008 HAMILTON ROAD PST	SONORA	138	138	2	66.85		1	477.0 ACSR
326			138	138	1	0.3		1	959.6 ACSS/TW
327	TL7009 ASHERTON	WEST BATESVILLE	138	138	2	36.09		1	336.0 ACSR
328	TL7010 PLEASANTON	CPSB LEON CREEK	138	138	2	15.4		1	1020.0 ACCC/TW
329	TL7011 PLEASANTON	BIGFOOT	138	138	2	29.83		1	336.4 ACSR
330	TL7012A MOORE	MEC DOWNIE	138	138	2	41.27		1	336.4 ACSR
331	TL7012B UVALDE	MEC DOWNIE	138	138	2	9.34		1	336.4 ACSR
332	TL7016 FALFURRIAS	LOBO	138	138	1	26.96		1	2x795.0 ACSS
333									795.0 ACSR
334	TL7017 BRUNI	CRESTONIO	138	138	1	14.8		1	795.0 ACSR
335	TL7018 LAREDO PLANT	DEL MAR	138	138	1	2.67		1	795.0 ACSR/AW
336	TL7019 ZAPATA	RANDADO	138	138	2	22.2		1	4/0 ACSR
337	TL7020A FALCON SWITCHING	FALCON DAM (US) CKT#2	138	138	2	4.5		1	4/0 ACSR
338	TL7020B FALCON SWITCHING	ZAPATA	138	138	1	25.8	3.95	1	795.0 ACSR
339	TL7021C LAREDO POWER PLANT	LAREDO VFT SOUTH	138	138	2	0.24		1	795.0 ACSR
340	TL7025 HEIGHTS	LAREDO CKT #1	138	138	1	4.4		1	795.0 AAAC
341	TL7025B HEIGHTS	LAREDO CKT #2	138	138	1	5.19		1	795.0 AAAC
342	TL7026 FREER	LOBO	69	138	1	1.09		1	2x795.0 ACSS
343					2	48.38			4/0 ACSR
344	TL7030 ENCINAL	COTULLA	138	138	1	29.09		1	795.0 ACSR
345	TL7046 ASHERTON	DILLEY SS	138	138	2	15.98		1	795.0 ACSR
346	TL7047 ASHERTON	DILLEY SS	138	138	2	21.8		1	795.0 ACSR
347	TL7048 COTULLA	DILLEY SS	138	138	1	16.15	1.17	1	795.0 ACSR
348	TL7065 HAMILTON ROAD	PICACHO CKT#1	138	138	2	8.67		1	4/0 ACSR
349	TL7066 PICACHO	AMISTAD HYDRO	138	138	2	6.4		1	4/0 ACSR
350	TL7067 HAMILTON ROAD	PICACHO CKT#2	138	138	1	1.45		1	4/0 ACSR
351					2	1.07
352	TL7068 HAMILTON ROAD	PICACHO CKT#2	138	138	1	1.29		1	4/0 ACSR
353					2	1.53
354	TL7069 HAMILTON ROAD	PICACHO CKT#2	138	138	1	0.44		1	4/0 ACSR
355					2	2.65
356	TL7079 BIGFOOT	MOORE	138	138	2	6.06		1	336.4 ACSR
357	TL7081 EAGLE PASS	CFE PIEDRAS NEGRAS	138	138	1	1.33		1	477.0 ACSR
358	TL7082 ESCONDIDO	HAMILTON ROAD	138	138	2	41.21		1	336.0 ACSR
359	TL7086 UVALDE	WEST BATESVILLE	138	138	2	20.61		1	336.0 ACSR
360	TL7087 WEST BATESVILLE	MEC BATESVILLE	138	138	2	9.36		1	795.0 ACSR
361	TL7088 DILLEY SS	STEC SAN MIGUEL	138	138	1	47.54		1	795.0 ACSR
362					2
363	TL7091 PICACHO	AMISTAD HYDRO	138	138	1	1.91		1	336.0 ACSR
364	TL7092B EAGLE PASS	ESCONDIDO CKT#1	138	138	1	0.32		1	4/0 ACSR
365					2	1.13			795.0 ACSR
366	TL7102 RIO BRAVO	ZAPATA	138	138	1	27.48	3.1	1	795 ACSR
367					1	0.23		1	4/0 ACSR
368	TL7105 WORMSER	RIO BRAVO	138	138	1	0.46		1	795.0 ACSR
369	TL7111 UNIVERSITY	WORMSER	138	138	1	1.74		1	795 ACSR
370					1	2.68		2	795 ACSR
371	TL7114 ENCINAL	WORMSER	138	138	1	40.77		1	795 ACSR
372					1	8.43		2	795 ACSR
373					1	0.27		1	795 ACSR/AW
374	TL7115B UNIVERSITY	WORMSER	138	138	1	9.99		1	795.0 ACSR
375	TL7117 ASHERTON	NORTH LAREDO	138	138	1	6.95		1	366.4 ACSR
376					2	56.69			795.0 ACSR
377	TL7123 SIERRA VISTA	WORMSER	138	138	1	1.11		1	795.0 ACSR
378			138	138	1	1.76		2	795.0 ACSR
379	TL7124 EL GATO	GOOLIE/SOUIX RD	138	138	1	5.3		1	795.0 ACSS
380	TL7125 SOUTH MCALLEN	STEWART ROAD	138	138	1	3.7		1	1590 ACSS
381					1	2.14		2	795.0 ACSS
382	TL7125 SOUTH MCALLEN	STEWART ROAD	138	138	1	5.96		1	795.0 ACSS
383	TL7138 PILONCILLO	PRANCH #1	138	138	1	0.06		1	795 ACSR
384	TL7141 BRACKETVILLE	BUS TIE #1	138	138	1	0.11		1	795 ACSS
385	TL7142 LAREDO STATCOM 138kV		138	138	2	0.1		1	1026 ACCC/TW
386	TL7144 ASHERTON	CARRIZO SPRINGS	69	138	1	8.36		1	959.6ACSS/TW
387	TL5224 BRACKETVILLE	BUS TIE #2	138	138	1	0.13		1	795 ACSS
388	TL5185 KENEDY SWITCHING STA	TULETA	138	138	1	19.33		2	959 ACSR/TW
389	TL5180 KENEDY SWITCHING STA	PETTUS	138	138	1	19.33		2	959 ACSR/TW
390	TL5261 BRACKETTVILLE	ESCONDIDO	138	138
391	TL5209 BONILLA	LADEKIDDE	345	345
392	TL5264 LA PALMA SVC	138KV BUS TIE #1	138	138
393	TL5265 LA PALMA SVC	138KV BUS TIE #2	138	138
394	69 KV (148 LINES)		69	69	1,2&4	966	47.18
395	AEP TEXAS NORTH
396	TL125A ABILENE MULBERRY	BLUFF CREEK SS	345	345	2	26.5	0.42	1	2x795.0 ACSR
397	TL125B BLUFF CREEK SS	SAN ANGELO RED CREEK	345	345	1	0.42		1	2x795.0 ACSR
398					2	49.56
399	TL126 ABILENE MULBERRY	OKLAUNION	345	345	2	115.65		1	2x795.0 ACSR
400	TL131 OKLAUNION	TU FISHER ROAD	345	345	2	30.14		1	2x795.0 ACSR
401	TL324 OKLAUNION DC TIE	DC TERMINAL NORTH (SPP)	345	345	1	0.02		1	1926.9KCM ACSR
402	TL325 OKLAUNION DC TIE	DC TERMINAL SOUTH (ERC)	345	345	1	0.02		1	1926.9KCM ACSR
403	TL001 ABILENE SOUTH	PUTNAM	138	138	1	3.13		1	4/0 ACSR
404					2	32.16			477.0 ACSR
405	TL013 PUTNAM-MORAN	THROCKMORTON - MUNDAY	69	138	1	13.3		1	795 ACSS/AW
406	TL028 ABILENE NORTHWEST	ANSON (TAP FORT PHANTOM PUM	69	138	1	1.63		1	795 ACSS/AW
407	TL031 SANTA ANNA	BROWNWOOD	138	138	1	7.29		1	795.0 ACSR
408	TL033 EDEN	YELLOWJACKET	69	138	1	0.11		1	795 ACSS
409	TL034 MASON SWITCHING	YELLOWJACKET	69	138	1	0.23	0.8	1	795 ACSS
410	TL048 MCCAMEY - MCELROY	CRANE GULF 1&2	69	138	1	0.32		1	795 ACSS
411	TL050 FORT STOCKTON PLANT	RIO PECOS	138	138	2	37.48		1	477.0 ACSR
412	TL051 EAST MUNDAY	PADUCAH CLARE STREET	138	138	1	3.2		1	477.0 ACSR
413					2	59.08
414	TL064A EAST MUNDAY	LAKE PAULINE	138	138	2	56.97		1	2x4/0 ACSR
415	TL064B EAST MUNDAY	PAINT CREEK WEST#1	138	138	2	25.96		1	397.0 ACSR
416	TL066A FORT PHANTOM	PAINT CREEK	138	138	2	38.73		1	1272.0 AAC
417					3	0.48			477.0 ACSR
418	TL066B CALIFORNIA CREEK TAP	CALIFORNIA CREEK	138	138	2	0.02		1	4/0 ACSR
419	TL070 ABILENE NORTHWEST	OAK CREEK	138	138	2	47.01		1	397.0 ACSR
420					2	5.21		1	795.0 ACSR
421	TL072 ABILENE NORTHWEST	PAINT CREEK	138	138	2	44.22		1	477.0 ACSR
422	TL077 BALLINGER	OAK CREEK	138	138	2	30.85		1	397.0 ACSR
423									477.0 ACSR
424	TL079A NICOLE	SAN ANGELO RED CREEK	138	138	1	3.21		2	2x795.0 ACSS
425					2	33.77			397.0 ACSR
426									477.0 ACSR
427	TL079B NORTH SAN ANGELO	SAN ANGELO RED CREEK	138	138	1	0.64		1	795.0 ACSR
428					2	8.96
429	TL079C SAN ANGELO CONCHO	SAN ANGELO RED CREEK	138	138	1	2.07		1	795.0 ACSR
430					2	7.66
431	TL080 ALPINE	FORT STOCKTON	69	138	1	0.15		1	477ACSR
432	TL082A BLUFF CREEK SS	NICOLE	138	138	1			1	2x795.0 ACSS
433	TL082B ABILENE SOUTH	BLUFF CREEK SS	138	138	1	0.43	1.68	1	1020.0 ACCC/TW
434					2	17.24			2x795.0 ACSS
435	TL082C NICOLE	OAK CREEK	138	138	1	2.42		1	2x795.0 ACSS
436
437	TL083A ABILENE SOUTH	EAST ABILENE	138	138	1	3.82		1	795.0 ACSR
438					2	5.63
439	TL083B ABILENE ELM CREEK	ABILENE NORTHWEST CKT#2	138	138	1	0.53		1	795.0 ACSR
440					2	2.54
441	TL083C ABILENE NORTHWEST	FORT PHANTOM	138	138	2	10.96	0.5	1	1272.0 AAC
442									2x795.0 ACSR
443	TL083D ABILENE SOUTH	FORT PHANTOM	138	138	1	2.07		1	1272.0 AAC
444					2	15.61			1272.0 ACSS
445					3	0.49			2x477.0 ACSR
446									795.0 ACSR
447	TL083E EAST ABILENE	FORT PHANTOM	138	138	2	9.54	0.39	1	1272.0 AAC
448									795.0 ACSR
449	TL083F ABILENE ELM CREEK	ABILENE SOUTH CKT#2	138	138	1	3.69		1	795.0 ACSR
450					2	6.61
451	TL083G EAST ABILENE TAP	EAST ABILENE	138	138	2	2.04		1	2x477.0 ACSR
452									795.0 ACSR
453	TL083G TEC SHARP TAP	TEC SHARP	138	138	2	2.04		1	2x477.0 ACSR
454									795.0 ACSR
455	TL084A SAN ANGELO CONCHO	SAN ANGELO POWER STATION	138	138	2	5.93		1	477.0 ACSR
456					3	0.16
457					1	0.12			1590 ACSR
458	TL084B SOUTH ANGELO TAP	SOUTH ANGELO	138	138	3	1		1	4/0 ACSR
459	TL085 SAN ANGELO	BIG LAKE	138	138	1		9.67	1	477.0 ACSR
460					2	54.9			795.0 ACSR
461	TL086 BIG LAKE	NORTH MCCAMEY	138	138	2	36.34		1	477.0 ACSR
462					2	10.3		1	956.6 ACSS
463					1	0.15		1	795 ACSS
464	TL087 LAKE PAULINE	VERNON CKT #2	138	138	2	24.36		1	477.0 ACSR
465	TL088A SAN ANGELO POWER	SAN ANGELO RED CREEK	138	138	1	1.29		1	477.0 ACSR
466					2	17.33
467	TL088B BALLINGER	SAN ANGELO RED CREEK	138	138	1	3.07		1	477.0 ACSR
468					2	29.48
469	TL089 HAMILTON ROAD PST	SONORA	138	138	2	21.84		1	477.0 ACSR
470	LOAD
471	TL089A ELDORADO LIVE OAK	SAN ANGELO POWER STATION	138	138	2	38.23		1	477.0 ACSR
472	TL089B ELDORADO LIVE OAK	SONORA CKT#2	138	138	2	22.07		1	477.0 ACSR
473	TL090 ASPERMONT	PAINT CREEK	138	138	2	39.74		1	477.0 ACSR
474	TL092A LCRA CRANE	RIO PECOS CKT #1	138	138	1	0.82		1	636.0 ACSR
475					2	22.83			795.0 ACSR
476	TL092B TEXAS NEW MEXICO TAP	CRANE TAP #2	69	138	1	0.1		1	4/0 ACSR
477	TL093 SAN ANGELO POWER	YELLOWJACKET	138	138	1	0.85		1	477.0 ACSR
478					2	54.31			795 ACSS
479	TL094 PUTNAM	LEON CKT #2	138	138	2	21.93		1	4/0 ACSR
480									477.0 ACSR
481	TL095 SAN ANGELO COLLEGE	SAN ANGELO POWER STATION	138	138	2	2.75		1	795.0 ACSR
482	HILLS
483	TL097 EAST MUNDAY	PAINT CREEK EAST#2	138	138	2	26.67		1	477.0 ACSR
484	TL100 BARRILLA JUNCTION	FORT STOCKTON PLANT	138	138	1	25.39		1	477.0 ACSR
485	TL111 ASPERMONT	SPUR	138	138	1	10.19		1	477.0 ACSR
486					2	35.36
487	TL113 ALAMITO CREEK	BARRILLA JUNCTION	138	138	1	0.32		1	477.0 ACSR
488					2	66.99
489	TL117 NORTH SAN ANGELO	SAN ANGELO COLLEGE HILLS	138	138	1	2.1		1	795.0 ACSR
490					2	6.48
491	TL120A CEDAR HILL	OAK CREEK	138	138	2	26.26		1	4/0 ACSR
492			138	138	1	0.09		1	959.6 ACSS
493	TL120B FORT CHADBOURNE TAP	FORT CHADBOURNE	138	138	2	0.02		1	4/0 ACSR
494	TL122 ABILENE MULBERRY	ABILENE NORTHWEST	138	138	2	2.59		1	1272.0 AAC
495									1272.0 ACSR
496	TL123 MENARD	FORT MASON (LCRA)	138	138	1	1.05		1	477.0 ACSR
497					2	37.27			795 ACSS
498	TL124 FORT MASON (LCRA)	GILLESPIE COUNTY LINE	138	138	2	22.87		1	477.0 ACSR
499					1	0.05		1	795 ACSS
500	TL127A BALLINGER	SANTA ANNA CKT #1	138	138	1	0.56		1	477.0 ACSR
501					2	37.82
502	TL127B EAST COLEMAN TAP	EAST COLEMAN	138	138	2	2.98		1	477.0 ACSR
503	TL128 OKLAUNION	VERNON	138	138	1	2.59		1	795.0 ACSR
504					2	6.72
505	TL129 ABILENE ELM CREEK	ABILENE MULBERRY CREEK	138	138	1	0.52		1	1272.0 AAC
506					2	5.19
507	TL133 OKLAUNION	SOUTHWEST VERNON	138	138	2	6.98		1	795.0 ACSR
508					1	0.48		1	795.0 ACSR
509	TL136 SPUR	SUN	138	138	1	0.31		1	795.0 ACSR
510					2	17.48
511	TL138 PADUCAH CLARE STREET	WEST CHILDRESS	138	138	1	1.87		1	477.0 ACSR
512					2	29.55
513	TL140 SOLSTICE	YUCCA DRIVE (ONCOR)	138	138	2	37.27		1	477.0 ACSR
514					1	0.49		1	477 ACSR
515					1	0.57		1	2-795 ACSR
516	TL141 FRIEND RANCH	SONORA	138	138	1	32.85		1	477.0 ACSR
517	TL204 STERLING-SUN JAMESON	ROBERT LEE - STERLING	69	138	1	0.08		1	959.6ACSS/TW
518	TL242 BIG LAKE	FRIEND RANCH	138	138	1	39.63		1	477.0 ACSR
519			138	138	1	0.4		2	959 ACSR/TW
520	TL243 LCRA NORTH MCCAMEY	NORTH MCCAMEY	138	138	1	0.19		1	795.0 ACSR
521	TL310 BLUFF CREEK	BUFFALO GAP	138	138	1	2.04		1	2x795.0 ACSS
522	TL319 GONZALES	ACACIA	69	138	1	2.4		1	795.0 ACSR
523	TL321 ESMERALDA	YUCCA	138	138	3	14.8		1	4/0ACSR
524	TL322 SAN ANGELO	RUSTHILL #1	69	138	1	0.02		1	1590 ACSR
525	TL323 SAN ANGELO CONCHO	RUSTHILL #2	138	138	1	0.17		1	1590 ACSR
526	TL327 SANTA RITA	EXTENSION	69	138	1	0.17		1	2/0 ACSR
527	TL353 DINNY	WEST YATES	69	138	1	3.19		1	959 ACSS/TW
528	TL329 BARRILLA JUNCTION	SOLSTICE	138	138	1	0.2		1	2x956.6 ACSS
529	TL331 N BRADY	BRADY CITY	69	138	1	0.9		2	795
530	TL333 ABILENE NORTHWEST	ELY	69	138	1	8.25		1	477ACSR
531	TL334 ALAMITO CREEK	MARFA	69	138	1	0.58		1	959 ACSS/TW
532	TL335 MUNDAY	POINTER	69	138	1	5.75		1	959 ACSR/TW
533	TL337 CASSAVA	YUCCA	138	138	1	11.9		1	397ACSR/T2
534	TL338 SOLSTICE	HOVEY	138	138	1	0.14		1	477 ACSR
535			138	138	1	0.1		1	477 ACSR
536	TL339 HENDRICK 138KV	HAIRPIN	138	138	1	0.68		2	795ACSS
537	TL340 ALBANY FOUNDRY	HULLTOWN	69	138	1	9.5		1	795 ACSS/AW
538	TL342 LOTEBUSH	ENSTOR HACBERRY DRAW	138	138	1	0.04		1	477 ACSR
539	TL343 BISON	POWELL FIELD 138KV TAP	69	138	1	6.8		1	4/0ACSR
540	TL345 ALBANY	FORT GRIFFIN	69	138	1	0.86		1	795 ACSS/AW
541	TL346 BIG LAKE	SAN ANGELO MATHIS FIELD	69	138	1	16.5		1	795 ACSS
542	TL348 CROWELL	MUNDAY	69	138	1	3.8		1	4/0 ACSR
543					1	12.2		1	2x477 ACSR
544	TL349 JAYTAN	ROTAN	69	138	1	21.25		1	795 ACSS/TW
545	TL350 ALPINE	BARRILLA JUNCTION	69	138	1	49.34		1	795 ACSS
546	TL351 ABILENE SOUTH	SAWGRASS	69	138	1	1.95		1	795 ACSS
547	TL352 CACTUS	FORT LANCASTER	69	138	1	9.2		1	956.6 ACSS
548	TL354 QUAINT 138kV EXTENSIO		69	138	1	0.27		2	795 ACSS/AW
549	TL356 BRONCO 138KV	EXTENSION	69	138	1	0.29		1	795 ACSS
550	TL358 FORT GRIFFIN	RAINEY CREEK	69	138	1	0.37		1	795 ACSS/AW
551	TL359 ALBANY FOUNDRY	FORT GRIFFIN	69	138	1	0.14		1	795 ACSS
552	TL363 ABILENE NORTHWEST	ANSON	69	138	1	1.38		1	795 ACSS
553					1	1.74		1	795 ACSS/AW
554	TL365 ABILENE NORTHWEST	ELM CREEK	69	138	1	3.1		1	795 ACSS
555	TL366 HENDRICK POI (OCI)		138	138	1	0.03		1	477ACSR
556	TL373 DERRICK	OWLS	69	138	1	4.24		1	795 ACSS
557	TL387 PECOS VALLEY	RIO PECOS	69	138	1	16.49		1	795 ACSS
558	TL400 CEDAR HILL	ROBERT LEE	69	138	1	12.6		1	795 ACSS
559	TL402 BRONCO	LASSO	69	138	1	0.1		1	795 ACSS
560	TL412 LOTEBUSH	BROZOS MIDSTREAM	138	138	1	0.04		1	959.6 ACSS/TW
561	TL413 LOTEBUSH	ARROWHEAD	138	138	1	0.04		1	1926.9 ACSR/TW
562	TL414 LOTEBUSH	NW COYANOSA	138	138	1	0.06		2	959.6 ACSS/TW
563	TL420 MERTZON	MATHIS FIELD	69	138	1	23.6		1	795 ACSS
564	TL407 SOLSTICE	BAKERSFIELD	345	345
565	69kV (173 LINES)		69	69	1,2,3	2,139.59	45.12		VARIOUS
566	Line costs and expense are	not available by individual
567	transmission line.	Totals shown in col j-p								88,263,851	1,659,412,634	1,747,676,485	339,705	11,550,021		11,889,726
36						8,145.58	180.18	501		88,263,851	1,659,412,634	1,747,676,485	339,705	11,550,021		11,889,726

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: TransmissionLineStartPoint

Jointly Owned Transmission Line:

AEP Texas owns 20.82% of transmission lines in the STP Corridor.

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

TRANSMISSION LINES ADDED DURING YEAR
Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m). If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic.
	LINE DESIGNATION			SUPPORTING STRUCTURE		CIRCUITS PER STRUCTURE		CONDUCTORS				LINE COST
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	LengthOfTransmissionLineAdded Line Length in Miles	SupportingStructureOfTransmissionLineType Type	AverageNumberOfSupportingStructuresOfTransmissionLinePerMiles Average Number per Miles	NumberOfTransmissionCircuitsPerStructurePresent Present	NumberOfTransmissionCircuitsPerStructureUltimate Ultimate	ConductorSize Size	ConductorSpecification Specification	ConductorConfigurationAndSpacing Configuration and Spacing	OperatingVoltageOfTransmissionLine Voltage KV (Operating)	CostOfLandAndLandRightsTransmissionLinesAdded Land and Land Rights	CostOfPolesTowersAndFixturesTransmissionLinesAdded Poles, Towers and Fixtures	CostOfConductorsAndDevicesTransmissionLinesAdded Conductors and Devices	AssetRetirementCostsTransmissionLines Asset Retire. Costs	CostOfTransmissionLinesAdded Total
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)
1	AEP TEXAS CENTRAL	COMPANY
2	TL5258 PHARR BUS TIE #1		0.18	1		1	1	795	ACSS		138		671,850	102,833		774,683
3	TL5259 PHARR BUS TIE #2		0.11	1		1	1	795	ACSS		138		511,358	120,484		631,842
4	AEP TEXAS NORTH	COMPANY
5	TL342 LOTEBUSH	ENSTOR HACBERRY DRAW	0.04	1		1	1	477	ACSR		138	13,947	625,890	42,065		681,902
6	TL412 LOTEBUSH	BROZOS MIDSTREAM	0.04	1		1	1	959.6	ACSS/TW		138		212,700	17,204		229,904
7	TL413 LOTEBUSH	ARROWHEAD	0.04	1		1	1	1926.9	ACSR/TW		138		288,140	24,332		312,472
8	TL414 LOTEBUSH	NW COYANOSA	0.06	1		2	2	959.6	ACSS/TW		138		453,426	35,949		489,375
44	TOTAL		0.47			7	7					13,947	2,763,364	342,867		3,120,178

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

SUBSTATIONS
Report below the information called for concerning substations of the respondent as of the end of the year. Substations which serve only one industrial or street railway customer should not be listed below. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
			VOLTAGE (In MVa)
Line No.	SubstationNameAndLocation Name and Location of Substation (a)	SubstationCharacterDescription Character of Substation (b)	PrimaryVoltageLevel Primary Voltage (In MVa) (c)	SecondaryVoltageLevel Secondary Voltage (In MVa) (d)	TertiaryVoltageLevel Tertiary Voltage (In MVa) (e)	SubstationInServiceCapacity Capacity of Substation (In Service) (In MVa) (f)	NumberOfTransformersInService Number of Transformers In Service (g)	Number of Spare Transformers (h)	ConversionApparatusAndSpecialEquipmentType Conversion Apparatus and Special Equipment, Type of Equipment (i)	NumberOfConversionApparatusAndSpecialEquipmentUnits Conversion Apparatus and Special Equipment, Number of Units (j)	CapacityOfConversionApparatusAndSpecialEquipment Conversion Apparatus and Special Equipment, Total Capacity (In MVa) (k)
1	WESLACO UNIT - TX	D	138	12.47		90	2
2	WESLACO UNIT - TX	D	138						STATCAP	1	29
3	WESMER - TX	D	138	12.47		56	2
4	WESMER - TX	D	12						STATCAP	2	10
5	WEST HARLINGEN - TX	D	69	12.47		56	2
6	WEST HARLINGEN - TX	D	12						STATCAP	3	11
7	WEST MCALLEN - TX	D	138	12.47		90	2
8	WEST MCALLEN - TX	D	12						STATCAP	4	19
9	WEST OSO - TX	D	138	12.47		28	1
10	WESTSIDE SW - TX	T	138						STATCAP	2	58
11	WHITE POINT - TX	T	138	69	12	93	1
12	WHITE POINT - TX	T	345	138	13.8	480	1
13	WHITE POINT - TX	T	138						AIR CORE REACTOR	6	86
14	WOODSBORO - TX	D	69	12.47		8	1
15	WOODSBORO - TX	D	12						STATCAP	1	2
16	WOOLDRIDGE - TX	D	138	12.47		28	1
17	WORMSER ROAD SW - TX	T	138						STATCAP	2	14
18	YORKTOWN - TX	D	138	13.09		25	2
19	ZACATE CREEK - TX	D	138	12.47		40	1
20	ZAPATA - TX	D	138	12.47		25	1
21	ZAPATA - TX	D	138	13.09		25	2
22	ABILENE AILEEN - TX	D	138	13.09	0.5	28	1
23	ABILENE COUNTRY CLUB - TX	D	138	13.09		20	1
24	ABILENE EAST - TX	T	138	13.09		28	1
25	ABILENE EAST - TX	T	138	69	7.67	75	1
26	ABILENE EAST - TX	T	138	69.3	13.2	63	1
27	ABILENE INDUSTRIAL PARK - TX	D	138	13.09		56	2
28	ABILENE NORTHWEST - TX	T	138	69	11.2	92	1
29	ABILENE NORTHWEST - TX	T	138	69.5	36.2	90	1
30	ABILENE OIL MILL - TX	D	69	13		25	1
31	ABILENE ONYX REA - TX	D	69	13		12	3
32	ABILENE POWER PLANT - TX	T	69	7.56		13	2
33	ABILENE POWER PLANT - TX	T	69	7.56	2.4	7	1
34	ABILENE POWER PLANT - TX	T	69	13.09			1
35	ABILENE SOUTH - TX	T	138	70.5	13.09	180	2
36	ABILENE SOUTH - TX	T	138						STATCAP	3	86
37	ACME BESTWALL - TX	D	69	13		5	1
38	AFTON (WT) - TX	D	69	7.2		3	3
39	ALBANY (WT) - TX	D	69	13		10	1
40	ALBANY FOUNDRY - TX	D	69	13		25	1
41	ALBANY HUBBARD BOOSTER #1 WCT - TX	D	2.4				3
42	ALBANY HUBBARD BOOSTER #1 WCT - TX	D	69	2.52		4	3
43	ALBANY HUBBARD BOOSTER #2 WCT - TX	D	2.4	0.48			3
44	ALBANY HUBBARD BOOSTER #2 WCT - TX	D	69	2.52		4	3
45	ALPINE - TX	D	69	13		40	4
46	ANSON - TX	D	69	13.09		9	1
47	ANSON REA - TX	D	69	13		5	1
48	ARROTT - TX	D	69	12.5		2	3
49	ASPERMONT - TX	T	138	69	14.4	63	1
50	ASPERMONT - TX	T	69	13		9	1
51	ASPERMONT CONTINENTAL OIL CO. - TX	D	69	13		4	1
52	ATKINSON RANCH - TX	D	69	2.4			2
53	BAIRD CITY - TX	D	69	13		5	1
54	BALLINGER - TX	T	138	13.09		25	1
55	BALLINGER - TX	T	138	66	13.8	63	1
56	BALLINGER HUMBLE - TX	D	69	2.4		1	3
57	BARNHART - TX	D	69	13.09		9	1
58	BARNHART - TX	D	69						STATCAP	1	4
59	BARRILLA JUNCTION - TX	T	138	69	6.57	63	1
60	BARRILLA JUNCTION - TX	T	69	12.4			1
61	BENJAMIN - TX	D	69	12.4		2	2
62	BENJAMIN - TX	D	69	13		1	1
63	BIG LAKE - TX	T	12	4.1		2	3
64	BIG LAKE - TX	T	69	13		10	3
65	BIG LAKE - TX	T	138	69	2.4	50	1
66	BIG LAKE - TX	T	138	69	5.39	50	1
67	BIG LAKE - PHILLIPS PUMP - TX	D	69	12.5		2	3
68	BLUFFS - TX	D	138	12.47		25	1
69	BOBCAT HILLS - TX	D	69	12.47		5	1
70	BOND ROAD - TX	D	7.62	13.09		9	1
71	BRADSHAW - TX	D	69	12.4		1	3
72	BRADY CITY (MUNICIPAL INTERCON - TX	D	69	13	7.62	11	1
73	BRADY CITY (MUNICIPAL INTERCON - TX	D							STATCAP	1	6
74	BRONTE - TX	D	69	12.47		6	1
75	BRONTE - TX	D							STATCAP	2
76	BRONTE (AMBASSADOR) - TX	D	69	13		2	3
77	BRONTE ATLANTIC - TX	T	69	12.5		2	1
78	BRYANT RANCH - TX	D	69	12.47		1	3
79	BUSH KNOB (THROCKMORTON) - TX	D	69	7.56		8	3
80	CANYON ROCK - TX	D	138	13.09		15	1
81	CASSAVA - TX	T	138	70.5	13.09	90	1
82	CEDAR GAP - TX	D	69	13		6	1
83	CEDAR HILL - TX	T	138	70.5	13.09	90	1
84	CEDAR HILL - TX	T	69						STATCAP	1	12
85	CHERRY CREEK (WT) - TX	D	69	13		5	1
86	CHILDRESS - TX	T	69	12.47		12	1
87	CHILDRESS 20TH ST SUB CHILDRES - TX	D	69	13		16	1
88	CHILDRESS WEST - TX	T	138	69	2.4	50	1
89	CHILLICOTHE - TX	D	69	13.09		11	3
90	CHINATI - TX	T	138						STATCAP	1
91	CHRISTOVAL - TX	D	69	13		6	1
92	CISCO - TX	D	138	13.09		24	2
93	CLAIRMONT SUN OIL CO. - TX	D	69	7.2		2	3
94	CLYDE - TX	D	69	13		25	1
95	CLYDE - TX	D	69						STATCAP	1	12
96	CLYDE MAGNOLIA PUMP PIPELINE - TX	D	69	2.5		6	1
97	COLEMAN EAST - TX	D	138	13.09		25	1
98	CORINTH - TX	D	69	7.2		1	3
99	CRANE (TESCO INTER) - TX	T	138	70.5	13.09	130	1
100	CRANE (TESCO INTER) - TX	T	138						STATCAP	1	57
101	CRANE COUNTY AIRPORT - TX	D	69	4.1		11	1
102	CROCKETT HEIGHTS (OZONA) - TX	D	69	12		2	3
103	CROSS PLAINS - TX	D	69	13.09		8	1
104	CROWELL - TX	T	69	13		6	1
105	DISCOVERY CANYON - TX	D	69	12.5		5	3
106	DUNE FIELD - TX	D	69	13		10	3
107	DYESS AFB #1 - TX	D	69	7.56	2.4	6	2
108	DYESS AFB #1 - TX	D	69	13	2.4	3	1
109	DYESS AFB #2 - TX	D	69	13		16	1
110	DYESS AFB #3 - TX	D	69	7.56	2.4	19	3
111	EDEN - TX	T	69	13		5	3
112	EDITH HUMBLE - TX	D	69	13.09		3	1
113	ELDORADO - TX	D	69	13		8	3
114	ELDORADO CITIES SERVICE CO. - TX	D	69	12		1	2
115	ELDORADO CITIES SERVICE CO. - TX	D	69	12.5		1	1
116	ELDORADO LIVE OAK SUB. - TX	T	138	69	6.6	63	1
117	ELDORADO LIVE OAK SUB. - TX	T	138	69	7	50	1
118	ELDORADO LIVE OAK SUB. - TX	T							STATCAP	1	12
119	ELDORADO SHELL BAILEY - TX	D	69	4.36		8	1
120	ELM CREEK - TX	T	138	69	8.55	92	1
121	ELM CREEK - TX	T	138	13.09		48	2
122	ELMDALE - TX	D	69	13		9	1
123	EOLA - TX	D	69	13		4	3
124	ESPY WELLS - TX	D	69	7.2			1
125	FLOMOT - TX	D	69	13		2	3
126	FORT DAVIS - TX	D	69	12.4		8	3
127	FORT DAVIS - TX	D	69						STATCAP	1	4
128	FORT LANCASTER - TX	T	138	69	12.47	50	1
129	FORT MCKAVITT - TX	D	69	2.4		2	3
130	FORT STOCKTON PLANT - TX	T	138	69	8.88	63	1
131	FORT STOCKTON SW STATION - TX	T	69	7.2			1
132	FREDERICKSBURG PHILLIPS - TX	D	69	2.4		1	3
133	FRIEND RANCH - TX	T	138	69	13.2	63	1
134	FRIEND RANCH - TX	T	2.4						DRCS	1	10
135	FRIESS RANCH - TX	D	69	12.5		2	3
136	FT CHADBOURNE - TX	D	138	13.09		11	1
137	FT PHANTOM CLEAR FORK PUM - TX	D	69	2.4		13	3
138	FT PHANTOM EAST PUMP STA - TX	D	69	4.3		2	3
139	FT PHANTOM PLANT - TX	T	138						STATCAP	1	29
140	GILLESPIE (KNOX CITY REA - TX	D	69	12.47		3	3
141	GIRARD - TX	D	69	2.4		1	3
142	GRAYBACK - TX	D	69	13.09		5	3
143	GRIMES FILTRATION PLAN - TX	D	12	4.1		5	3
144	HAMLIN - TX	D	69	13		8	3
145	HAMLIN PLASTERCO CELOTEX THR - TX	D	69	13		2	3
146	HAMLIN REA - TX	D	69	12.4		2	2
147	HAMLIN REA - TX	D	69	12.47		1	1
148	HAMLIN SHELL PUMP - TX	D	12	2.4		1	3
149	HAMLIN SHELL PUMP - TX	D	69	7.2		1	3
150	HAMLIN TEXAS PIPE LINE - TX	D	69	12.4		11	3
151	HAMLIN TEXAS PIPE LINE - TX	D	69	13.09		1	1
152	HARROLD OIL FIELD - TX	D	69	13		4	1
153	HARTFORD STREET - TX	D	69	13		28	1
154	HASKELL - TX	D	69	7.56		10	3
155	HASKELL TEXAS PIPE LINE - TX	D	69	4.1		7	1
156	HATCHELL REA - TX	D	69	12.47		1	1
157	HATCHELL REA - TX	D	69	13		2	2
158	HAWLEY HUMBLE - EXXON - TX	D	12	2.4		1	3
159	HAWLEY HUMBLE - EXXON - TX	D	69	13.2		6	1
160	HORNET 69KV - TX	D	69	13.09		8	1
161	HUMBLE KEMPER EXXON - TX	D	69	2.4		5	6
162	INDIAN MESA - TX	D	138	13.09		5	3
163	IRAAN - TX	D	12	2.4		1	3
164	IRAAN - TX	D	69	13		10	3
165	IRAAN - TX	D	69						STATCAP	1	9
166	IRAAN AIR PRODUCTS - TX	D	69	2.4		15	3
167	IRAAN AIR PRODUCTS - TX	D							STATCAP	1	6
168	JAYTON - TX	T	69	4.1		2	3
169	JUNCTION - TX	D	69	13		3	1
170	JUNCTION - TX	D	69	13.09		5	2
171	KENNEDY PONDER TAP - TX	D	69	12.5			1
172	KIRKLAND - TX	D	69	2.4		1	3
173	KNOX CITY - TX	D	69	13		7	2
174	KNOX CITY - TX	D	69	13.09		3	1
175	LONGWORTH - TX	D	69	12.47		6	1
176	MAPLE STREET - TX	D	138	13.09	13.2	25	1
177	MARATHON YATES - TX	D	69	4		5	1
178	MARFA - TX	T	69	7.2		2	1
179	MARFA - TX	T	69	13		3	2
180	MARFA ALAMITO CREEK - TX	T	138	69	5.01	47	1
181	MARFA ALAMITO CREEK - TX	T	138	69	13.8	47	1
182	MARFA ALAMITO CREEK - TX	T	69						STATCAP	1	7
183	MASON PHILLIPS - TX	D	69	2.4		2	3
184	MASTERSON FIELD - TX	D	69	13		6	1
185	MATADOR - TX	T	69	13		5	3
186	MCCAMEY - TX	T	12	4.1		2	3
187	MCCAMEY - TX	T	138	12.47		9	1
188	MCCAMEY SHELL - TX	D	69	4.1		8	1
189	MCCAMEY SHELL PUMP - TX	D	12	2.4		1	1
190	MCCAMEY SHELL PUMP - TX	D	12	2.4		1	1
191	MCCAMEY SHELL PUMP - TX	D	12	4.16		1	3
192	MCELROY - TX	D	69	7.5		10	2
193	MCELROY - TX	D	69	7.56		5	1
194	MCELROY - TX	D	69	13.09		20	1
195	MCELROY - TX	D	12						STATCAP	1	2
196	MCELROY - TX	D	69						STATCAP	1	7
197	MCMURRY - TX	D	69	13		45	2
198	MELVIN - TX	D	69	13.09		9	1
199	MENARD PHILLIPS PETROLEUM CO. - TX	D	69	2.4		4	1
200	MERKEL - TX	D	69	13		9	1
201	MERKEL - TX	D							STATCAP	1	12
202	MERTZON - TX	D	69	13		5	1
203	MESA VIEW - TX	D	138	13.09		50	1
204	MIDWAY LANE - TX	D	69	12.5		10	3
205	MILES (WT) - TX	T	69	13		2	3
206	MORAN - TX	D	69	13.1		3	3
207	MULBERRY CREEK - TX	T	345	138	13.2	530	2
208	MULBERRY CREEK - TX	T	12						REACTIVE SPECIAL	1
209	MUNDAY - TX	D	69	13.09		9	1
210	MUNDAY EAST - TX	T	138	69	13.09	54	1
211	MUNDAY EAST - TX	T	138						STATCAP	1	29
212	NORTH BRADY - TX	T	69			10	2
213	NORTH BRADY - TX	T	69	2.2		10	2
214	NORTH MCCAMEY - TX	T	138	13.09		28	1
215	OKLAUNION HVDC INTER - TX	T	345	26.4	26.4	540	2
216	OKLAUNION HVDC INTER - TX	T	345	26.4	26.4	270		1
217	OKLAUNION HVDC INTER - TX	T	345						REACTIVE SPECIAL	8
218	OVER STREET - TX	D	69	13.09	4.16	25	1
219	OWLS - TX	D	138	69	13.09	90	1
220	OZONA - TX	D	69	13		13	1
221	PADUCAH - TX	D	69	12.5		4	3
222	PAINT CREEK PLANT - TX	T	138	70.5	36.2	90	1
223	PAINT ROCK - TX	D	69	4.1		334	3
224	PAISANO - TX	D	69	12.5		1	1
225	PAN AMERICAN - TX	D	69	2.4			1
226	PANDALE 69KV SUB - TX	D	69	13.09		12	1
227	PEACOCK (WT) - TX	D	69	2.4		1	3
228	PECAN BAYOU - TX	D	138	12.47		28	1
229	PECOS VALLEY - TX	D	69	12.5		1	3
230	PERKINS-PROTHO - TX	D	69	12.5		1	3
231	POWELL FIELD - TX	D	69	13.09		15	1
232	POWELL FIELD - TX	D	69						STATCAP	2	9
233	POWELL SHELL - TX	D	69	4		5	3
234	PUNCHER 69KV - TX	D	69	13.09		8	1
235	PUNCHER 69KV - TX	D	69						STATCAP	1	7
236	PUTNAM - TX	T	138	70.5	12.47	90	1
237	PUTNAM - TX	T	138	138		150	1
238	PUTNAM - TX	T	138						STATCAP	1	29
239	PUTNAM 69KV - TX	D	69	12.5		4	1
240	QUANAH - TX	D	69	12		15	3
241	QUANAH ACME MILLS - TX	D	12	2.4		2	3
242	RADIUM - TX	T	138	69	7.83	63	1
243	RAINEY CREEK - TX	D	138	13.09	13.8	28	1
244	RANKIN - TX	D	69	13.09		10	1
245	REBECCA LANE - TX	D	138	13.09	5.67	25	1
246	RIO PECOS PLANT (GIRVIN) - TX	T	138	69	13.8	63	1
247	RIO PECOS PLANT (GIRVIN) - TX	T	138	69.3	13.2	50	1
248	RIO PECOS PLANT (GIRVIN) - TX	T	69	12		4	1
249	RIO PECOS PLANT (GIRVIN) - TX	T	138						STATCAP	1	29
250	RIO PECOS PLANT (GIRVIN) - TX	T	138						AIR CORE REACTOR	7	140
251	RISING STAR - TX	D	69	13		4	1
252	ROARING SPRINGS - TX	D	69	12.47		6	1
253	ROBERT LEE - TX	D	69	13		11	1
254	ROBERTSON PRISON - TX	D	69	7.5		9	3
255	ROBY - TX	T	69	13		6	1
256	ROCHESTER - TX	D	69	12.47		5	1
257	ROTAN - TX	D	69	7.56		9	2
258	ROTAN - TX	D	69	13		3	1
259	ROTAN GYP MILL EAST - TX	D	12	0.48		3	6
260	ROUND TOP - TX	D	69	13		13	1
261	ROWENA - TX	D	69	13		5	1
262	RULE - TX	D	69	13.09		5	2
263	RULE - TX	D	69	13.09		2	1
264	RUSSEK STREET - TX	T	138	13.09		50	2
265	RUSTHILL - TX	T	138	70.5	13.09	78	1
266	S.A. AVENUE N. - TX	D	69	13		22	1
267	S.A. AVENUE N. - TX	D	12						STATCAP	1	2
268	S.A. BEN FICKLIN - TX	D	138	13.09		28	1
269	S.A. COKE ST - TX	D	138	13.09		28	1
270	S.A. COLLEGE HILLS WEST - TX	T	138	13.09		22	1
271	S.A. COLLEGE HILLS WEST - TX	T	138	69	13.53	63	1
272	S.A. COLLEGE HILLS WEST - TX	T	138	13.09		28	1
273	S.A. COLLEGE HILLS WEST - TX	T	69						STATCAP	1	22
274	S.A. CONCHO PLANT - TX	T	138	12.47		28	1
275	S.A. EMERSON ST. - TX	D	69	13		28	1
276	S.A. GRAPE CREEK - TX	D	69	13.09		10	3
277	S.A. HIGHLAND - TX	D	138	13.09		28	1
278	S.A. JACKSON ST. - TX	D	69	13		56	2
279	S.A. LAKE DRIVE - TX	D	138	13.09		28	1
280	S.A. MATHIS AIR FIELD - TX	D	69	4.36		9	1
281	S.A. NORTH - TX	T	69	13		28	1
282	S.A. NORTH - TX	T	138	69	6.57	63	1
283	S.A. NORTH - TX	T							STATCAP	2	24
284	S.A. PAULANN - TX	D	138	12.47		25	1
285	S.A. RED CREEK - TX	T	345	138	13.8	450	1
286	S.A. RED CREEK - TX	T	345						REACTOR	1	100
287	S.A. RED CREEK - TX	T							STATCAP	2	50
288	S.A. RED CREEK - TX	T	12						AIR CORE REACTOR	1
289	S.A. SOUTH - TX	D	138	13.09		28	1
290	S.A. SOUTH - TX	D	69	12.47		28	1
291	S.A. SOUTH - TX	D							STATCAP	1	2
292	S.A. SOUTHLAND HILLS - TX	D	138	13.09		28	1
293	S.A. WALNUT STREET - TX	D	69	13		25	1
294	SAGE - TX	D	69	12.5		25	1
295	SANTA ANNA - TX	T	138	69	14.4	34	1
296	SANTA ANNA - TX	T	69	13.09		6	1
297	SANTA RITA - TX	D	69	13.09		30	2
298	SARAGOSA - TX	D	69	13		8	1
299	SHAFTER MINE 4KV MINE - TX	D	69	12		23	3
300	SHEFFIELD (WT) - TX	D	69	12.47		2	1
301	SHEFFIELD (WT) - TX	D	69	13		5	3
302	SHELTON STREET - TX	D	69	13		50	2
303	SILVER - TX	D	69	12.47		25	1
304	SILVER - TX	D	69						STATCAP	1	7
305	SILVER - TX	D							STATCAP	1
306	SONORA - TX	T	69	13		10	3
307	SONORA - TX	T	138	69	13.2	42	1
308	SONORA - TX	T	138						STATCAP	2	58
309	SONORA ATLANTIC - TX	D	69	12		2	3
310	SONORA ATLANTIC - TX	D	69	13		4	1
311	SONORA CITY - TX	T	69	13		13	1
312	SONORA CITY - TX	T	69						STATCAP	1	12
313	SOUTH CROSS - TX	D	69	4.1		8	3
314	SOUTH CROSS - TX	D	69						STATCAP	1	4
315	SPUDDER FLAT - TX	D	138	12.47		9	1
316	SPUR - TX	D	69	2.52		2	2
317	SPUR - TX	D	69	4.1		1	1
318	SPUR - TX	D	69	7.56		2	3
319	SPUR - TX	D	138	69	5.1	56	1
320	SPUR - TX	D	69						STATCAP	1	12
321	STAMFORD - TX	D	69	13		28	1
322	STAMFORD PUMP - TX	D	69	12.5		1	1
323	STAMFORD PUMP - TX	D	69	13.09		1	1
324	STAMFORD PUMP - TX	D	69	13.1		1	1
325	STERLING CITY - TX	T	69	13		7	1
326	SUN VALLEY - TX	D	69	12.5		2	3
327	SWENSON - TX	D	69	12.5		1	3
328	TALPA ATLANTIC - TX	D	69	7.2		1	3
329	TALPA ATLANTIC - TX	D	69	13		502	4
330	TALPA ATLANTIC - TX	D	69	13.1		501	2
331	TANKERSLEY - TX	D	69	13		5	1
332	TEXAS-NEW MEXICO - TX	D	69	4		2	3
333	THROCKMORTON - TX	D	69	13		5	1
334	THROCKMORTON WOODSON OIL CO - TX	D	69	7.2		1	3
335	TRENT (WT) - TX	D	69	7.2		3	3
336	TRUSCOTT CITY - TX	D	69	7.2		1	2
337	TRUSCOTT CITY - TX	D	69	12.47			1
338	TRUSCOTT HUMBLE - TX	D	34.5	2.3		1	3
339	TURKEY - TX	D	69	13		4	1
340	TUSCOLA - TX	D	69	12.47		8	1
341	TUSCOLA - TX	D	69	13		9	1
342	TUSCOLA - TX	D	69						STATCAP	1	14
343	TWILIGHT TRAILS - TX	D	138	13.09		20	1
344	VALENTINE TAP - TX	D	69	7.2		2	3
345	VALENTINE TAP - TX	D	69	13		1	1
346	VALERA - TX	D	69	12.47		1	3
347	VERNON MAIN ST. SUB. - TX	T	69	13		27	4
348	VERNON MAIN ST. SUB. - TX	T	138	69		63	1
349	VERNON MAIN ST. SUB. - TX	T	138						STATCAP	2	29
350	VERNON PLANT SUB - TX	D	69	12.47		14	1
351	VOGEL STREET - TX	D	69	13		25	1
352	WAGGONER REFINERY - TX	D	69	7		1	1
353	WAGGONER REFINERY - TX	D	69	7.2		2	2
354	WAGGONER REFINERY - TX	D	69	12.47		1		1
355	WALNUT STREET - TX	D	69	13		20	1
356	WEINERT - TX	D	69	13.09		3	1
357	WEST TEXAS GULF - TX	D	69	4.36		6	3
358	WINTERS - TX	D	69	12.47		11	1
359	WYLIE CHAMPION - TX	D	138	13.09	5.9	25	1
360	AIRLINE(CP) - TX	T	138	69	12	448	2
361	AIRLINE(CP) - TX	T	69	12.47		106	4
362	AIRLINE(CP) - TX	T	138						STATCAP	1	58
363	AIRLINE(CP) - TX	T	69						STATCAP	3	26
364	AIRLINE(CP) - TX	T	69						AIR CORE REACTOR	5
365	ALAZAN - TX	D	138	24.9		11	1
366	ALAZAN - TX	D	26	12.47		9	1
367	ALICE - TX	T	69	12.47		37	2
368	ALICE - TX	T	138	69	12	93	1
369	ALICE - TX	T	12						STATCAP	2	5
370	AMISTAD - TX	D	138	12.47		6	1
371	ANNA STREET - TX	D	138	12.47		80	2
372	ANNA STREET - TX	D	12						STATCAP	3	2
373	ARANSAS PASS - TX	T	138	69	12	224	1
374	ARCADIA - TX	D	138	12.47		90	2
375	ARCADIA - TX	D	12						STATCAP	2	5
376	ARMSTRONG - TX	D	138	12.47		6	1
377	ASHERTON - TX	T	69	7.2		5	3
378	ASHERTON - TX	T	138	69	13.09	130	1
379	ASHERTON - TX	T	138						STATCAP	1	14
380	ASHERTON - TX	T	69						STATCAP	1	14
381	B&B GRAVEL - TX	D	69	12.47		5	3
382	BANQUETE - TX	D	69	12.47		9	1
383	BAY CITY - TX	D	138	12.47		90	2
384	BAY CITY - TX	D	138						STATCAP	1	14
385	BAY CITY PUMP NO. 1 - TX	D	69	2.3		1	3
386	BAY CITY PUMP NO. 3 - TX	D	69	2.3		3	3
387	BEEVILLE - TX	D	69	12.47		28	1
388	BEEVILLE - TX	D	69	2.2		10	1
389	BEEVILLE - TX	D	12						STATCAP	1	5
390	BEEVILLE - TX	D	69						STATCAP	3	46
391	BERCLAIR - TX	D	69	7.5		3	3
392	BIG FOOT SW - TX	T	138	69	12.47	37	1
393	BIG FOOT SW - TX	T	138						STATCAP	1	14
394	BIG FOOT SW - TX	T	69						STATCAP	1	7
395	BIG OAK - TX	D	23	12		1	1
396	BIG OAK - TX	D	69	13.09		25	1
397	BIG WELLS - TX	D	138	12.47		11	1
398	BISHOP - TX	D	69	12.47		9	1
399	BLACK BAYOU - TX	D	138	12.47		11	1
400	BLESSING - TX	T	69	12		6	4
401	BLESSING - TX	T	138	69	12.47	83	1
402	BLESSING - TX	T	345	138	12.47	600	1
403	BRACKETTVILLE - TX	D	138	12.47		6	1
404	BROOKHOLLOW - TX	D	69	12.47		36	2
405	BROOKHOLLOW - TX	D	12						STATCAP	1	2
406	BROWNSVILLE (CP) - TX	D	69	12.47		20	2
407	BROWNSVILLE (CP) - TX	D	12						STATCAP	2	5
408	BRUNI - TX	D	138	13.09		13	1
409	BUENA VISTA - TX	D	138	12.47		28	1
410	CAMPWOOD - TX	D	26	12.47		3	1
411	CAMPWOOD - TX	D	26	12.47	7.2	3	1
412	CAMPWOOD - TX	D	69	7.2		5	3
413	CAMPWOOD - TX	D	69						STATCAP	2	7
414	CARBIDE - TX	T	138	69	12.47	280	2
415	CASA BLANCA - TX	D	69	13.09		9	1
416	CASA BLANCA - TX	D	12						STATCAP	1	2
417	CATARINA - TX	T	138	12		25	1
418	CAUSEWAY - TX	D	138	12.47		28	1
419	CAUSEWAY - TX	D	12						STATCAP	2	7
420	CHARLOTTE - TX	D	69	13.09		9	1
421	CHARLOTTE - TX	D	12						STATCAP	1	2
422	CHASE FIELD - TX	D	69	12.47		9	1
423	CHOCOLATE BAYOU - TX	T	138	13.09		9	1
424	CHOKE CANYON - TX	D	138	13.09		15	1
425	CITRUS CITY - TX	T	138	13.09		50	2
426	CLARKWOOD - TX	D	138	12.47		56	2
427	CLARKWOOD - TX	D	12						STATCAP	1	2
428	CLEMVILLE - TX	D	69	12.47		9	1
429	COFFEE PORT - TX	D	138	12.47		11	1
430	COFFEE PORT - TX	D	138						STATCAP	1	29
431	COLETO CREEK - TX	T	345	138	12.47	600	1
432	COLETO CREEK - TX	T	345	138	13.8	600	1
433	COLETO CREEK - TX	T	13.8						AIR CORE REACTOR	12	127
434	COLUMBUS - TX	D	69	12.47		9	1
435	COMSTOCK - TX	D	138	13		8	1
436	CONOCO - TX	D	138	12.47		6	1
437	CONTINENTAL(CP) - TX	D	69	7.2		5	3
438	COTULLA - TX	D	138	12		50	2
439	COTULLA - TX	D	12						STATCAP	1	2
440	CRESTONIO - TX	D	138	12.47		19	2
441	DARST - TX	D	69	12.47		20	2
442	DARST - TX	D	12						STATCAP	2	1
443	DEL MAR - TX	D	138	12.47		28	1
444	DEL MAR - TX	D	138						STATCAP	3	75
445	DEL RIO - TX	D	138	12.47		53	2
446	DEL RIO - TX	D	12						STATCAP	4	19
447	DEVINE - TX	D	69	12.47		19	3
448	DEVINE - TX	D	12						STATCAP	3	7
449	DILLEY - TX	D	69	13.09		19	2
450	DILLEY SW - TX	T	138	69	12.47	37	1
451	DILLEY SW - TX	T	138						STATCAP	2	113
452	DILLEY SW - TX	T	69						STATCAP	3	26
453	DILLEY SW - TX	T	69						AIR CORE REACTOR	6
454	DIMMIT - TX	D	138	13.09		25	1
455	EAGLE LAKE - TX	D	69	12.47		20	2
456	EAGLE LAKE - TX	D	12						STATCAP	2	5
457	EAGLE PASS - TX	D	138	12.47		28	1
458	EAGLE PASS - TX	D	138	13.09		25	1
459	EAGLE PASS - TX	D	12						STATCAP	4	14
460	EAGLE PASS - TX	D	138						STATCAP	2	31
461	EAGLE PASS HVDC - TX	T	138	17.9		95	2
462	EAGLE PASS HVDC - TX	T	18						STATCAP	4	25
463	EAGLE PASS HVDC - TX	T	13.2						REACTIVE SPECIAL	1
464	EAST HARRISON - TX	D	69	12.47		101	3
465	EAST HARRISON - TX	D	12						STATCAP	5	24
466	EDNA - TX	D	138	12.47		19	2
467	EDROY - TX	D	69						AIR CORE REACTOR	3
468	EL CAMPO - TX	T	138	12.47		28	1
469	EL CAMPO - TX	T	69	12.47		28	1
470	EL CAMPO - TX	T	138	69	12.47	93	1
471	EL CAMPO - TX	T	12						STATCAP	2	5
472	EL GATO - TX	D	138	13.09		40	1
473	ELSA - TX	D	138	12.47		56	2
474	ELSA - TX	D	12						STATCAP	2	5
475	ENCINAL - TX	D	138	12.47		5	1
476	ESCONDIDO - TX	T	138	12.47		25	1
477	ESCONDIDO - TX	T	138						STATCAP	1	14
478	FALCON SW - TX	T	138						STATCAP	1	14
479	FALFURRIAS - TX	T	138	12.47		11	1
480	FALFURRIAS - TX	T	69	12.47		9	1
481	FALFURRIAS - TX	T	138	69	13.09	54	1
482	FOSTER FIELD - TX	D	69	12.47		9	1
483	FREER - TX	D	69	12.47		9	1
484	FREER - TX	D	69	13.09		9	1
485	FREER - TX	D	12						STATCAP	4	10
486	FRONTERA SWITCH - TX	T	138						STATCAP	2	115
487	FULTON (CP) - TX	D	69	12.47		28	1
488	GANADO - TX	D	138	12.47		9	1
489	GARCENO - TX	D	138	12.47		25	1
490	GARWOOD CITY - TX	D	69	12.47		5	3
491	GARWOOD IDEAL - TX	D	69	4.16		3	3
492	GARWOOD PUMP - TX	D	69	2.3		2	3
493	GARWOOD RELIFT - TX	D	69	2.3		90	3
494	GARZA - TX	T	138	69	12.5	83	1
495	GARZA - TX	T	69						STATCAP	1	11
496	GATEWAY (CP) - TX	D	138	12.47		68	2
497	GEORGE WEST - TX	D	138	12.47		9	1
498	GEORGE WEST - TX	D	12						STATCAP	2	5
499	GOHLKE - TX	D	138	12.47		6	1
500	GOLIAD - TX	D	69	12.47		9	1
501	GOODWIN - TX	D	138	12.47		25	1
502	GOODWIN - TX	D	138	13.09		25	1
503	GOVERNMENT WELLS - TX	D	26	12.47		3	1
504	GOVERNMENT WELLS - TX	D	69	12.47		11	1
505	GOVERNMENT WELLS - TX	D	69	24.9		11	1
506	GOVERNMENT WELLS - TX	D	12						STATCAP	2	5
507	GOVERNMENT WELLS - TX	D	24.94						STATCAP	2	5
508	GREENLAKE - TX	D	69	7.2		3	2
509	GREENLAKE - TX	D	69	12.47		7	4
510	GREGORY - TX	D	69	13.09		50	2
511	GRETA - TX	D	69	12.47		11	1
512	HAINE DRIVE - TX	D	138	12.47		56	2
513	HAINE DRIVE - TX	D	12						STATCAP	1	5
514	HALL ACRES ROAD - TX	D	138	12.47		92	2
515	HARLINGEN NO. 1 - TX	D	69	12.47		56	2
516	HARLINGEN NO. 1 - TX	D	12						STATCAP	2	10
517	HARLINGEN SW ST - TX	T	69	13.09		50	2
518	HARLINGEN SW ST - TX	T	138	69	13.09	130	1
519	HARLINGEN SW ST - TX	T	12						STATCAP	2	10
520	HEARD - TX	D	69	2.4		5	3
521	HEARN ROAD - TX	D	69	7.2		19	3
522	HEARN ROAD - TX	D	69	12.47		28	1
523	HIDALGO - TX	D	138	12.47		25	2
524	HIGHWAY 9 - TX	T	69	12.47		101	3
525	HIGHWAY 9 - TX	T	138	70.5	12.47	200	1
526	HOCHHEIM - TX	D	69	2.4		2	3
527	HOLLY - TX	D	138	12.47		90	2
528	HOMEPORT - TX	D	138	12.47		28	1
529	INDUSTRIAL - TX	D	69	12.47		56	2
530	INGLESIDE CITY - TX	D	138	12.47		56	2
531	JOURDANTON - TX	D	12						STATCAP	2	5
532	JOURDANTON - TX	D	69						STATCAP	2	43
533	KARNES CITY - TX	D	138	13.09		25	1
534	KENEDY - TX	D	69	12.47		11	1
535	KENEDY SWITCH - TX	T	138	12.47		11	1
536	KENEDY SWITCH - TX	T	69	12.47		9	1
537	KENEDY SWITCH - TX	T	138	69	12.47	93	1
538	KINGSVILLE - TX	D	138	12.47		56	2
539	KLEBERG - TX	D	138	12.47		56	2
540	KLEBERG - TX	D	138						STATCAP	1	29
541	KNIPPA - TX	D	69	7.2		5	3
542	KOCH UP RIVER - TX	T	138	69	12.47	93	1
543	LA PALMA 138KV - TX	T	138						STATCAP	2	100
544	LA PALMA 138KV - TX	T	138						AIR CORE REACTOR	3
545	LA PALMA 345KV - TX	T	345	138	13.8	672	1
546	LA PALMA 345KV - TX	T	345	138	34.5			1
547	LA PALMA 69KV - TX	T	138	69	12	297	2
548	LAGUNA - TX	D	69	12.47		28	1
549	LAKESIDE (CP) - TX	D	69	2.3		5	3
550	LANE CITY - TX	T	138						STATCAP	1	29
551	LANE CITY PUMP - TX	D	138	4.16		5	1
552	LAREDO HEIGHTS - TX	D	138	12.47		80	2
553	LAREDO HEIGHTS - TX	D	12						STATCAP	4	14
554	LAREDO PLANT - TX	T	138	12.47		28	1
555	LAREDO PLANT - TX	T	12						STATCAP	4	19
556	LAREDO PLANT - TX	T							REACTIVE SPECIAL	1
557	LAREDO STATCOM - TX	T	34.5	14.04		227	6
558	LEARY LANE - TX	D	69	12.47		90	2
559	LIVE OAK - TX	D	69	12.47		28	1
560	LOLITA - TX	T	138	12.47		11	1
561	LON HILL - TX	T	138	69	12.47	200	1
562	LON HILL - TX	T	138	70.5	12.47	200	1
563	LON HILL - TX	T	345	138	13.8	960	2
564	LON HILL - TX	T	13.8						AIR CORE REACTOR	1
565	LON HILL - TX	T	7.62						AIR CORE REACTOR	2	28
566	LON HILL - TX	T	138						STATCAP	2
567	LONE STAR - TX	D	69	12.47		2	3
568	LONE TREE - TX	D	69	12.47		1	1
569	LONE TREE - TX	D	69						STATCAP	1	14
570	LOS FRESNOS - TX	D	138	12.47		50	2
571	LYTLE - TX	D	69	7.2		5	3
572	MAGILL 138KV - TX	D	138						STATCAP	1	29
573	MAGNOLIA - TX	D	138	13.09		13	1
574	MAGRUDER - TX	D	69	12.47		56	2
575	MALONE - TX	D	69	12.47		5	3
576	MALONE - TX	D	12						STATCAP	1	2
577	MARKHAM - TX	D	69	12.47		6	1
578	MATHIS - TX	D	69	12.47		20	2
579	MATHIS - TX	D	12						STATCAP	2	2
580	MATTHEWS - TX	D	69	12.47		5	3
581	MAVERICK - TX	D	138	12.47		5	1
582	MAYBERRY - TX	T	138	13.09		24	1
583	MAYBERRY - TX	T	138	13.09		40	1
584	MAYO - TX	D	138	13.09		25	1
585	MCCOLL ROAD - TX	D	138	12.47		40	1
586	MCKENZIE ROAD - TX	D	138	12.47		28	1
587	MEDIO CREEK - TX	D	138	12.47		11	1
588	MILITARY HIGHWAY - TX	T	138	13.09		13	1
589	MILITARY HIGHWAY - TX	T	34.5	14.04		151	4
590	MILITARY HIGHWAY - TX	T	138						STATCAP	2	115
591	MILO - TX	D	138	12.47		28	1
592	MINES ROAD - TX	D	138	12.47		28	1
593	MINES ROAD - TX	D	12						STATCAP	2	5
594	MOCKINGBIRD - TX	D	138	13.09		25	1
595	MOORE FIELD - TX	D	138	12.47		25	2
596	MOORE FIELD - TX	D	23	12.47	2.4	11	1
597	MOORE FIELD - TX	D	26	12.47		11	1
598	MORRIS STREET - TX	D	138	12.47		179	4
599	MUSTANG ISLAND - TX	D	69	13.09		9	1
600	NAVAL BASE - TX	D	138	70.5	13.09	120	1
601	NELSON SHARPE III - TX	T	138	138		150	1
602	NELSON SHARPE III - TX	T	345	138	13.8	675	1
603	NELSON SHARPE III - TX	T	138						STATCAP	2	86
604	NORDHEIM - TX	D	138	13.09		13	1
605	NORMANNA CST - TX	D	69	12.47		2	3
606	NORTH ALAMO - TX	D	138	12.47		22	1
607	NORTH ALAMO - TX	D	138	13.09		25	1
608	NORTH ALAMO - TX	D	12						STATCAP	2	5
609	NORTH EDINBURG 345 - TX	T	69	12.47		28	1
610	NORTH EDINBURG 345 - TX	T	69	13.09		25	1
611	NORTH EDINBURG 345 - TX	T	13.2						REACTOR	1	15
612	NORTH EDINBURG 345 - TX	T	138	69	12	83	1
613	NORTH EDINBURG 345 - TX	T	138	69	13.2	73	1
614	NORTH EDINBURG 345 - TX	T	345	138	12	1200	2
615	NORTH EDINBURG 345 - TX	T	138						STATCAP	1	50
616	NORTH EDINBURG 345 - TX	T	345						STATCAP	1	933
617	NORTH EDINBURG 345 - TX	T	12						AIR CORE REACTOR	2	14
618	NORTH ELLA - TX	D	69	2.3		3	3
619	NORTH MCALLEN - TX	D	138	12.47		125	3
620	NORTH MCALLEN - TX	D	12						STATCAP	3	12
621	NORTH MERCEDES - TX	D	138	13.09		50	2
622	NORTH MERCEDES - TX	D	12						STATCAP	1	2
623	NORTH PADRE ISLE. 69 - TX	D	69	12.47		28	1
624	NORTH PADRE ISLE. 69 - TX	D	69	13		28	1
625	NORTH PADRE ISLE. 69 - TX	D	138						STATCAP	1	14
626	NORTH VICTORIA - TX	D	69	12.47		90	2
627	NORTH VICTORIA - TX	D	12						STATCAP	1	2
628	NORTH WESLACO - TX	D	138	12.47		13	1
629	NORTH WESLACO - TX	D	12						STATCAP	1	2
630	OCONNER - TX	D	69	12.47		3	1
631	ODEM - TX	D	69	7.2		5	3
632	ODEM - TX	D	69	12.47		11	1
633	OLEANDER - TX	T	138	70.5	12.47	130	1
634	OLMITO - TX	D	138	12.47		25	1
635	PALACIOS - TX	D	69	12.47		11	1
636	PALMHURST - TX	D	138	12.47		87	2
637	PALMHURST - TX	D	12						STATCAP	2	7
638	PALMVIEW - TX	D	138	12.47		68	2
639	PARKER - TX	D	69	12.47		5	3
640	PEARSALL - TX	D	69	12.47		19	2
641	PEARSALL - TX	D	12						STATCAP	2	5
642	PETTUS - TX	D	69	13.09		13	1
643	PETTUS - TX	D	69	24.9		11	1
644	PHARAOH - TX	D	138	12.47		56	2
645	PHARR - TX	T	138	12.47		75	2
646	PICACHO - TX	D	138						STATCAP	1	29
647	PLACEDO - TX	D	69	12.47		6	1
648	PLEASANTON - TX	T	138	12.47		56	2
649	PLEASANTON - TX	T	138	70.5	13.09	54	1
650	POINT COMFORT - TX	D	69	12		2	1
651	POINT COMFORT - TX	D	69	12.47		3	2
652	POLK AVENUE - TX	D	138	12.47		92	2
653	POLK AVENUE - TX	D	12						STATCAP	6	24
654	PORT ARANSAS - TX	D	69	12.47		56	2
655	PORT ISABEL SWITCH - TX	T	138	12.47		9	1
656	PORT ISABEL SWITCH - TX	T	138	13.09		25	1
657	PORT ISABEL SWITCH - TX	T	12						STATCAP	2	5
658	PORT LAVACA - TX	D	69	12.47		9	1
659	PORT LAVACA - TX	D	69	13.09		9	1
660	PORT LAVACA - TX	D	12						STATCAP	1	2
661	PORT LAVACA - TX	D	69						STATCAP	1	7
662	PORT LAVACA - TX	D							AIR CORE REACTOR	1
663	PORTLAND (CP) - TX	D	138	12.47		56	2
664	PORTLAND (CP) - TX	D	12						STATCAP	2	5
665	PRAIRIE PUMP - TX	D	69	12.47		5	3
666	PREMONT - TX	D	69	12.47		21	2
667	PREMONT - TX	D	13.2						REACTIVE SPECIAL	1
668	PUEBLO - TX	D	138	12.47		30	1
669	RACHAL - TX	D	138	12.47		13	1
670	RANDADO - TX	D	138	12.47		5	1
671	RANGERVILLE - TX	D	23	12.47		8	1
672	RANGERVILLE - TX	D	69	12.47		8	1
673	RANGERVILLE - TX	D	69	13.09		9	1
674	RANGERVILLE - TX	D	69						STATCAP	1	7
675	RAYMONDVILLE #1 - TX	D	69	12.47		36	2
676	RAYMONDVILLE #1 - TX	D	12						STATCAP	2	5
677	RAYMONDVILLE #2 - TX	T	26	12.47		11	1
678	RAYMONDVILLE #2 - TX	T	69	12.47		11	1
679	RAYMONDVILLE #2 - TX	T	138	70.5	12.47	54	1
680	RAYMONDVILLE #2 - TX	T	12						STATCAP	2	5
681	RAYMONDVILLE #2 - TX	T	138						STATCAP	1	15
682	REFUGIO - TX	D	69	12.47		21	2
683	REFUGIO - TX	D	12						STATCAP	4	10
684	RINCON - TX	T	138	69	13.8	84	1
685	RIO BRAVO - TX	D	138	24.9		11	1
686	RIO BRAVO - TX	D	138	24.94		13	1
687	RIO BRAVO - TX	D	26	12.47		14	2
688	RIO BRAVO - TX	D	26	12.47		7		1
689	RIO GRANDE CITY - TX	D	69	12.47		28	1
690	RIO GRANDE CITY - TX	D	138	70.5	12.47	90	1
691	RIO GRANDE CITY - TX	D	12						STATCAP	4	10
692	RIO GRANDE CITY - TX	D	138						STATCAP	1	29
693	RIO HONDO SW STA - TX	T	345	138	13	600	1
694	RIO HONDO SW STA - TX	T	345	138	13.8	675	1
695	RIO HONDO SW STA - TX	T	138						STATCAP	2	105
696	RIO RICO - TX	D	69	12.47		18	2
697	RIO RICO - TX	D	12						STATCAP	1	2
698	RIO RICO - TX	D	69						STATCAP	1	11
699	RIVERSIDE (CP) - TX	D	69	2.3		5	3
700	ROCKPORT (CP) - TX	T	69	12.47		11	1
701	ROCKPORT (CP) - TX	T	138	69	13.09	108	2
702	ROCKSPRINGS ATL - TX	D	69	12.47		3	3
703	RODD FIELD - TX	D	138	12.47		92	2
704	ROMA - TX	T	138	12.47		25	2
705	ROMA - TX	T	12						STATCAP	1	2
706	RUNGE - TX	D	138	13.09		13	1
707	SABINAL - TX	D	69	7.2		5	3
708	SAN BENITO - TX	D		13.09		25	1
709	SAN BENITO - TX	D	69	12.47		25	1
710	SAN BENITO - TX	D	12						STATCAP	3	12
711	SAN DIEGO - TX	D	69	12.47		9	1
712	SAN DIEGO - TX	D	69	13.09		13	1
713	SAN DIEGO - TX	D	12						STATCAP	2	5
714	SAN YGNACIO - TX	D	138	12.47		6	1
715	SANTO NINO - TX	D	138	12.47		58	2
716	SANTO NINO - TX	D	12						STATCAP	2	7
717	SEAWALL - TX	D	69	12.47		9	1
718	SEAWALL - TX	D	69	13.09		13	1
719	SHARYLAND - TX	D	138	12.47		37	1
720	SHARYLAND - TX	D	138	12.47		50	1
721	SIERRA VISTA - TX	D	138	13.09		25	1
722	SINTON - TX	D	69	12.47		20	2
723	SKIDMORE - TX	D	69	13.09		6	1
724	SMITH - TX	D	69	2.3		5	3
725	SOUTH MCALLEN - TX	T	138	12.47		50	2
726	SOUTH MCALLEN - TX	T	12						STATCAP	2	5
727	SOUTH MCALLEN - TX	T	138						STATCAP	1	50
728	SOUTH MISSION - TX	D	138	12.47		50	2
729	SOUTH PADRE ISLAND - TX	D	138	12.47		56	2
730	SOUTH SANTA ROSA - TX	D	138	12.47		50	2
731	SOUTH SANTA ROSA - TX	D	138						STATCAP	1	29
732	SOUTHEAST EDINBURG - TX	D	138	12.47		56	2
733	SOUTHEAST EDINBURG - TX	D	12						STATCAP	1	2
734	SOUTHSIDE - TX	D	138	12.47		112	4
735	STADIUM - TX	D	69	12.47		56	2
736	STADIUM - TX	D	12						STATCAP	2	5
737	STAFFORD HILL - TX	D	69	12.47		3	3
738	STEVENS - TX	D	69	4.16		21	2
739	STEWART ROAD - TX	T	138	69	12	33	1
740	STEWART ROAD - TX	T	138						STATCAP	2	58
741	STRATTON (CP) - TX	T	138	69	12		1
742	SUNCHASE - TX	D	138	12.47		28	1
743	TAFT - TX	D	69	7.2		5	3
744	TAFT - TX	D	69	12.47		11	1
745	TATTON - TX	D	69	13.09		9	1
746	THOMASTON - TX	D	138	12.47		7	1
747	THREE RIVERS (COR) - TX	T	69	12.47		19	2
748	THREE RIVERS (COR) - TX	T	138	70.5	13.09	78	1
749	THREE RIVERS (COR) - TX	T	12						STATCAP	3	7
750	THREE RIVERS (COR) - TX	T	138						STATCAP	2
751	TYNAN - TX	D	69	13.09			1
752	UNIVERSITY - TX	D	138	12.47		28	1
753	UNIVERSITY - TX	D	138	13.09		25	1
754	UVALDE - TX	T	138	12.47		56	2
755	UVALDE - TX	T	138	69	13.09	54	1
756	UVALDE - TX	T	12						STATCAP	5	16
757	UVALDE - TX	T	138						STATCAP	1	14
758	UVALDE - TX	T	69						STATCAP	1	14
759	VICTORIA PLANT - TX	T	138	69	12.47	374	2
760	VICTORIA PLANT - TX	T	69	12		9	1
761	VICTORIA PLANT - TX	T	69	12.47		48	3
762	VICTORIA PLANT - TX	T	69						STATCAP	1	29
763	VILLA CAVAZOS - TX	D	138	12.47		25	1
764	WADSWORTH - TX	D	138	12.47		11	1
765	WASHINGTON STREET - TX	D	69	12.47		101	3
766	WATERWORKS (CP) - TX	D	69	0.46		2	3
767	WATERWORKS (CP) - TX	D	69	2.3		3	3
768	WEAVER ROAD - TX	D	69	12.47		9	1
769	WEIL TRACT - TX	D	138	12.47		45	1
770	WEIL TRACT - TX	D	138						STATCAP	2	58
771	WESLACO SWITCH - TX	T	138						STATCAP	2	86

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not attempt to include or aggregate amounts in a nonspecific category such as "general". Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Line No.	Description of the Good or Service (a)	Name of Associated/Affiliated Company (b)	Account(s) Charged or Credited (c)	Amount Charged or Credited (d)
1	Non-power Goods or Services Provided by Affiliated
2	A. Ray King Transmission Training Facility	(a) OPCo	921	269,653
3	Administrative and General Expenses - Maintenance	AEPSC	935	3,398,837
4	Administrative and General Expenses - Operation	AEPSC	(b) Various (1)	4,988,897
5	Audit Services	AEPSC	920,923	1,184,660
6	Civil & Political Activities & Other Services	AEPSC	Various (2)	681,392
7	Construction Services	AEPSC	107,108	105,333,177
8	Corporate Accounting	AEPSC	920,923	4,651,498
9	Corporate Communications	AEPSC	920,923	750,498
10	Coporate Planning & Budgeting	AEPSC	920,923	982,161
11	Coporate Safety & Health	AEPSC	920,923	580,004
12	Customer Accounts Expenses	AEPSC	Various (3)	5,316,649
13	Customer Service and Informational Expenses	AEPSC	Various (4)	415,405
14	Distribution Expenses - Operation	AEPSC	Various (5)	6,589,100
15	Fuel & Storeroom Services	AEPSC	152,163	4,453,458
16	Human Resources	AEPSC	920,923	2,138,272
17	HVDC East Tie	SWEPCo	Various (6)	749,282
18	Information Technology	AEPSC	920,923	8,255,327
19	Legal GC/Administration	AEPSC	920,923	3,971,637
20	Materials and Supplies	OPCo	Various (7)	739,714
21	Materials and Supplies	PSO	Various (8)	606,988
22	Materials and Supplies	SWEPCo	Various (9)	427,647
23	Non-fuel Oklaunion O&M Billings	PSO	Various (10)	2,028,230
24	Oklaunion Joint Books Allocation	PSO	Various (11)	14,355,607
25	Other Operating Revenues	ETT	456.1	1,538,093
26	Real Estate & Workplace Services	AEPSC	920,923	2,359,539
27	Regulatory Services	AEPSC	920,923	2,120,311
28	Research & Other Services	AEPSC	188	714,087
29	Sales Expenses	AEPSC	911,912	316,287
30	Strategy & Innovation	AEPSC	920,923	1,069,102
31	Transmission Expenses - Maintenance	AEPSC	Various (12)	1,820,395
32	Transmission Expenses - Operation	AEPSC	Various (13)	20,048,915
33	Treasury & Risk	AEPSC	920,923	1,154,669
19
20	Non-power Goods or Services Provided for Affiliated
21	Building and Property Leases	AEPSC	454	1,540,518
22	Construction Services	ETT	107,108	2,685,268
23	Construction Services	SWEPCo	107,108	1,064,343
24	Fleet and Vehicle Charges	AEPSC	Various	261,097
25	HVDC North Transmission Tie	PSO	Various (14)	665,218
26	Material and Supplies	ETT	154	346,181
27	Material and Supplies	OPCo	154	856,188
28	Material and Supplies	PSO	154	1,170,179
29	Material and Supplies	SWEPCo	154	1,763,268
30	Transmission Expenses - Maintenance	ETT	Various (15)	1,330,857
31	Transmission Expenses - Operation	ETT	Various (16)	3,171,910
42

Name of Respondent:

AEP Texas Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

Year/Period of Report

End of:

2018

FOOTNOTE DATA

(a) Concept: NameOfAssociatedAffiliatedCompany

Affiliated Companies shown in Column ( B ):

AEPSC - American Electric Power Service Corporation

ETT - Electric Transmission TX, LLC

OPCo - Ohio Power Company

PSO - Public Service Company of Oklahoma

SWEPCo - Southwestern Electric Power Company

AEPSC Allocations

Certain managerial and professional services provided by AEPSC are allocated among

multiple affiliates. The costs of the services are billed on a direct-charge basis, whenever

possible. Costs incurred to perform services that benefit more than one company are

allocated to the benefiting companies using one of 80 FERC accepted allocation factors.

The allocation factors used to bill for services performed by AEPSC are based upon

formulae that consider factors such as number of customers, number of employees,

number of transmission pole miles, number of invoices and other factors. The data upon

which these formulae are based is updated monthly, quarterly, semi-annually or annually,

depending on the particular factor and its volatility. The billings for services are made

at cost and include no compensation for a return on investment.

FLEET Allocations (Various)

Costs related to AEP's fleet vehicles are allocated in the same manner as the labor of each

department utilizing the vehicles. To the extent a department provides service to another

affiliate company, an applicable share of their fleet costs are also assigned to that

affiliate company.

(b) Concept: AccountsChargedOrCreditedTransactionsWithAssociatedAffiliatedCompanies

Various Account Listings
As Provided in Column (c)	FERC Accounts:
Various (1)	920,921,923,924,925,926,928,930.1,930.2,931
Various (2)	426.1,426.3,426.4
Various (3)	901,902,903,905
Various (4)	907,908,909,910
Various (5)	580,582,583,584,586,588,589
Various (6)	186,561.3,562,570,922,924,925
Various (7)	107,108,154,560,570,935
Various (8)	107,108,154,186,560,592,593,930
Various (9)	107,108,154,570,935
Various (10)	154,426.1,501,506,556,925,926
Various (11)	107,108,152,500,502,505,506,510,511,512,513,514,924
Various (12)	568,569,569.1,569.2,569.3,570,571,572,573
Various (13)	560,561.2,561.3,561.4,561.5,561.6,562,563,566,920,923
Various (14)	560,562,566,570,922,925,926
Various (15)	568'569'570'571'573
Various (16)	560,561.2,562,563,566

Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return