AEP Texas S-4 Registration of securities issued in business combination transactions

As filed with the Securities and Exchange Commission on November 17, 2017

Registration No. 333-________

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________

Form S-4

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

________________________________

AEP Texas Inc.

(Exact name of registrant issuer as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization) 4911 (Primary Standard Industrial Classification Code Number) 51-0007707 (I.R.S. Employer Identification Number)

1 Riverside Plaza

Columbus, OH 43215-2373

(614) 716-1000

(Address, including zip code, and telephone number, including

area code, of registrant’s principal executive offices)

Thomas G. Berkemeyer, Associate General Counsel

American Electric Power Service Corporation

1 Riverside Plaza

Columbus, Ohio 43215-2373

(614) 716-1648

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Approximate date of commencement of proposed exchange offers: As soon as practicable after this Registration Statement is declared effective.

If the securities being registered on this form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, please check the following box. o

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o	Accelerated filer o
Non-accelerated filer x (Do not check if a smaller reporting company)
	Smaller reporting company o
	Emerging Growth Company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. o

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

Exchange Act Rule 13e-4(i) (Cross-Border Issuer Tender Offer) o

Exchange Act Rule 14d-1(d) (Cross-Border Third-Party Tender Offer) o

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Amount to be Registered	Proposed Maximum Offering Price per Note	Proposed Maximum Aggregate Offering Price(1)	Amount of Registration Fee
2.40% Senior Notes, Series C due 2022	$400,000,000	100%	$400,000,000	$49,800
3.80% Senior Notes, Series D due 2047	$300,000,000	100%	$300,000,000	$37,350

(1) Estimated solely for the purpose of calculating the registration fee under Rule 457(f) of the Securities Act of 1933, as amended.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not complete the exchange offers or sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED _____________________, 2017

PRELIMINARY PROSPECTUS

AEP Texas Inc.

Offers to Exchange

$400,000,000 aggregate principal amount of its 2.40% Senior Notes, Series C due 2022 and

$300,000,000 aggregate principal amount of its 3.80% Senior Notes, Series D due 2047,

each of which have been registered under the Securities Act of 1933, as amended,

for any and all of its outstanding

2.40% Senior Notes, Series A due 2022 and

3.80% Senior Notes, Series B due 2047, respectively

We are conducting the Offers to Exchange described above, or Exchange Offers, in order to provide you with an opportunity to exchange your unregistered outstanding notes referred to above, or Outstanding Notes, for substantially identical notes of the same series that have been registered under the Securities Act, which we refer to as Exchange Notes.

The Exchange Offers

• We will exchange all Outstanding Notes that are validly tendered and not validly withdrawn for an equal principal amount of Exchange Notes that are registered under the Securities Act.

• You may withdraw tenders of Outstanding Notes at any time prior to the expiration of the Exchange Offers.

• The Exchange Offers expire at 5:00 p.m., New York City time, on __________, 2017, unless extended. We do not currently intend to extend the Expiration Date.

• The exchange of Outstanding Notes for Exchange Notes in the Exchange Offers will not be a taxable event to holders for United States federal income tax purposes.

• The terms of the Exchange Notes to be issued in the Exchange Offers are substantially identical to the Outstanding Notes of the respective series, except that the Exchange Notes will be registered under the Securities Act, and do not have any transfer restrictions, registration rights or additional interest provisions.

Results of the Exchange Offers

• Except as prohibited by applicable law, the Exchange Notes may be sold in the over-the-counter market, in negotiated transactions or through a combination of such methods. There is no existing market for the Exchange Notes to be issued, and we do not plan to list the Exchange Notes on a national securities exchange or market.

• We will not receive any proceeds from the Exchange Offers.

All untendered Outstanding Notes will remain outstanding and continue to be subject to the restrictions on transfer set forth in the Outstanding Notes and in the indenture governing the Outstanding Notes. In general, the Outstanding Notes may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Other than in connection with the Exchange Offers, we do not currently anticipate that we will register the Outstanding Notes under the Securities Act.

Each broker-dealer that receives Exchange Notes for its own account in the Exchange Offers must acknowledge that it will deliver a prospectus in connection with any resale of those Exchange Notes. The letter of transmittal states that by so acknowledging and delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Notes received in exchange for Outstanding Notes where the broker-dealer acquired such Outstanding Notes as a result of market-making or other trading activities. We have agreed that, for a period of 180 days after the Expiration Date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. See “Plan of Distribution.”

See “Risk Factors” beginning on page 7 for a discussion of certain risks that you should consider before participating in the Exchange Offers.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of the Exchange Notes to be distributed in the Exchange Offers or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus is __________, 2017.

In making your investment decision, you should rely only on the information contained in or incorporated by reference into this prospectus. We have not authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not making an offer of the Exchange Notes in any jurisdiction where the offer thereof is not permitted. The information contained in this prospectus speaks only as of the date of this prospectus.

This prospectus incorporates by reference important business and financial information about us from documents filed with the SEC that have not been included herein or delivered herewith. Information incorporated by reference is available without charge at the website that the SEC maintains at http://www.sec.gov, as well as from other sources. See “Available Information.” In addition, you may request a copy of such document, at no cost, by writing or calling us at the following address or telephone number: Investor Relations, American Electric Power Service Corporation, 1 Riverside Plaza, Columbus, OH 43215; 614-716-1000. In order to receive timely delivery of those materials, you must make your requests no later than five business days before expiration of the applicable exchange offer, or __________, 2017, the present expiration date of the exchange offers.

References to “AEP Texas,” “Company,” “we,” “us” and “our” in this prospectus are references to AEP Texas Inc. specifically or, if the context requires, to AEP Texas Inc. and its subsidiaries, collectively.

TABLE OF CONTENTS
Summary	1
Risk Factors	7
Forward-Looking Statements	16
Use of Proceeds	17
Capitalization	18
Selected Financial Data	19
Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	49
Business	50
Management	56
Compensation Discussion and Analysis	58
Transactions with Related Persons	91
The Exchange Offers	92
Description of the Exchange Notes	104
Material United States Federal Income Tax Consequences Of The Exchange Offers	112
Plan of Distribution	112
Legal Matters	112
Experts	112
Available Information	113
Index to Financial Statements	114

SUMMARY

This summary highlights certain information concerning the Company and this offering that may be contained elsewhere in this prospectus. This summary is not complete and does not contain all the information that may be important to you. You should read this prospectus in its entirety before making an investment decision.

AEP Texas Inc.

Overview

AEP Texas is a wholly owned public utility subsidiary of American Electric Power Company, Inc. (“AEP”). The Company is engaged in the transmission and distribution of electric power to approximately 1,024,000 retail meters through retail electric providers (“REPs”) in its service territory in southern, western and central Texas.

AEP Texas was formed by the merger, effective December 31, 2016, of AEP Texas Central Company (“TCC”) and AEP Texas North Company (“TNC”) into AEP Utilities, Inc. The merger preserved the respective rate structures of the merging entities. AEP Utilities, Inc. changed its name to AEP Texas Inc.

As of December 31, 2016, AEP Texas had approximately 1,500 employees. Among the principal industries served by AEP Texas are chemical and petroleum refining, chemicals and allied products, oil and natural gas extraction, food processing, metal refining, plastics and machinery equipment, agriculture and the manufacturing or processing of cotton seed products, oil products, precision and consumer metal products, meat products and gypsum products. The territory served by AEP Texas also includes several military installations and correctional facilities. AEP Texas is a member of the Electric Reliability Council of Texas (“ERCOT”). Currently, the Company’s operations are:

• Electric Distribution - As of December 31, 2016, through REPs owned by third parties, the Company provides distribution service to approximately 1,024,000 retail meters in west, central and southern Texas. The Company’s service territory includes 92 counties and covers approximately 100,000 square miles. Distribution services are on a cost-of-service basis at rates approved by the Public Utility Commission of Texas (“PUCT”).

• Electric Transmission - The Company’s electric transmission business provides non-discriminatory wholesale open access transmission service in ERCOT. The Company provides retail transmission service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by Federal Energy Regulatory Commission (“FERC”) consistent with PUCT rules.

• Electric Generation - Under Texas Restructuring Legislation, the Company’s utility predecessors exited the generation business and ceased serving retail load. AEP Texas continues to own part of the Oklaunion Plant operated by Public Service Company of Oklahoma, an affiliate of AEP Texas (“PSO”). AEP Texas has leased its entire portion of the output of the Oklaunion Plant through 2027 to a non-utility affiliate pursuant to a purchase power agreement (“PPA”). AEP Texas is evaluating strategic alternatives for its interest in the Oklaunion Plant. Potential alternatives may include, but are not limited to, continued ownership, early termination of the current lease or the sale of its interest in the plant. Management has not made a decision regarding the potential alternatives, nor have they set a specific time frame for a decision. Certain of these alternatives could result in a loss or could reduce future net income and cash flows.

1

The Exchange Offers

In September 2017, we issued the Outstanding Notes in transactions not subject to the registration requirements of the Securities Act of 1933, as amended, or “Securities Act". The term “2022 Exchange Notes” refers to the 2.40% Senior Notes, Series C due 2022 and the term “2047 Exchange Notes” refers to the 3.80% Senior Notes, Series D due 2047, each as registered under the Securities Act, and all of which collectively are referred to as the “Exchange Notes.” The term “Notes” collectively refers to the Outstanding Notes and the Exchange Notes.

General	In connection with the issuance of the Outstanding Notes, we entered into a registration rights agreement with representatives of the initial purchasers of the Outstanding Notes pursuant to which we agreed, among other things, to deliver this prospectus to you and to use commercially reasonable efforts to complete the Exchange Offers within 315 days after the date of original issuance of the Outstanding Notes. You are entitled to exchange in the Exchange Offers your Outstanding Notes for the respective series of Exchange Notes that are identical in all material respects to the Outstanding Notes except:
	Ÿ	the Exchange Notes have been registered under the Securities Act and, therefore, will not be subject to the restrictions on transfer applicable to the Outstanding Notes (except as described in “The Exchange Offers-Resale of Exchange Notes” and “Description of the Exchange Notes-Form; Transfers; Exchanges”);
	Ÿ	the Exchange Notes are not entitled to any registration rights which are applicable to the Outstanding Notes under the registration rights agreement, including any rights to additional interest for failure to comply with the registration rights agreement; and
	Ÿ	the Exchange Notes will bear different CUSIP numbers.
The Exchange Offers	We are offering to exchange:
	Ÿ	$400,000,000 aggregate principal amount of 2.40% Senior Notes, Series C due 2022 that have been registered under the Securities Act for any and all of our existing 2.40% Senior Notes, Series A due 2022 and
	Ÿ	$300,000,000 aggregate principal amount of 3.80% Senior Notes, Series D due 2047 that have been registered under the Securities Act for any and all of our existing 3.80% Senior Notes, Series B due 2047.
	You may only exchange Outstanding Notes in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. Any untendered Outstanding Notes must also be in a minimum denomination of $2,000.
Resale	Based on an interpretation by the staff of the Securities and Exchange Commission, or SEC, set forth in no-action letters issued to third parties, we believe that the Exchange Notes issued pursuant to the Exchange Offers in exchange for the Outstanding Notes may be offered for resale, resold and otherwise transferred by you (unless you are our “affiliate” within the meaning of Rule 405 under the Securities Act) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that:
	Ÿ	you are acquiring the Exchange Notes in the ordinary course of your business; and
	Ÿ	you have not engaged in, do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of the Exchange Notes.
	Any holder of Outstanding Notes who:
	Ÿ	is our affiliate;
	Ÿ	does not acquire Exchange Notes in the ordinary course of its business; or
	Ÿ	tenders its Outstanding Notes in the Exchange Offers with the intention to participate, or for the purpose of participating, in a distribution of Exchange Notes

2

	cannot rely on the position of the staff of the SEC enunciated in the staff’s no-action letters to Morgan Stanley & Co. Incorporated (available June 5, 1991) and Exxon Capital Holdings Corporation (available May 13, 1988), as interpreted in Shearman & Sterling (available July 2, 1993), or similar no-action letters and, in the absence of an exemption therefrom, must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the Exchange Notes. If you are a broker-dealer and receive Exchange Notes for your own account in exchange for Outstanding Notes that you acquired as a result of market-making activities or other trading activities, you must acknowledge that you will deliver this prospectus in connection with any resale of the Exchange Notes and that you are not our affiliate and did not purchase your Outstanding Notes from us or any of our affiliates. See “Plan of Distribution.” Our belief that the Exchange Notes may be offered for resale without compliance with the registration or prospectus delivery provisions of the Securities Act is based on interpretations of the SEC for other exchange offers that the SEC expressed in some of its no-action letters to other issuers in exchange offers like ours. We have not sought a no-action letter in connection with the Exchange Offers, and we cannot guarantee that the SEC would make a similar decision about our Exchange Offers. If our belief is wrong, or if you cannot truthfully make the representations mentioned above, and you transfer any Exchange Note issued to you in the Exchange Offers without meeting the registration and prospectus delivery requirements of the Securities Act, or without an exemption from such requirements, you could incur liability under the Securities Act. We are not indemnifying you for any such liability.
Expiration Date	The Exchange Offers will expire at 5:00 p.m., New York City time, on __________, 2017, unless extended by us. We do not currently intend to extend the Expiration Date.
Withdrawal	You may withdraw the tender of your Outstanding Notes at any time prior to the expiration of the Exchange Offers. We will return to you any of your Outstanding Notes that are not accepted for any reason for exchange, without expense to you, promptly after the expiration or termination of the Exchange Offers.

Conditions to the Exchange Offers	Each Exchange Offer is subject to customary conditions. We reserve the right to waive any defects, irregularities or conditions to exchange as to particular Outstanding Notes. See “The Exchange Offers-Conditions to the Exchange Offers.”
Procedures for Tendering Outstanding Notes	If you wish to participate in any of the Exchange Offers, you must either:
	Ÿ	complete, sign and date the applicable accompanying letter of transmittal, or a facsimile of the letter of transmittal, in accordance with the instructions contained in this prospectus and the letter of transmittal, and mail or deliver such letter of transmittal or facsimile thereof, together with the Outstanding Notes to be exchanged for Exchange Notes, and any other required documents, to the Exchange Agent at the address set forth on the cover page of the letter of transmittal; or
	Ÿ	if you hold Outstanding Notes through The Depository Trust Company, or “DTC”, comply with DTC’s Automated Tender Offer Program procedures described in this prospectus, by which you will agree to be bound by the letter of transmittal.
	By signing, or agreeing to be bound by, the letter of transmittal, you will represent to us that, among other things:
	Ÿ	any Exchange Notes received by you will be acquired in the ordinary course of your business;
	Ÿ	you have no arrangements or understanding with any person to participate in the distribution of the Exchange Notes within the meaning of the Securities Act;
	Ÿ	if you are a broker-dealer, you will receive Exchange Notes for your own account in exchange for Outstanding Notes that were acquired as a result of market-making activities or other trading activities, and you will deliver a prospectus in connection with any resale of such Exchange Notes.

3

Special Procedures for Beneficial Owners	If you are a beneficial owner of Outstanding Notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and you wish to tender those Outstanding Notes in any of the Exchange Offers, you should contact the registered holder promptly and instruct the registered holder to tender those Outstanding Notes on your behalf. If you wish to tender on your own behalf, you must, prior to completing and executing the letter of transmittal and delivering your Outstanding Notes, either make appropriate arrangements to register ownership of the Outstanding Notes in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time and may not be able to be completed prior to the Expiration Date.
Guaranteed Delivery Procedures	If you wish to tender your Outstanding Notes and your Outstanding Notes are not immediately available, or you cannot deliver your Outstanding Notes, the letter of transmittal or any other required documents, or you cannot comply with the procedures under DTC’s Automated Tender Offer Program for transfer of book-entry interests prior to the Expiration Date, you must tender your Outstanding Notes according to the guaranteed delivery procedures set forth in this prospectus under “The Exchange Offers-Guaranteed Delivery Procedures.”
Effect on Holders of Outstanding Notes	As a result of the making of, and upon acceptance for exchange of all validly tendered Outstanding Notes pursuant to the terms of, the Exchange Offers, we will have fulfilled a covenant under the registration rights agreement. Accordingly, we will not be required to pay additional interest on the Outstanding Notes under the circumstances described in the registration rights agreement. If you do not tender your Outstanding Notes in any of the Exchange Offers, you will continue to be entitled to all the rights and subject to all the limitations applicable to the Outstanding Notes as set forth in the Indenture (as defined below), except we will not have any further obligation to you to provide for the exchange and registration of untendered Outstanding Notes under the registration rights agreement. To the extent that Outstanding Notes are tendered and accepted in the Exchange Offers, the trading market for Outstanding Notes that are not so tendered and accepted could be adversely affected.
Consequences of Failure to Exchange	All untendered Outstanding Notes will remain outstanding and continue to be subject to the restrictions on transfer set forth in the Outstanding Notes and in the Indenture. In general, the Outstanding Notes may not be offered or sold unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Other than in connection with the Exchange Offers, we do not currently anticipate that we will register the Outstanding Notes under the Securities Act.
United States Federal Income Tax Consequences	The exchange of Outstanding Notes in the Exchange Offers will not be a taxable event to holders for United States federal income tax purposes. See “Material United States Federal Income Tax Consequences Of The Exchange Offers.”
Use of Proceeds	We will not receive any proceeds from the issuance of the Exchange Notes in the Exchange Offers. See “Use of Proceeds.”
Exchange Agent	The Bank of New York Mellon Trust Company, N.A. is the Exchange Agent for the Exchange Offers. Any questions and requests for assistance with respect to accepting or withdrawing from the Exchange Offers, requests for additional copies of this prospectus or of the letter of transmittal and requests for the notice of guaranteed delivery should be directed to the Exchange Agent. The address and telephone number of the Exchange Agent are set forth in the section captioned “The Exchange Offers-Exchange Agent.”

4

The Exchange Notes

The summary below describes the principal terms of the Exchange Notes. Certain of the terms and conditions described below are subject to important limitations and exceptions. The “Description of the Exchange Notes” section of this prospectus contains more detailed descriptions of the terms and conditions of the Outstanding Notes and Exchange Notes. The Exchange Notes will have terms identical in all material respects to the respective series of Outstanding Notes, except that the Exchange Notes will not contain certain terms with respect to transfer restrictions, registration rights and additional interest for failure to observe certain obligations in the registration rights agreement.

Issuer	AEP Texas Inc.
The Exchange Notes	$400,000,000 principal amount of 2.40% Senior Notes, Series C due 2022 and $300,000,000 principal amount of 3.80% Senior Notes, Series D due 2047.
Maturity	October 1, 2022 for 2022 Exchange Notes and October 1, 2047 for 2047 Exchange Notes.
Interest Rate	2.40% per annum for 2022 Exchange Notes and 3.80% per annum for 2047 Exchange Notes.
Interest Payment Dates	April 1 and October 1 of each year, beginning on April 1, 2018.
Ranking	The Exchange Notes are our senior unsecured obligations and will rank equally in right of payment with all our other senior unsecured obligations and will be effectively subordinated to all of our secured debt, of which we have none outstanding as of November 1, 2017.
Optional Redemption	At any time prior to September 1, 2022, we may redeem the 2022 Exchange Notes at any time, in whole or in part, at a “make whole” redemption price equal to the greater of (1) the principal amount being redeemed or (2) the sum of the present values of the remaining scheduled payments of principal and interest on the 2022 Exchange Notes being redeemed that would be due if such 2022 Exchange Notes matured on September 1, 2022, discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined herein), plus 10 basis points, plus in each case accrued and unpaid interest to the redemption date. At any time prior to April 1, 2047, we may redeem the 2047 Exchange Notes at any time, in whole or in part, at a “make whole” redemption price calculated by us equal to the greater of (1) the principal amount being redeemed or (2) the sum of the present values of the remaining scheduled payments of principal and interest on the 2047 Exchange Notes being redeemed that would be due if such 2047 Exchange Notes matured on April 1, 2047, discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined herein), plus 20 basis points, plus in each case accrued and unpaid interest to the redemption date.
	At any time on or after September 1, 2022, we may redeem the 2022 Exchange Notes in whole or in part at 100% of the principal amount of the 2022 Exchange Notes being redeemed, plus accrued and unpaid interest thereon to but excluding the date of redemption. At any time on or after April 1, 2047, we may redeem the 2047 Exchange Notes in whole or in part at 100% of the principal amount of the 2047 Exchange Notes being redeemed, plus accrued and unpaid interest thereon to but excluding the date of redemption.
Covenants	The Indenture (as defined herein) limits our ability to incur Liens (as defined herein) and limits our ability to merge, consolidate or sell all or substantially all of our assets as an entirety. These limitations are subject to a number of important qualifications and exceptions. For more information, see “Description of the Exchange Notes.”

5

Absence of Established Market for the Exchange Notes	We do not plan to have the Exchange Notes listed on any securities exchange or included in any automated quotation system. There is no existing trading market for the Exchange Notes, and there can be no assurance regarding any future development of a trading market for the Exchange Notes, the price at which holders of the Exchange Notes may be able to sell their Exchange Notes or the ability of such holders to sell their Exchange Notes at all.
Form of Notes	The Exchange Notes will be issued in fully registered book-entry form and each series of Exchange Notes will be represented by one or more global certificates, which will be deposited with or on behalf of DTC and registered in the name of DTC’s nominee. Beneficial interests in global certificates will be shown on, and transfers thereof will be effected only through, records maintained by DTC and its direct and indirect participants, and your interest in any global certificate may not be exchanged for certificated Notes, except in limited circumstances described herein. See “Description of the Exchange Notes-Book-Entry Only Issuance-The Depository Trust Company.”
Trustee	The Bank of New York Mellon Trust Company, N.A.
Governing Law	The Indenture is, and the Exchange Notes will be, governed by, and construed in accordance with, the laws of the State of New York.

6

RISK FACTORS

An investment in the Notes, including a decision to tender your Outstanding Notes in the Exchange Offers, involves a number of risks. Risks described below should be carefully considered together with the other information included in this prospectus. Any of the events or circumstances described as risks below could result in a significant or material adverse effect on our business, results of operations, cash flows or financial condition, and a corresponding decline in the market price of or our ability to repay, the Notes. The risks and uncertainties described below may not be the only risks and uncertainties that we face. Additional risks and uncertainties not currently known may also result in a significant or material adverse effect on our business, results of operations, cash flow or financial condition.

Risks Related to Our Business

We may not be able to recover the costs of our substantial planned investment in capital improvements and additions.

Our business plan calls for extensive investment in capital improvements and additions including the construction of additional transmission facilities, modernizing and restoring existing infrastructure as well as other initiatives.  We currently provide service at rates approved by the PUCT and FERC.  If these regulatory commissions do not approve adjustments to the rates we charge, we would not be able to recover the costs associated with our planned extensive investment.  This would cause our financial results to be diminished.  

Our regulated electric revenues, earnings and results are dependent on the regulation that may limit our ability to recover costs and other amounts.

The rates we collect for the distribution and transmission of electricity are subject to approval by the PUCT and FERC. If our regulated utility earnings exceed the returns established by our regulators, retail electric rates may be subject to review and possible reduction, which may decrease our future earnings. Additionally, if our regulators do not allow recovery of costs incurred in providing service on a timely basis, it could reduce future net income and cash flows and impact financial condition. Similarly, if recovery or other rate relief authorized in the past, even on an interim basis, is not approved or is overturned or reversed on appeal, our future earnings could be negatively impacted. Any regulatory action or litigation outcome that triggers a reversal of a regulatory asset or deferred cost generally results in an impairment to the balance sheet and a charge to the income statement.

As of September 30, 2017, AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $697 million. A base rate review could produce a refund 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.

We may not recover costs incurred to begin construction on projects that are canceled.

Our business plan for the construction of new projects involves a number of risks, including construction delays, nonperformance by equipment and other third party suppliers, and increases in equipment and labor costs.  To limit the risks of these construction projects, we enter into equipment purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals and/or siting or environmental permits.  If any of these projects is canceled for any reason, including our failure to receive necessary regulatory approvals and/or siting or environmental permits, we could incur significant cancellation penalties under the equipment purchase orders and construction contracts.  In addition, if we have recorded any construction work or investments as an asset we may need to impair that asset in the event the project is canceled.

7

Disruptions at power generation facilities owned by third parties could interrupt our sales of transmission and distribution services.

We transmit and distribute electric power that the REPs obtain from power generation facilities owned by third parties. If power generation is disrupted or if power generation capacity is inadequate, our sales of transmission and distribution services may be diminished or interrupted, and our results of operations, financial condition and cash flows could be adversely affected.

Our financial performance may be adversely affected if we are unable to successfully operate our facilities or perform certain corporate functions.

Our financial performance is highly dependent on the successful operation of our transmission and distribution facilities.  Operating these facilities involves many risks, including:

• operator error and breakdown or failure of equipment or processes.

• operating limitations that may be imposed by regulatory requirements.

• compliance with mandatory reliability standards, including mandatory cyber security standards.

• information technology failure that impairs our information technology infrastructure or disrupts normal business operations.

• information technology failure that affects our ability to access customer information or causes us to lose confidential or proprietary data that materially and adversely affects our reputation or exposes us to legal claims.

• catastrophic events such as fires, earthquakes, explosions, hurricanes, tornados, ice storms, terrorism (including cyber-terrorism), floods or other similar occurrences.

Hostile cyber intrusions could severely impair our operations, lead to the disclosure of confidentialinformation and damage our reputation.

We own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run our facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or our operations could view our computer systems, software or networks as targets for cyber attack. In addition, our business requires that we collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.

A successful cyber attack on the systems that control our transmission, distribution or other assets could severely disrupt business operations, preventing us from serving customers or collecting revenues. The breach of certain business systems could affect our ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring.  We maintain cyber insurance to cover liabilities and losses directly arising from a potential cyber event. We also maintain property and casualty insurance that may cover certain resultant physical damage or third-party injuries caused by potential cyber events. However, damage and claims arising from such incidents may exceed the amount of any insurance available and other damage and claims arising from such incidents may not be covered at all. For these reasons, a significant cyber incident could reduce future net income and cash flows and impact financial condition.

In an effort to reduce the likelihood and severity of cyber intrusions, we have a comprehensive cyber security program designed to protect and preserve the confidentiality, integrity and availability of data and systems. In addition, we are subject to mandatory cyber security regulatory requirements. However, cyber threats continue to evolve and adapt, and, as a result, there is a risk that we could experience a successful cyber-attack despite our current security posture and regulatory compliance efforts.

8

A substantial portion of our receivables is concentrated in a small number of REPs, and any delay or default in payment could adversely affect our cash flows, financial condition and results of operations.

Our receivables from the distribution of electricity are collected from REPs that supply the electricity we distribute to our customers. As of December 31, 2016, we did business with approximately one hundred REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for our services or could cause them to delay such payments. We depend on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. Applicable PUCT regulations significantly limit the extent to which we can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in our service territory, and we thus remain at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. The PUCT revised its regulations in 2009 to (i) enhance the financial qualifications required of REPs that began selling power after January 1, 2009, and (ii) authorize utilities to defer bad debts resulting from defaults by REPs for recovery in a future rate case. In 2016, AEP Texas’ largest REP accounted for 18% of its operating revenue, its second largest REP accounted for 18% of its operating revenue and its third largest REP accounted for 10% of its operating revenue. Any delay or default in payment by REPs could adversely affect our cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments we had received from such REP.

Regulation of transmission and distribution rates may delay or deny full recovery of our costs.

The rates we are allowed to charge may or may not match our expenses at any given time. While rate regulation in Texas is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the PUCT will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our actual costs.

Transmission and distribution revenues and results of operations are seasonal.

A portion of our revenues is derived from rates that we collect from each REP based on the amount of electricity we distribute on behalf of each REP. Thus, our revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage.

Transmission and distribution revenues and results of operations are subject to risks that are beyond our control.

The cost of repairing damage to our facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events, in excess of reserves established for such repairs, could reduce future net income and cash flows and impact financial condition.

Technological change may make alternative energy sources more attractive and may adversely affect our revenues and results of operations.

The continuous process of technological development may result in the introduction to retail customers of economically attractive alternatives to purchasing electricity through our distribution facilities. Manufacturers of self-generation facilities continue to develop smaller-scale, more-fuel-efficient generating units that can be cost-effective options for retail customers with smaller electric energy requirements. Any reduction in the amount of electric energy we distribute as a result of these technologies may have an adverse impact on our results of operations and financial condition.

9

Failure to attract and retain an appropriately qualified workforce could harm our results of operations.

Certain events, such as an aging workforce without appropriate replacements, mismatch of skillset or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs.  The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development.  In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise.  Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate our business.  If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.

Parties we have engaged to provide construction materials or services may fail to perform their obligations, which could harm our results of operations.

Our business plan calls for extensive investment in capital improvements and additions, including the construction of additional transmission facilities as well as other initiatives.  We are exposed to the risk of substantial price increases in the costs of materials used in construction.  We have engaged numerous contractors and entered into a large number of agreements to acquire the necessary materials and/or obtain the required construction related services.  As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us.  Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and almost certainly cause delays in that and related projects.  Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions.  This would cause our financial results to be diminished, and we might incur losses or delays in completing construction.

We are subject to physical and financial risks associated with climate change.

Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events. Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.

Increased energy use due to weather changes may require us to invest in additional transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions.

Severe weather impacts our service territories, primarily when thunderstorms, tornadoes, hurricanes and snow or ice storms occur. For a discussion of the impact of Hurricane Harvey, see the “Executive Overview - Hurricane Harvey” section of “MANAGEMENT’S DISCUSSION AND ANALYSIS” in the prospectus. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations. A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region’s economic health, it may also impact our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities.

10

Hazards associated with high-voltage electricity transmission may result in suspension of our operations or the imposition of civil or criminal penalties.

Our operations are subject to the usual hazards associated with high-voltage electricity transmission, including explosions, fires, inclement weather, natural disasters, mechanical failure, unscheduled downtime, equipment interruptions, remediation, chemical spills, discharges or releases of toxic or hazardous substances or gases and other environmental risks. The hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties. AEP Texas maintains property and casualty insurance, but we are not fully insured against all potential hazards incident to our business, such as damage to poles, towers and lines or losses caused by outages.

We are subject to environmental regulations and to laws that can give rise to substantial liabilities.

We are subject to federal, state and local environmental laws and regulations, which impose requirements to minimize environmental and other impacts from our construction activities, establish standards for the management, treatment, storage, transportation and disposal of solid and hazardous wastes and hazardous materials, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities relating to investigation and remediation of contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes were treated or disposed of in accordance with historic standards, as well as properties we currently own or operate. Such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share.

Failure to comply with environmental laws and regulations applicable to us could result in civil or criminal penalties and remediation costs. Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Some of our facilities and properties are located near environmentally sensitive areas such as wetlands and habitats of endangered or threatened species. Compliance with these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our costs and, therefore, our business, financial condition and results of operations.

We are subject to various regulatory requirements, including reliability standards; contract filing requirements; reporting, recordkeeping and accounting requirements; and transaction approval requirements.

Under federal law, owners and operators of the bulk power transmission system are subject to mandatory reliability standards, including both operational and cybersecurity standards, promulgated by the North American Electric Reliability Corporation (“NERC”) and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with new reliability standards may subject us to higher operating costs and/or increased capital expenditures. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable.

The Company must comply with FERC requirements for approval of certain transactions; reporting, recordkeeping and accounting requirements; and for filing contracts related to the provision of jurisdictional services. Under FERC policy, failure to file jurisdictional agreements on a timely basis may result in forgoing the time value of revenues collected under the agreement, but not to the point where a loss would be incurred. The failure to obtain timely approval of transactions or to comply with applicable reporting, recordkeeping or accounting requirements could subject us to penalties that could have a material adverse effect on our financial condition, results of operations and cash flows.

11

Acts of war, terrorist attacks, natural disasters, severe weather and other catastrophic events may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Acts of war, terrorist attacks, natural disasters, severe weather and other catastrophic events may negatively affect our business, financial condition and cash flows in unpredictable ways, such as increased security measures and disruptions of markets. Energy related assets, including, for example, our transmission facilities and the generation and distribution facilities that we interconnect with, may be at risk of acts of war, terrorist attacks, as well as natural disasters, severe weather and other catastrophic events. Such events or the threat of such events may increase costs associated with heightened security requirements. In addition, such events or threats may have a material effect on the economy in general and could result in a decline in energy consumption, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may be negatively impacted by changes in federal income tax policy.

We are impacted by the United States federal income tax policy, including corporate income tax laws. Both the administration and the Republicans in the House of Representatives have made public statements in support of comprehensive tax reform, including significant changes to the United States corporate income tax laws. In addition, on November 2, 2017, the House Ways and Means Committee of the House of Representatives released a tax reform bill titled the “Tax Cuts and Jobs Act” which would, if enacted, significantly revise current United States Federal Income tax laws. Management is currently unable to predict whether these reform discussions or legislative proposals will result in any significant changes to existing tax laws, or if any such changes would have a cumulative positive or negative impact on us. A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers. This and other changes in the United States federal income tax laws could have an adverse effect on cash flow, financial conditions, and liquidity.

Risks Related to Market or Economic Volatility

If we are unable to access capital markets on reasonable terms, it could reduce future net income and cash flows and impact financial condition.

We rely on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows.  Volatility and reduced liquidity in the financial markets could affect our ability to raise capital and fund our capital needs, including construction costs and refinancing maturing indebtedness.  In addition, if capital is available only on less than reasonable terms or to borrowers whose creditworthiness is better than ours, capital costs could increase materially.  Restricted access to capital markets and/or increased borrowing costs could reduce future net income and cash flows and impact financial condition.

Downgrades in our credit ratings could negatively affect our ability to access capital.

The credit ratings agencies periodically review our capital structure and the quality and stability of our earnings.  Any negative ratings actions could constrain the capital available to us and could limit our access to funding for our operations.  Our business is capital intensive, and we are dependent upon our ability to access capital at rates and on terms we determine to be attractive.  In periods of market turmoil, access to capital is difficult for all borrowers.  If our ability to access capital becomes significantly constrained, our interest costs will likely increase and could reduce future net income and cash flows and impact financial condition.

We are considering strategic alternatives for our interest in the Oklaunion Plant and may incur losses as a result.

Management is evaluating strategic alternatives for the Company’s interest in the Oklaunion Plant. Management has not made a decision regarding the potential alternatives, nor have they set a specific timeframe for a decision.  Certain of these alternatives could result in a loss or could reduce future net income and cash flow and harm financial condition.

12

Risks Relating to Our Corporate and Financial Structure

Although the Notes are designated as “senior,” your right to receive payment on the Notes will be unsecured and effectively subordinated to any future secured debt of AEP Texas, to the extent of the value of the collateral therefor.

The Notes will be general senior unsecured obligations and therefore will be effectively subordinated to AEP Texas’ future secured indebtedness. As of September 30, 2017, AEP Texas had no secured indebtedness outstanding. Although the Indenture will place some limitations on our ability to create liens securing indebtedness, there will be significant exceptions to these limitations that would allow us to secure indebtedness without equally and ratably securing the Notes. If AEP Texas were to incur secured indebtedness and if AEP Texas defaulted on the Notes or certain other indebtedness or became bankrupt, liquidated or reorganized, any secured creditor could use the value of the collateral securing that debt to satisfy their secured indebtedness before you would receive any payment on the Notes, unless the Notes were similarly secured as described in “DESCRIPTION OF NOTES - Limitation on Liens” herein. If the value of such collateral is not sufficient to pay any secured indebtedness in full, AEP Texas’ secured creditors would share the value of AEP Texas’ other assets, if any, with you and the holders of other claims against AEP Texas which rank equally with the Notes.

AEP Texas could enter into various transactions that could increase the amount of its outstanding indebtedness, or adversely affect its capital structure or credit ratings, or otherwise adversely affect the holders of the Notes.

The terms of the Notes will not prevent AEP Texas from entering into a variety of acquisition, refinancing, recapitalization or other highly-leveraged transactions. As a result, AEP Texas may enter into a transaction even though the transaction could increase the total amount of its outstanding indebtedness, adversely affect its capital structure or credit ratings or otherwise adversely affect the holders of the Notes.

As of September 30, 2017, AEP Texas had approximately $3.7 billion of indebtedness outstanding (of which $1.1 billion was securitization bonds issued by its subsidiaries).

Certain provisions in our debt instruments limit our financial and operating flexibility.

Our outstanding debt instruments contain numerous financial and operating covenants that place significant restrictions on, among other things, our ability to create liens and engage in mergers and consolidations.

Our outstanding debt instruments also require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios. Our ability to comply with these and other requirements and restrictions may be affected by changes in economic or business conditions, results of operations or other events beyond our control. A failure to comply with the obligations contained in any of our debt instruments could result in acceleration of certain of our outstanding debt.

Certain covenants with respect to the Notes and our outstanding indebtedness are described under “DESCRIPTION OF THE NOTES” and in Note 13 to AEP Texas’ audited financial statements and related notes included elsewhere in this prospectus.

We are subject to control by AEP.

We are an indirect wholly-owned subsidiary of AEP and, therefore, AEP ultimately controls the decision of all matters submitted for shareholder approval. In circumstances involving a conflict of interest between AEP, on the one hand, and our creditors, on the other, AEP could exercise this power to the detriment of our creditors, including holders of the Exchange Notes.

13

Risks Related to the Exchange Offers

There may be adverse consequences if you do not exchange your Outstanding Notes.

If you do not exchange your Outstanding Notes for Exchange Notes in the Exchange Offers, you will continue to be subject to restrictions on transfer of your Outstanding Notes as set forth in the offering memorandum distributed in connection with the private offering of the Outstanding Notes. In general, the Outstanding Notes may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the Outstanding Notes under the Securities Act. You should refer to “Prospectus Summary-The Exchange Offers” and “The Exchange Offers” for information about how to tender your Outstanding Notes.

The tender of Outstanding Notes under the Exchange Offers will reduce the outstanding amount of the Outstanding Notes, which may have an adverse effect upon, and increase the volatility of, the market prices of the Outstanding Notes due to a reduction in liquidity.

Your ability to transfer the Exchange Notes may be limited if there is no active trading market, and there is no assurance that any active trading market will develop for the Exchange Notes.

We are offering the Exchange Notes to the holders of the Outstanding Notes. We do not intend to list the Exchange Notes on any securities exchange. There is currently no established market for the Exchange Notes. If no active trading market develops, you may not be able to resell your Exchange Notes at their fair market value or at all. Future trading prices of the Exchange Notes will depend on many factors including, among other things, prevailing interest rates, our operating results and the market for similar securities. No assurance can be given as to the liquidity of or trading market for the Exchange Notes.

Certain persons who participate in the Exchange Offers must deliver a prospectus in connection with resales of the Exchange Notes.

Based on interpretations of the staff of the SEC contained in Exxon Capital Holdings Corp., SEC no-action letter (available May 13, 1988), Morgan Stanley & Co. Inc., SEC no-action letter (available June 5, 1991) and Shearman & Sterling, SEC no-action letter (available July 2, 1993), we believe that you may offer for resale, resell or otherwise transfer the Exchange Notes without compliance with the registration and prospectus delivery requirements of the Securities Act. We cannot guarantee that the SEC would make a similar decision about our Exchange Offers. If our belief is wrong, or if you cannot truthfully make the representations mentioned above, and you transfer any Exchange Note issued to you in the Exchange Offers without meeting the registration and prospectus delivery requirements of the Securities Act, or without an exemption from such requirements, you could incur liability under the Securities Act. Additionally, in some instances described in this prospectus under “Plan of Distribution,” certain holders of Exchange Notes will remain obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer the Exchange Notes. If such a holder transfers any Exchange Notes without delivering a prospectus meeting the requirements of the Securities Act or without an applicable exemption from registration under the Securities Act, such a holder may incur liability under the Securities Act. We do not and will not assume, or indemnify such a holder against, this liability.

14

Risks Related to the Exchange Notes

The following risk applies to the Outstanding Notes and will apply equally to the Exchange Notes.

If the ratings of the Exchange Notes are lowered or withdrawn, the market value of the Exchange Notes could decrease.

A rating is not a recommendation to purchase, hold or sell the Exchange Notes, inasmuch as the rating does not comment as to market price or suitability for a particular investor. The ratings of the Exchange Notes address the rating agencies’ views as to the likelihood of the timely payment of interest and the ultimate repayment of principal of the Exchange Notes pursuant to their respective terms. There is no assurance that a rating will remain for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if in their judgment circumstances in the future so warrant. In the event that any of the ratings initially assigned to the Exchange Notes is subsequently lowered or withdrawn for any reason, the market price of the Exchange Notes may be adversely affected.

15

FORWARD-LOOKING STATEMENTS

We use forward-looking statements in this prospectus. Statements that are not historical facts are forward-looking statements, and are based on beliefs and assumptions of our management, and on information currently available to management. Forward-looking statements include statements preceded by, followed by or using such words as “believe,” “expect,” “anticipate,” “plan,” “estimate” or similar expressions. Such statements speak only as of the date they are made, and we undertake no obligation to update publicly any of them in light of new information or future events. Actual results may materially differ from those implied by forward-looking statements due to known and unknown risks and uncertainties. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

• The economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory.

• Inflationary or deflationary interest rate trends.

• Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.

• The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.

• Weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs.

• The ability of REPs (as defined below) to satisfy obligations to us.

• Our ability to build or acquire transmission lines and facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs.

• A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.

• Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in distribution and transmission service.

• Resolution of litigation.

• Our ability to constrain operation and maintenance costs.

• Changes in technology, particularly with respect to new, developing, alternative or distributed sources of generation.

• Changes in PUCT regulation and the allocation of costs within ERCOT (each defined below).

• Actions of rating agencies, including changes in the ratings of our debt.

• The impact of volatility in the capital markets on the value of the investments held by our pension, and other postretirement benefit plans and the impact of such volatility on future funding requirements.

• Accounting pronouncements periodically issued by accounting standard-setting bodies.

• Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

In light of these risks and uncertainties, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described. For additional details regarding these and other risks and uncertainties, see “RISK FACTORS” in this prospectus.

16

USE OF PROCEEDS

We will not receive any cash proceeds from the issuance of the Exchange Notes pursuant to the Exchange Offers. In consideration for issuing the Exchange Notes as contemplated in this prospectus, we will receive in exchange a like principal amount of Outstanding Notes, the terms of which are identical in all material respects to the Exchange Notes of the related series, except that the Exchange Notes will not contain terms with respect to transfer restrictions, registration rights and additional interest for failure to observe certain obligations in the registration rights agreement. The Outstanding Notes surrendered in exchange for the Exchange Notes will be retired and cancelled, and will not be reissued. Accordingly, the issuance of the Exchange Notes will not result in any increase in our outstanding debt or the receipt of any additional proceeds.

17

CAPITALIZATION

The following table sets forth our historical unaudited capitalization as of September 30, 2017.

You should read the data set forth below in conjunction with “USE OF PROCEEDS,” “SELECTED FINANCIAL DATA,” “MANAGEMENT’S DISCUSSION AND ANALYSIS,” and our audited and unaudited financial statements and related notes included elsewhere in this prospectus.

The Outstanding Notes that are surrendered in exchange for the Exchange Notes will be retired and cancelled and cannot be reissued. As a result, the issuance of the Exchange Notes will not result in any change in our capitalization.

	September 30, 2017
	(Unaudited)
	(in millions)
Long-term Debt
Securitization Bonds	$	1,059.2
Other Long-term Debt, including amounts due within one year	2,663.3
Total Long-term Debt	3,722.5
Total Equity	2,004.6
Total Capitalization	$	5,727.1

18

SELECTED FINANCIAL DATA

The selected financial data for the years ended December 31, 2016, 2015 and 2014 and as of December 31, 2016 and 2015 have been derived from our audited financial statements which are included elsewhere in this prospectus. The selected financial data for the nine months ended September 30, 2017 and 2016 and as of September 30, 2017 are derived from our unaudited financial statements which are included elsewhere in this prospectus. The selected financial data for the years ended December 31, 2013 and 2012 and as of September 30, 2016 and December 31, 2014, 2013 and 2012 are derived from our unaudited financial statements and are not included elsewhere in this prospectus. The unaudited financial statements reflect all normal and recurring accruals and adjustments, which in the opinion of management, are necessary for the fair representation of that information for and as of the periods presented. Historical results are not necessarily indicative of future results and results for the nine months ended September 30, 2017 are not necessarily indicative of results to be expected for the full year.

You should read the data set forth below in conjunction with “USE OF PROCEEDS,” “MANAGEMENT’S DISCUSSION AND ANALYSIS” and our audited and unaudited financial statements and related notes included elsewhere in this prospectus.

	Nine Months Ended
	September 30,					Years Ended December 31,
	2017		2016			2016			2015			2014		2013		2012
	(in millions)
STATEMENTS OF INCOME DATA
Total Revenues	$	1,164.3	$	1,099.4		$	1,461.4		$	1,458.0		$	1,428.6	$	1,307.8	$	1,273.3
Operating Income	$	322.6	$	298.2		$	379.6		$	320.8		$	352.5	$	371.4	$	364.6
Income From Continuing Operations	$	146.6	$	140.2		$	195.4		$	121.7		$	127.1	$	166.6	$	142.1
Income (Loss) From Discontinued Operations, Net of Tax	—		(49.4		)	(48.8		)	(1.4		)	0.8		10.5		24.9
Net Income	$	146.6	$	90.8		$	146.6		$	120.3		$	127.9	$	177.1	$	167.0
	As of September 30,					As of December 31,
	2017		2016			2016			2015			2014		2013		2012
	(in millions)
BALANCE SHEETS DATA (a)
Total Property, Plant and Equipment	$	7,932.0	$	7,118.6		$	7,322.7		$	6,740.2		$	6,215.0	$	5,732.0	$	5,289.2
Accumulated Depreciation and Amortization	1,592.3		1,540.4			1,542.0			1,480.4			1,434.9		1,363.9		1,298.4
Total Property, Plant and Equipment - Net	$	6,339.7	$	5,578.2		$	5,780.7		$	5,259.8		$	4,780.1	$	4,368.1	$	3,990.8
Total Assets	$	8,679.9	$	7,814.6		$	7,709.1		$	7,882.5		$	7,523.3	$	7,337.9	$	7,619.8
Total Equity	$	2,004.6	$	1,741.0		$	1,657.1		$	1,674.7		$	1,309.4	$	1,212.9	$	1,131.6
Long-term Debt (b)	$	3,722.5	$	3,250.2		$	3,217.7		$	3,443.7		$	3,342.5	$	3,297.5	$	3,268.3
Obligations Under Capital Leases (b)	$	20.9	$	18.2		$	18.4		$	14.8		$	11.6	$	8.6	$	5.7

(a) Amounts reflect reclassifications due to the impact of discontinued operations (see Note 7 and Note 6 to AEP Texas’ audited and unaudited financial statements and related notes, respectively, included elsewhere in this prospectus).

(b) Includes portion due within one year.

19

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following discussion and analysis by management focuses on those factors that had a material effect on our results of operations and financial condition during the periods presented and should be read in connection with AEP Texas’ audited and unaudited financial statements and related notes included elsewhere in this prospectus. The discussion contains certain forward-looking statements that involve risk and uncertainties. See “FORWARD LOOKING STATEMENTS” and “RISK FACTORS.”

EXECUTIVE OVERVIEW

Company Overview

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.

Prior to the merger, AEP Utilities, Inc. was a subsidiary of AEP and holding company for TCC, TNC and CSW Energy, Inc. CSW Energy, Inc. owns the Desert Sky and Trent Wind Farms (Wind Farms). As a result of this merger, the assets and liabilities of CSW Energy, Inc. were transferred to an affiliated company.

AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,024,000 retail customers through REPs in west, central and southern Texas. As of December 31, 2016, AEP Texas had approximately 1,500 employees. Among the principal industries served by AEP Texas are chemical and petroleum refining, chemicals and allied products, oil and natural gas extraction, food processing, metal refining, plastics and machinery equipment, agriculture and the manufacturing or processing of cotton seed products, oil products, precision and consumer metal products, meat products and gypsum products. 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 Plant operated by PSO but has leased its entire portion of the output of the plant through 2027 to a non-utility affiliate.

TCC and TNC Merger

Effective December 31, 2016, TCC and TNC merged into AEP Utilities, Inc., as approved by the FERC and the PUCT in September 2016 and December 2016, respectively. Upon merger, AEP Utilities, Inc. changed its name to AEP Texas Inc., but maintained TCC’s and TNC’s respective customer rates. The PUCT ordered certain post-merger conditions which included a) the sharing of certain interest rate savings with customers and b) an annual credit to customers of approximately $630 thousand for savings resulting from an expected reduction in post-merger debt issuance costs, effective until the next base rate case.

AEP Texas Interim Transmission and Distribution Rates

As of September 30, 2017, AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $697 million. A base rate review could produce a refund 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.

20

U.K. Windfall Tax

AEP Utilities, Inc. was subject to the U.K. Windfall Tax through prior investments in U.K. electric companies. In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. AEP, on behalf of AEP Utilities, Inc. filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, AEP Utilities recognized a tax benefit of $80 million, plus $43 million of pretax interest income in the second quarter of 2013. As of December 31, 2015, the Federal Income Tax receivable was recorded in Deferred Charges and Other Noncurrent Assets on the balance sheet. Prior to the merger, the balance was transferred by AEP Utilities to Parent. In the first quarter of 2017, Parent received the tax refund related to the U.K. Windfall Tax, including interest through the date of the refund.

Changes in Certifying Accountant

On July 26, 2016, the Audit Committee of the Board of Directors (the “Audit Committee”) of AEP determined not to renew the engagement of Deloitte & Touche LLP, the independent registered public accounting firm or independent auditor, as applicable, for the audits of the consolidated financial statements as of and for the fiscal year ending December 31, 2017 of AEP and certain of its subsidiaries, including AEP Texas. On July 26, 2016, the Audit Committee appointed PricewaterhouseCoopers LLP as the independent registered public accounting firm or independent auditor, as applicable, to audit the financial statements of AEP and such subsidiaries for the fiscal year ending December 31, 2017. The Audit Committee invited several accounting firms to participate in a competitive bidding process, including Deloitte & Touche LLP. The decision to retain PricewaterhouseCoopers LLP was made by the Audit Committee. This action effectively dismissed Deloitte & Touche LLP as the independent registered public accounting firm or independent auditor, as applicable, of AEP and such subsidiaries and became effective upon Deloitte & Touche LLP’s completion of its procedures on the financial statements of AEP and such subsidiaries as of and for the year ending December 31, 2016.

Hurricane Harvey

In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. As restoration efforts are ongoing, AEP Texas’ total costs related to this storm are not yet known. AEP Texas’ current estimated cost is approximately $250 million to $300 million, including capitalized expenditures. AEP Texas currently estimates that it will incur approximately $90 million of operation and maintenance costs related to service restoration efforts. 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 September 30, 2017, the total balance of AEP Texas’ deferred storm costs is approximately $97 million including approximately $73 million of incremental storm expenses as a regulatory asset related to Hurricane Harvey. Management is currently in the early stages of analyzing the impact of potential insurance claims and recoveries and, at this time, cannot estimate the impact of this amount. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. AEP Texas is currently evaluating recovery options for the regulatory asset; however, management believes the asset is probable of recovery. The other named hurricanes did not have a material impact on AEP Texas’ operations in the third quarter of 2017. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flows and financial condition.

21

RESULTS OF OPERATIONS

The following discussion of AEP Texas’ results of operations includes an analysis of Gross Margin, which is a non-GAAP financial measure.  Gross Margin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation as presented in AEP Texas’ statements of income.  Under state utility rate making processes, certain transmission and distribution costs are generally reimbursable directly from and billed to customers. As a result, they do not typically impact Operating Income. Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze AEP Texas’ financial performance in that it minimizes the effect on Total Revenues caused by volatility in these expenses. Operating income, which is presented in accordance with GAAP in AEP Texas’ statements of income, is the most comparable GAAP financial measure to the presentation of gross margin.  AEP Texas’ definition of gross margin may not be directly comparable to similarly titled financial measures used by other companies.

The table below summarizes the significant components of AEP Texas’ net income for the years ended December 31, 2016, 2015 and 2014:

	Years Ended December 31,
	2016			2015			2014
	(in millions)
Transmission and Distribution Revenues	$	1,461.4		$	1,458.0		$	1,428.6
Fuel and Other Consumables Used for Electric Generation	32.1			32.1			45.0
Gross Margin	1,429.3			1,425.9			1,383.6
Other Operation and Maintenance	528.2			530.9			487.0
Depreciation and Amortization	413.9			468.9			444.1
Taxes Other Than Income Taxes	107.6			105.3			100.0
Operating Income	379.6			320.8			352.5
Interest Income	10.9			0.8			0.2
Allowance for Equity Funds Used During Construction	9.2			6.7			4.8
Interest Expense	(144.4		)	(148.4		)	(152.0		)
Income From Continuing Operations Before Income Tax Expense	255.3			179.9			205.5
Income Tax Expense	59.9			58.2			78.4
Income From Continuing Operations	195.4			121.7			127.1
Income (Loss) From Discontinued Operations, Net Of Tax	(48.8		)	(1.4		)	0.8
Net Income	$	146.6		$	120.3		$	127.9

KWh Sales/Degree Days

Summary of KWh Energy Sales
	Years Ended December 31,
	2016	2015	2014
	(in millions of KWhs)
Retail:
Residential	11,844	11,562	11,571
Commercial	11,214	10,797	10,908
Industrial	7,892	7,699	7,290
Miscellaneous	577	582	590
Total Retail	31,527	30,640	30,359

22

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.

Summary of Heating and Cooling Degree Days
	Years Ended December 31,
	2016	2015	2014
	(in degree days)
Actual – Heating (a)	201	390	428
Normal – Heating (b)	328	325	337
Actual – Cooling (c)	3,058	2,718	2,553
Normal – Cooling (b)	2,648	2,642	2,618

(a) Heating degree days are calculated on a 55 degree temperature base.

(b) Normal Heating/Cooling represents the thirty-year average of degree days.

(c) Cooling degree days are calculated on a 70 degree temperature base.

23

2016 Compared to 2015

Reconciliation of Year Ended December 31, 2015 to Year Ended December 31, 2016

Net Income

(in millions)

Year Ended December 31, 2015	$	120.3
Changes in Gross Margin:
Retail Margins	49.8
Off-system Sales	(3.0		)
Transmission Revenues	35.2
Other Revenues	(78.6		)
Total Change in Gross Margin	3.4
Changes in Expenses and Other:
Other Operation and Maintenance	2.7
Depreciation and Amortization	55.0
Taxes Other Than Income Taxes	(2.3		)
Interest Income	10.1
Allowance for Equity Funds Used During Construction	2.5
Interest Expense	4.0
Total Change in Expenses and Other	72.0
Income Tax Expense	(1.7		)
Income (Loss) Attributable to Discontinued Operations, Net of Tax	(47.4		)
Year Ended December 31, 2016	$	146.6

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances were as follows:

• Retail Margins increased $50 million primarily due to the following:

• A $20 million increase in revenues associated with the Transmission Cost Recovery Factor (TCRF) revenue rider. This increase was offset by a corresponding increase in Other Operating and Maintenance expenses below.

• A $17 million increase in revenues associated with the Distribution Cost Recovery Factor (DCRF) revenue rider.

• A $13 million increase in weather-normalized margins primarily in the residential and commercial classes.

• Transmission Revenues increased $35 million primarily due to increased transmission investment in Electric Reliability Council of Texas regional transmission organization (ERCOT).

• Other Revenues decreased $79 million primarily due to a decrease in securitization revenue as a result of the final maturity of the first securitization bond, offset in Depreciation and Amortization and other expense items below.

Expenses and Other and Income (Loss) Attributable to Discontinued Operations, Net of Tax changed between years as follows:

• Other Operation and Maintenance expenses increased $3 million primarily due to the following:

• A $16 million increase in transmission expenses primarily due to increased ERCOT Transmission Cost of Service.

This increase was partially offset by:

• A $5 million decrease in storm restoration expenses.

• A $4 million decrease in overhead line expenses.

• A $3 million decrease in vegetation management expenses.

24

• Depreciation and Amortization expenses decreased $55 million primarily due to the following:

• A $65 million decrease primarily due to the final maturity of the first securitization bond, which is offset in Other Revenues above.

This decrease was partially offset by:

• A $14 million increase in depreciable base of transmission and distribution assets.

• Interest Income increased $10 million primarily due to a settlement with the Internal Revenue Service related to the U.K. Windfall Tax.

• Interest Expense decreased $4 million primarily due to the following:

• A $13 million decrease in interest related to securitization transition funding partially due to the final maturity of the first securitization bond. This decrease was offset by a corresponding decrease in Other Revenues above.

This decrease was partially offset by the following:

• An $11 million increase due to the issuances of senior unsecured notes.

• Income (Loss) Attributable to Discontinued Operations, Net of Tax decreased $47 million primarily due to the impairment of the Wind Farms.

25

2015 Compared to 2014

Reconciliation of Year Ended December 31, 2014 to Year Ended December 31, 2015

Net Income

(in millions)

Year Ended December 31, 2014	$	127.9
Changes in Gross Margin:
Retail Margins	27.0
Off-system Sales	(1.4		)
Transmission Revenues	23.6
Other Revenues	(6.9		)
Total Change in Gross Margin	42.3
Changes in Expenses and Other:
Other Operation and Maintenance	(43.9		)
Depreciation and Amortization	(24.8		)
Taxes Other Than Income Taxes	(5.3		)
Interest Income	0.6
Allowance for Equity Funds Used During Construction	1.9
Interest Expense	3.6
Total Change in Expenses and Other	(67.9		)
Income Tax Expense	20.2
Income (Loss) Attributable to Discontinued Operations, Net of Tax	(2.2		)
Year Ended December 31, 2015	$	120.3

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances were as follows:

• Retail Margins increased $27 million primarily due to the following:

• A $26 million increase primarily due to revenues associated with the TCRF revenue rider. This increase was offset by a corresponding increase in Other Operating and Maintenance expenses below.

• A $4 million increase in weather-related usage primarily due to a 4% increase in cooling degree days.

These increases were partially offset by the following:

• A $3 million decrease in weather-normalized margins primarily in the commercial class.

• Transmission Revenues increased $24 million primarily due to increased transmission investment in ERCOT.

• Other Revenues decreased $7 million primarily due to the following:

• A $4 million decrease in securitization revenue related to transition funding, offset in Depreciation and Amortization and other expense items below.

• A $3 million decrease in demand side management revenues.

Expenses and Other and Income Tax Expense changed between years as follows:

• Other Operation and Maintenance expenses increased $44 million primarily due to the following:

• A $29 million increase in transmission expenses primarily due to increased ERCOT Transmission Cost of Service.

• A $5 million increase in storm restoration expenses.

• Depreciation and Amortization expenses increased $25 million primarily due to the following:

• A $12 million increase in depreciation expense primarily due to an increase in depreciable base of transmission and distribution assets.

• A $9 million increase in amortizations due to securitization amortizations related to transition funding, offset in Other Revenues above.

26

• Taxes Other Than Income Taxes increased $5 million primarily due to increased property taxes as a result of additional capital investment and increased tax rates.

• Interest Expense decreased $4 million primarily due to the following:

• A $12 million decrease in interest related to securitization transition funding. This decrease was offset by a corresponding decrease in Other Revenues above.

This decrease was partially offset by the following:

• A $10 million increase due to the issuances of senior unsecured notes.

• Income Tax Expense decreased $20 million primarily due to a decrease in pretax book income and by the recording of federal and state income tax adjustments.

27

The table below summarizes the significant components of AEP Texas’ net income for the three and nine months ended September 30, 2017 and 2016:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(in millions)
Transmission and Distribution Revenues	$	431.2		$	403.9		$	1,164.3		$	1,099.4
Fuel and Other Consumables Used for Electric Generation	8.3			14.2			17.2			24.7
Gross Margin	422.9			389.7			1,147.1			1,074.7
Other Operation and Maintenance	135.9			135.3			388.2			379.2
Depreciation and Amortization	124.0			112.0			343.0			316.0
Taxes Other Than Income Taxes	33.3			30.0			93.3			81.3
Operating Income	129.7			112.4			322.6			298.2
Interest Income	0.5			0.8			1.6			2.6
Allowance for Equity Funds Used During Construction	—			2.0			2.2			7.0
Interest Expense	(35.3		)	(36.2		)	(105.6		)	(108.5		)
Income From Continuing Operations Before Income Tax Expense	94.9			79.0			220.8			199.3
Income Tax Expense	30.6			23.5			74.2			59.1
Income From Continuing Operations	64.3			55.5			146.6			140.2
Income (Loss) From Discontinued Operations, Net Of Tax	—			(47.4		)	—			(49.4		)
Net Income	$	64.3		$	8.1		$	146.6		$	90.8

KWh Sales/Degree Days

Summary of KWh Energy Sales

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2017	2016	2017	2016
	(in millions of KWhs)
Retail:
Residential	3,867	3,944	9,163	9,365
Commercial	3,135	3,174	8,395	8,519
Industrial	1,866	1,906	6,024	5,847
Miscellaneous	157	160	429	439
Total Retail	9,025	9,184	24,011	24,170

28

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.

Summary of Heating and Cooling Degree Days

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2017	2016	2017	2016
	(in degree days)
Actual - Heating (a)	—	—	103	123
Normal - Heating (b)	—	—	199	198
Actual - Cooling (c)	1,393	1,534	2,640	2,619
Normal - Cooling (b)	1,364	1,358	2,396	2,384

(a) Heating degree days are calculated on a 55 degree temperature base.

(b) Normal Heating/Cooling represents the thirty-year average of degree days.

(c) Cooling degree days are calculated on a 70 degree temperature base.

29

Third Quarter of 2017 Compared to Third Quarter of 2016

Reconciliation of Third Quarter 2016 to Third Quarter 2017

Net Income

(in millions)

Third Quarter 2016	$	8.1
Changes in Gross Margin:
Retail Margins	15.8
Off-system Sales	0.4
Transmission Revenues	9.4
Other Revenues	7.6
Total Change in Gross Margin	33.2
Changes in Expenses and Other:
Other Operation and Maintenance	(0.6		)
Depreciation and Amortization	(12.0		)
Taxes Other Than Income Taxes	(3.3		)
Interest Income	(0.3		)
Allowance for Equity Funds Used During Construction	(2.0		)
Interest Expense	0.9
Total Change in Expenses and Other	(17.3		)
Income Tax Expense	(7.1		)
Income (Loss) Attributable to Discontinued Operations, Net of Tax	47.4
Third Quarter 2017	$	64.3

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances were as follows:

• Retail Margins increased $16 million primarily due to the following:

• A $14 million increase in revenues associated with the DCRF revenue rider.

• A $7 million increase due to weather-normalized margins.

These increases were partially offset by:

• A $7 million decrease in weather-related usage primarily due to a 9% decrease in cooling degree days.

• Transmission Revenues increased $9 million primarily due to recovery of increased transmission investment in ERCOT.

• Other Revenues increased $8 million primarily due to increased securitization revenue. The increase in other revenues has corresponding increases in other items below.

Expenses and Other and Income Tax Expense changed between years as follows:

• Depreciation and Amortization expenses increased $12 million primarily due to securitization amortizations related to transition funding, offset in Other Revenues above.

• Taxes Other Than Income Taxes increased $3 million primarily due to increased property taxes as a result of additional capital investment and increased tax rates.

• Income Tax Expense increased $7 million primarily due to an increase in pretax book income and the recording of federal income tax adjustments.

• Income (Loss) Attributable to Discontinued Operations, Net of Tax increased $47 million primarily due to the impairment of the Wind Farms in the third quarter of 2016.

30

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016

Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017

Net Income

(in millions)

Nine Months Ended September 30, 2016	$	90.8
Changes in Gross Margin:
Retail Margins	37.3
Off-system Sales	1.1
Transmission Revenues	27.2
Other Revenues	6.8
Total Change in Gross Margin	72.4
Changes in Expenses and Other:
Other Operation and Maintenance	(9.0		)
Depreciation and Amortization	(27.0		)
Taxes Other Than Income Taxes	(12.0		)
Interest Income	(1.0		)
Allowance for Equity Funds Used During Construction	(4.8		)
Interest Expense	2.9
Total Change in Expenses and Other	(50.9		)
Income Tax Expense	(15.1		)
Income (Loss) Attributable to Discontinued Operations, Net of Tax	49.4
Nine Months Ended September 30, 2017	$	146.6

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances were as follows:

• Retail Margins increased $37 million primarily due to the following:

• A $40 million increase in revenues associated with the DCRF revenue rider.

This increase was partially offset by:

• A $3 million decrease in weather-related usage primarily due to a 16% decrease in heating degree days.

• A $3 million decrease due to weather-normalized margins.

• Transmission Revenues increased $27 million primarily due to recovery of increased transmission investment in ERCOT.

• Other Revenues increased $7 million primarily due to increased securitization revenue. The increase in other revenues has corresponding increases in other items below.

Expenses and Other and Income Tax Expense changed between years as follows:

• Other Operation and Maintenance expenses increased $9 million primarily due to the following:

• A $5 million increase in transmission expenses primarily due to increased ERCOT Transmission Cost of Service.

• A $4 million increase in distribution expenses primarily due to vegetation management.

• Depreciation and Amortization expenses increased $27 million primarily due to the following:

• A $16 million increase in securitization amortizations related to transition funding, offset in Other Revenues above.

• An $11 million increase in depreciation expense primarily due to an increase in depreciable base of transmission and distribution assets.

31

• Taxes Other Than Income Taxes increased $12 million primarily due to increased property taxes as a result of additional capital investment and increased tax rates.

• Allowance for Equity Funds Used During Construction decreased $5 million primarily due to larger short-term debt balances.

• Income Tax Expense increased $15 million primarily due to an increase in pretax book income and the recording of favorable federal and state income tax adjustments in 2016.

• Income (Loss) Attributable to Discontinued Operations, Net of Tax increased $49 million primarily due to the impairment of the Wind Farms in the third quarter of 2016.

32

FINANCIAL CONDITION

AEP Texas measures financial condition by the strength of its balance sheet and the liquidity provided by its cash flows.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

	September 30, 2017				December 31, 2016
	(dollars in millions)
Securitization Bonds	$	1,059.2	18.5	%	$	1,245.8	24.7	%
Other Long-term Debt, including amounts due within one year	2,663.3		46.5	%	1,971.9		39.1	%
Advances from Affiliates	—		—	%	169.5		3.4	%
Total Debt	3,722.5		65.0	%	3,387.2		67.2	%
Common Equity	2,004.6		35.0	%	1,657.1		32.8	%
Total Debt and Equity Capitalization	$	5,727.1	100.0	%	$	5,044.3	100.0	%

AEP Texas’s ratio of debt-to-total capital changed primarily due to an increase in common equity related to capital contributions from Parent, partially offset by an increase in long-term debt due to an increase in construction expenditures.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP Texas’ financial stability.  AEP Texas has a $200 million term loan facility that matures in July 2019 and as of September 30, 2017, it was fully drawn. AEP Texas has access to AEP’s liquidity through AEP’s corporate borrowing program. AEP uses its corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries, including AEP Texas. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The corporate borrowing program is backed by AEP’s commercial paper program and corporate credit facilities. Management believes AEP Texas has adequate liquidity under AEP’s corporate borrowing program.  Additional liquidity is available to AEP Texas from equity contributions from AEP.  Management is committed to maintaining adequate liquidity.  AEP Texas generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt and equity contributions from AEP.  See Note 13 and Note 11 to AEP Texas’ audited and unaudited financial statements and related notes, respectively, appearing elsewhere in this prospectus.

AEP’s Commercial Paper Credit Facilities

AEP manages liquidity by maintaining adequate external financing commitments.  As of September 30, 2017, AEP had a $3 billion revolving credit facility to support its operations. AEP Texas does not maintain separate credit facilities (other than the term loan facility). During the first nine months of 2017, the maximum amount of commercial paper AEP had outstanding was $1.6 billion. The weighted-average interest rate for AEP’s commercial paper during the first nine months of 2017 was 1.19%. As of September 30, 2017, AEP’s available liquidity was approximately $3 billion.

Financing Plan

As of September 30, 2017, AEP Texas has $306.4 million of long-term debt due within one year including $235.5 million related to Transition Funding. In August 2017, AEP Texas remarketed $60 million of 1.75% Pollution Control Bonds due in 2020. The remainder will be retired as it becomes due.

In October 2017, AEP Texas retired $41 million of 5.625% Pollution Control Bonds due in 2017.

33

Debt Covenants and Borrowing Limitations

AEP Texas’ term loan facility and long-term debt agreements (“Debt Agreements”) contain certain covenants and require AEP Texas to maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually defined in the Debt Agreements. As of September 30, 2017, this contractually-defined percentage was 57.1%. Nonperformance under these covenants could result in an event of default under these Debt Agreements. In addition, the acceleration of AEP Texas’ payment obligations, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these Debt Agreements.

The AEP credit facilities do not permit the lenders to refuse a draw on any facility if a material adverse change occurs.

Utility Money Pool borrowings and external borrowings of AEP Texas may not exceed amounts authorized by regulatory orders and AEP manages AEP Texas’ borrowings to stay within those authorized limits.

For a further discussion of AEP Texas’ debt covenant, see Notes 13 and 11, respectively, of AEP Texas’ audited and unaudited financial statements and related notes appearing elsewhere in this prospectus.

Credit Ratings

AEP Texas does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade. AEP Texas has long-term credit ratings from Moody’s and Standard & Poor’s of Baa1 and A-, respectively.

CASH FLOW

For Years Ended December 31, 2016, 2015 and 2014

AEP Texas relies primarily on cash flows from operations and debt issuances to fund its liquidity and investing activities. AEP Texas’ investing and capital requirements are primarily capital expenditures, repaying of long-term debt and advances received from affiliates and paying dividends on common stock.

	Years Ended December 31,
	2016			2015			2014
	(in millions)
Cash and Cash Equivalents at Beginning of Period	$	5.0		$	11.2		$	11.5
Net Cash Flows from Continuing Operating Activities	516.6			495.2			558.0
Net Cash Flows Used for Continuing Investing Activities	(434.4		)	(700.0		)	(565.9		)
Net Cash Flows from (Used for) Continuing Financing Activities	(96.1		)	195.1			7.6
Net Cash Flows from Discontinued Operations	9.5			3.5			—
Net Decrease in Cash and Cash Equivalents	(4.4		)	(6.2		)	(0.3		)
Cash and Cash Equivalents at End of Period	$	0.6		$	5.0		$	11.2

AEP Texas uses advances from affiliates, in addition to capital contributions, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.

34

Operating Activities

		Years Ended December 31,
		2016			2015			2014
		(in millions)
Income from Continuing Operations		$	195.4		$	121.7		$	127.1
Depreciation and Amortization	��	413.9			468.9			444.1
Accrued Taxes, Net		(22.6		)	46.9			11.0
Other		(70.1		)	(142.3		)	(24.2		)
Net Cash Flows from Continuing Operating Activities		$	516.6		$	495.2		$	558.0

Net Cash Flows from Continuing Operating Activities were $517 million in 2016 consisting primarily of Income from Continuing Operations of $195 million and $414 million of noncash Depreciation and Amortization. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets.

Net Cash Flows from Continuing Operating Activities were $495 million in 2015 consisting primarily of Income from Continuing Operations of $122 million and $469 million of noncash Depreciation and Amortization. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets.

Net Cash Flows from Continuing Operating Activities were $558 million in 2014 consisting primarily of Income from Continuing Operations of $127 million and $444 million of noncash Depreciation and Amortization. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets.

Investing Activities

	Years Ended December 31,
	2016			2015			2014
	(in millions)
Construction Expenditures	$	(640.9	)	$	(593.4	)	$	(579.0	)
Change in Advances to Affiliates, Net	139.0			(138.0		)	0.6
Change in Restricted Cash for Securitized Transition Funding	57.1			2.3			(8.8		)
Other	10.4			29.1			21.3
Net Cash Flows Used for Continuing Investing Activities	$	(434.4	)	$	(700.0	)	$	(565.9	)

Net Cash Flows Used for Continuing Investing Activities were $434 million in 2016 primarily due to Construction Expenditures for transmission investments of $641 million. AEP Texas was also repaid advances to affiliates of $139 million.

Net Cash Flows Used for Continuing Investing Activities were $700 million in 2015 primarily due to Construction Expenditures for transmission investments of $593 million. AEP Texas also provided advances to affiliates of $138 million.

Net Cash Flows Used for Continuing Investing Activities were $566 million in 2014 primarily due to Construction Expenditures for transmission investments.

35

Financing Activities

	Years Ended December 31,
	2016			2015			2014
	(in millions)
Capital Contributions from Parent	$	53.0		$	272.3		$	—
Issuance/Retirement of Debt, Net	(229.5		)	96.4			40.5
Change in Advances from Affiliates, Net	117.0			(142.0		)	3.8
Dividends Paid on Common Stock	(34.0		)	(29.0		)	(35.0		)
Other	(2.6		)	(2.6		)	(1.7		)
Net Cash Flows from (Used for) Continuing Financing Activities	$	(96.1	)	$	195.1		$	7.6

Net Cash Flows Used for Continuing Financing Activities in 2016 were $96 million.  AEP Texas had debt issuances of $199 million and debt retirements of $429 million. AEP Texas received advances from affiliates of $117 million and capital contributions of $53 million. AEP Texas also paid $34 million of common stock dividends. See Note 13 to AEP Texas’ audited consolidated financial statements and related notes appearing elsewhere in this prospectus.

Net Cash Flows from Continuing Financing Activities in 2015 were $195 million.  AEP Texas had debt issuances of $370 million and debt retirements of $274 million. AEP Texas received capital contributions of $272 million and repaid advances from affiliates of $142 million. AEP Texas also paid $29 million of common stock dividends. See Note 13 to AEP Texas’ audited consolidated financial statements and related notes appearing elsewhere in this prospectus.

Net Cash Flows from Continuing Financing Activities in 2014 were $8 million.  AEP Texas had debt issuances of $299 million and debt retirements of $258 million. AEP Texas also paid $35 million of common stock dividends.  See Note 13 to AEP Texas’ audited consolidated financial statements and related notes appearing elsewhere in this prospectus.

For Nine Months Ended September 30, 2017 and 2016

	Nine Months Ended   September 30,
	2017			2016
	(in millions)
Cash and Cash Equivalents at Beginning of Period	$	0.6		$	5.0
Net Cash Flows from Continuing Operating Activities	490.5			317.4
Net Cash Flows Used for Continuing Investing Activities	(1,019.7		)	(183.0		)
Net Cash Flows from (Used for) Continuing Financing Activities	528.7			(134.6		)
Net Cash Flows from Discontinued Operations	—			0.9
Net Increase (Decrease) in Cash and Cash Equivalents	(0.5		)	0.7
Cash and Cash Equivalents at End of Period	$	0.1		$	5.7

AEP Texas uses advances from affiliates, in addition to capital contributions, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.

36

Operating Activities

	Nine Months Ended   September 30,
	2017			2016
	(in millions)
Income from Continuing Operations	$	146.6		$	140.2
Depreciation and Amortization	343.0			316.0
Deferred Income Taxes	124.1			31.8
Change in Regulatory Assets	(74.1		)	2.0
Accrued Taxes, Net	1.7			(34.6		)
Other	(50.8		)	(138.0		)
Net Cash Flows from Continuing Operating Activities	$	490.5		$	317.4

Net Cash Flows from Continuing Operating Activities were $491 million in 2017 consisting primarily of Income from Continuing Operations of $147 million and $343 million of noncash Depreciation and Amortization. Deferred Income Taxes increased primarily due to the impacts of bonus depreciation. The change of $74 million in Regulatory Assets was primarily due to the increase in the deferred incremental storm expenses related to Hurricane Harvey. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash.

Net Cash Flows from Continuing Operating Activities were $317 million in 2016 consisting primarily of Income from Continuing Operations of $140 million and $316 million of noncash Depreciation and Amortization. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets.

Investing Activities

	Nine Months Ended   September 30,
	2017			2016
	(in millions)
Construction Expenditures	$	(617.5	)	$	(438.9	)
Change in Restricted Cash for Securitized Transition Funding	23.3			92.6
Change in Advances to Affiliates, Net	(437.0		)	152.9
Other	11.5			10.4
Net Cash Flows Used for Continuing Investing Activities	$	(1,019.7	)	$	(183.0	)

Net Cash Flows Used for Continuing Investing Activities were $1 billion in 2017 primarily due to Construction Expenditures for transmission investments of $618 million. AEP Texas also provided advances to affiliates of $437 million.

Net Cash Flows Used for Continuing Investing Activities were $183 million in 2016 primarily due to Construction Expenditures for transmission investments of $439 million. AEP Texas was also repaid advances to affiliates of $153 million.

37

Financing Activities

	Nine Months Ended   September 30,
	2017			2016
	(in millions)
Capital Contributions from Parent	$	200.0		$	—
Issuance/Retirement of Debt, Net	501.5			(196.0		)
Change in Advances from Affiliates, Net	(169.5		)	88.6
Dividends Paid on Common Stock	—			(25.5		)
Other	(3.3		)	(1.7		)
Net Cash Flows from (Used for) Continuing Financing Activities	$	528.7		$	(134.6	)

Net Cash Flows from Continuing Financing Activities in 2017 were $529 million.  AEP Texas had debt issuances of $760 million and debt retirements of $248 million. AEP Texas received capital contributions of $200 million and repaid advances from affiliates of $170 million. See Note 11 to AEP Texas’ unaudited consolidated financial statements and related notes appearing elsewhere in this prospectus.

Net Cash Flows Used for Continuing Financing Activities in 2016 were $135 million.  AEP Texas had debt retirements of $395 million and debt issuances of $200 million. AEP Texas received advances from affiliates of $89 million. AEP Texas also paid $26 million of common stock dividends. See Note 11 to AEP Texas unaudited consolidated financial statements and related notes appearing elsewhere in this prospectus.

In October 2017, AEP Texas retired $41 million of 5.625% Pollution Control Bonds due in 2017.

BUDGETED CONSTRUCTION EXPENDITURES

Management forecasts approximately $1.1 billion of construction expenditures in 2017. Management forecasts approximately $2.0 billion of construction expenditures in total for 2018 and 2019. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather including the impacts of Hurricane Harvey, legal reviews and the ability to access capital. Management expects to fund these construction expenditures through cash flows from operations and financing activities. AEP Texas can participate in the Utility Money Pool to finance its short-term borrowing needs until long-term funding is arranged.

OFF-BALANCE SHEET ARRANGEMENTS

AEP Texas’ current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that AEP Texas enters in the normal course of business.  As of September 30, 2017 and December 31, 2016, AEP Texas had no off-balance sheet arrangements.

CONTRACTUAL OBLIGATION INFORMATION

AEP Texas’ contractual cash obligations include amounts reported on the balance sheets and other obligations disclosed in the footnotes.  Other than debt issuances and retirements discussed in the “Cash Flow” section above, as of September 30, 2017, contractual obligations has not changed significantly from the year-end discussion below.

38

The following table summarizes AEP Texas’ contractual cash obligations as of December 31, 2016:

Payments Due by Period
Contractual Cash Obligations	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Advances from Affiliates (a)	$	169.5	$	—	$	—	$	—	$	169.5
Interest on Fixed Rate Portion of Long-term Debt (b)	85.3		162.8		156.6		848.8		1,253.5
Fixed Rate Portion of Long-term Debt (c)	263.1		567.2		383.9		1,823.5		3,037.7
Variable Rate Portion of Long-term Debt (d)	—		200.0		—		—		200.0
Capital Lease Obligations (e)	4.2		6.3		4.3		6.3		21.1
Noncancelable Operating Leases (e)	9.6		16.8		13.7		17.9		58.0
Construction Contracts for Capital Assets (f)	170.6		192.4		60.4		160.0		583.4
Total	$	702.3	$	1,145.5	$	618.9	$	2,856.5	$	5,323.2

(a) Represents principal only, excluding interest.

(b) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2016 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(c) See “Long-term Debt” section of Note 13.  Represents principal only, excluding interest.

(d) See “Long-term Debt” section of Note 13.  Represents principal only, excluding interest.  Variable rate debt had interest rates that ranged between 2.06% and 2.4375% as of December 31, 2016.

(e) See Note 12.

(f) Represents only capital assets for which there are signed contracts.  Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs.

AEP Texas’ $4 million liability related to uncertain tax positions is not included above because management cannot reasonably estimate the cash flows by period.

AEP Texas’ portion of pension funding requirements is not included in the above table.  As of December 31, 2016, AEP Texas expects to make contributions to the pension plans totaling $9 million in 2017.  Estimated contributions of $4 million in 2018 and $7 million in 2019 may vary significantly based on market returns, changes in actuarial assumptions and other factors.  Based upon the projected benefit obligation and fair value of assets available to pay pension benefits, the pension plans were 98.8% funded as of December 31, 2016. See “Estimated Future Benefit Payments and Contributions” section of Note 8.

In addition to the amounts disclosed in the contractual cash obligations table above, additional commitments are made in the normal course of business, including standby letters of credit. See “Letters of Credit” section of Note 6 for additional information.

SIGNIFICANT TAX LEGISLATION

The Tax Increase Prevention Act of 2014 included a one-year extension of the 50% bonus depreciation and provided for the extension of research and development, employment and several energy tax credits for 2014.

The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit.

39

These enacted provisions had no material impact on net income or financial condition but did have a favorable impact on cash flows in 2014, 2015 and 2016 and are expected to have a favorable impact on future cash flows.

Federal Tax Reform

Management is evaluating the possibility of federal tax reform. Management has reviewed the tax proposals currently available, particularly the House Republican Blueprint and the November 2, 2017 tax reform bill titled the “Tax Cuts and Jobs Act.” Management has assessed the accumulated deferred federal income taxes on the balance sheet as of December 31, 2016 and identified approximately $600 million in potential excess accumulated deferred federal income taxes based on an assumed 20% federal tax rate. Based upon the last major tax reform initiative in 1986, management believes that approximately $400 million of the excess accumulated deferred income tax related to depreciation would flow back to customers through lower rates over the life of the applicable property, while the remaining $200 million would flow back to customers through lower rates over a negotiated period of years as determined through the regulatory process. Management continues to work with industry groups and legislators to advocate for the benefit of AEP Texas’ customers and shareholders.

CYBER SECURITY

Cyber security presents a growing risk for electric utility systems because a cyber-attack could affect critical energy infrastructure.  Breaches to the cyber security of the grid or to the AEP System are potentially disruptive to people, property and commerce and create risk for business, investors and customers.  In February 2013, President Obama signed an executive order that addresses how government agencies will operate and support their functions in cyber security as well as redefines how the government interfaces with critical infrastructure, such as the electric grid.  The AEP System already operates under regulatory cyber security standards to protect critical infrastructure.  The cyber security framework that was being developed through this executive order was reviewed by FERC and the U.S. Department of Energy (DOE).  In 2014, the DOE published an Energy Sector Cyber Security Framework Implementation Guide for utilities to use in adopting and implementing the National Institute of Standards and Technology framework. AEP continues to be actively engaged in the framework process.

The electric utility industry is one of the few critical infrastructure functions with mandatory cyber security requirements under the authority of FERC. The Energy Policy Act of 2005 gave FERC the authority to oversee reliability of the bulk power system, including the authority to implement mandatory cyber security reliability standards. The North American Electric Reliability Corporation (NERC), which FERC certified as the nation’s Electric Reliability Organization, developed mandatory critical infrastructure protection cyber security reliability standards. AEP participated in the NERC grid security and emergency response exercises, GridEx, in 2013 and 2015.  These efforts, led by NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.

Critical cyber assets, such as data centers, power plants, transmission operations centers and business networks are protected using multiple layers of cyber security and authentication.  The AEP System is constantly scanned for risks or threats. Cyber hackers have been able to breach a number of very secure facilities, from federal agencies, banks and retailers to social media sites.  As these events become known and develop, AEP continually assesses its cyber security tools and processes to determine where to strengthen its defenses. Management continually reviews its business continuity plan to develop an effective recovery effort that decreases response times, limits financial impacts and maintains customer confidence following any business interruption. Management works closely with a broad range of departments, including Legal, Regulatory, Corporate Communications, Audit Services, Information Technology and Security, to ensure the corporate response to consequences of any breach or potential breach is appropriate both for internal and external audiences based on the specific circumstances surrounding the event.

Management continues to take steps to enhance the AEP System’s capabilities for identifying risks or threats and has shared that knowledge of threats with utility peers, industry and federal agencies.  AEP operates a Cyber Security Intelligence and Response Center responsible for monitoring the AEP System for cyber threats as well as collaborating with internal and external threat sharing partners from both industry and government. AEP is a member of a number

40

of industry specific threat and information sharing communities including the Department of Homeland Security and the Electricity Information Sharing and Analysis Center.

AEP has partnered in the past with a major defense contractor who has significant cyber security experience and technical capabilities developed through their work with the U.S. Department of Defense.  AEP works with a consortium of other utilities across the country, learning how best to share information about potential threats and collaborating with each other.  AEP continues to work with a nonaffiliated entity to conduct several discussions each year about recognizing and investigating cyber vulnerabilities.  Through these types of efforts, AEP is working to protect itself while helping its industry advance its cyber security capabilities.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies. Management considers an accounting estimate to be critical if:

• It requires assumptions to be made that were uncertain at the time the estimate was made; and

• Changes in the estimate or different estimates that could have been selected could have a material effect on net income or financial condition.

Management discusses the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the disclosures relating to them.

Management believes that the current assumptions and other considerations used to estimate amounts reflected in the financial statements are appropriate. However, actual results can differ significantly from those estimates.

The sections that follow present information about AEP Texas’s critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate.

Regulatory Accounting

Nature of Estimates Required

AEP Texas’s 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.

AEP Texas recognizes regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds or revenue for costs to be incurred in future periods) for the economic effects of regulation. Specifically, the timing of expense and income recognition is matched with regulated revenues. Liabilities are also recorded for refunds, or probable refunds, to customers that have not been made.

Assumptions and Approach Used

When incurred costs are probable of recovery through regulated rates, regulatory assets are recorded on the balance sheet. Management reviews the probability of recovery at each balance sheet date and whenever new events occur. Similarly, regulatory liabilities are recorded when a determination is made that a refund is probable or when ordered by a commission. Examples of new events that affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs as well as the return of revenues, rate of return earned on invested capital and timing and amount of assets to be recovered through regulated rates. If recovery of a regulatory asset is no longer probable, that regulatory asset is written-off as a charge against earnings. A write-

41

off of regulatory assets or establishment of a regulatory liability may also reduce future cash flows since there will be no recovery through regulated rates.

Effect if Different Assumptions Used

A change in the above assumptions may result in a material impact on net income. Refer to Note 4 to AEP Texas’ audited financial statements and the related notes included elsewhere in this prospectus for further detail related to regulatory assets and regulatory liabilities.

Revenue Recognition - Unbilled Revenues

Nature of Estimates Required

AEP Texas records revenues when energy is delivered to the customer. The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded. This estimate is reversed in the following month and actual revenue is recorded based on meter readings.

Accrued unbilled revenues for AEP Texas were $65 million and $46 million as of December 31, 2016 and 2015, respectively. The changes in unbilled electric utility revenues for AEP Texas were $19 million, $(5) million and $3 million for the years ended December 31, 2016, 2015 and 2014, respectively. The changes in unbilled electric revenues are primarily due to changes in weather and rates.

Assumptions and Approach Used

For AEP Texas, the monthly estimate for unbilled revenues is based upon a primary computation of calendar month billed sales less the current month’s billed KWh, plus the prior month’s unbilled KWh. However, due to meter reading issues, meter drift and other anomalies, a secondary computation is made, based upon an allocation of billed KWh to the current month and previous month, on a billing cycle-by-cycle basis, and by dividing the current month aggregated result by the billed KWh. The two methodologies are evaluated to confirm that they are not statistically different.

Effect if Different Assumptions Used

If the two methodologies used to estimate unbilled revenue are statistically different, a limiter adjustment is made to bring the primary computation within one standard deviation of the secondary computation. Additionally, significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the estimate of unbilled revenue.

Long-Lived Assets

Nature of Estimates Required

In accordance with the requirements of “Property, Plant and Equipment” accounting guidance, AEP Texas evaluates long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable including planned abandonments and a probable disallowance for rate-making on a plant under construction or the assets meet the held-for-sale criteria. AEP Texas utilizes a group composite method of depreciation to estimate the useful lives of long-lived assets. The evaluations of long-lived, held and used assets may result from abandonments, significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operations analyses. If the carrying amount is not recoverable, AEP Texas records an impairment to the extent that the fair value of the asset is less than its book value. Performing an impairment evaluation involves a significant degree of estimation and judgment in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping

42

affected assets and developing the undiscounted and discounted future cash flows (used to estimate fair value in the absence of market-based value, in some instances) associated with the asset. For assets held for sale, an impairment is recognized if the expected net sales price is less than its book value. For regulated assets, the earnings impact of an impairment charge could be offset by the establishment of a regulatory asset, if rate recovery is probable. For competitive generation assets, any impairment charge is recorded against earnings.

Assumptions and Approach Used

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 other than in 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, AEP Texas estimates fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals. Cash flow estimates are based on relevant information available at the time the estimates are made. Estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. Also, when measuring fair value, management evaluates the characteristics of the asset or liability to determine if market participants would take those characteristics into account when pricing the asset or liability at the measurement date. Such characteristics include, for example, the condition and location of the asset or restrictions of the use of the asset. AEP Texas performs depreciation studies that include a review of any external factors that may affect the useful life to determine composite depreciation rates and related lives which are subject to periodic review by state regulatory commissions for cost-based regulated assets. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

Effect if Different Assumptions Used

In connection with the evaluation of long-lived assets in accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the fair value of the asset can vary if different estimates and assumptions would have been used in the applied valuation techniques. The estimate for depreciation rates takes into account the history of interim capital replacements and the amount of salvage expected. In cases of impairment, the best estimate of fair value was made using valuation methods based on the most current information at that time. Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including, but not limited to, differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions and management’s analysis of the benefits of the transaction.

Pension and Other Postretirement Benefits

AEP maintains a qualified, defined benefit pension plan (Qualified Plan), which covers substantially all nonunion and certain union employees, and unfunded, nonqualified supplemental plans (Nonqualified Plans) to provide benefits in excess of amounts permitted under the provisions of the tax law for participants in the Qualified Plan (collectively the Pension Plans).  Additionally, AEP entered into individual employment contracts with certain current and retired executives that provide additional retirement benefits as a part of the Nonqualified Plans.  AEP also sponsors other postretirement benefit plans to provide health and life insurance benefits for retired employees (Postretirement Plans).  The Pension Plans and Postretirement Plans are collectively referred to as the Plans. AEP Texas participates in the Plans.

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1 to AEP Texas’ audited financial statements and related notes included elsewhere in this prospectus.  See Note 8 to AEP Texas’ audited financial statements and related notes included elsewhere in this prospectus for information regarding costs and assumptions for employee retirement and postretirement benefits. See Note 7 to AEP Texas’ unaudited financial statements and related notes included elsewhere in this prospectus for information regarding costs.

43

The following table shows AEP Texas’ net periodic cost (credit) of the Plans:

	Years Ended December 31,
Net Periodic Cost (Credit)	2016			2015			2014
	(in millions)
Pension Plans	$	8.3		$	10.0		$	14.0
Postretirement Plans	(6.7		)	(8.7		)	(7.5		)

The net periodic benefit cost is calculated based upon a number of actuarial assumptions, including expected long-term rates of return on the Plans’ assets.  In developing the expected long-term rate of return assumption for 2017, management evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions.  Management also considered historical returns of the investment markets and tax rates which affect a portion of the Postretirement Plans’ assets.  Management anticipates that the investment managers employed for the Plans will invest the assets to generate future returns averaging 6% for the Qualified Plan and 6.75% for the Postretirement Plans.

The expected long-term rate of return on the Plans’ assets is based on management’s targeted asset allocation and expected investment returns for each investment category.  Assumptions for the Plans are summarized in the following table:

	Pension Plans				Other Postretirement Benefit Plans
			Assumed/				Assumed/
	2017		Expected		2017		Expected
	Target		Long-Term		Target		Long-Term
	Asset		Rate of		Asset		Rate of
	Allocation		Return		Allocation		Return
Equity	25	%	8.55	%	65	%	7.88	%
Fixed Income	59		4.65		33		4.54
Other Investments	15		8.03		—		—
Cash and Cash Equivalents	1		3.30		2		3.30
Total	100	%			100	%

Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation.  Management believes that 6% for the Qualified Plan and 6.75% for the Postretirement Plans are reasonable estimates of the long-term rate of return on the Plans’ assets.  The Pension Plans’ assets had an actual gain of 6.98% and 0.8% for the years ended December 31, 2016 and 2015, respectively.  The Postretirement Plans’ assets had an actual gain of 5.39% for the year ended December 31, 2016 and an actual loss of 0.9% for the year ended December 31, 2015.  Management will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary.

AEP bases the determination of pension expense or income 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 based on the market-related value of assets.  Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.  As of December 31, 2016, AEP Texas had cumulative losses of approximately $3 million that remain to be recognized in the calculation of the market-related value of assets.  These unrecognized net actuarial losses may result in increases in the future pension costs depending on several factors, including whether such losses at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance.

The method used to determine the discount rate that AEP utilizes for determining future obligations is a duration-based method in which 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

44

plan.  The discount rate as of December 31, 2016 under this method was 4.05% for the Qualified Plan, 3.85% for the Nonqualified Plans and 4.1% for the Postretirement Plans.  Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on the Pension Plans’ assets of 6%, discount rates of 4.05% and 3.85% and various other assumptions, management estimates that AEP Texas’ pension costs for the Pension Plans will approximate $8 million, $5 million and $5 million in 2017, 2018 and 2019, respectively.  Based on an expected rate of return on the Postretirement Plans’ assets of 6.75%, a discount rate of 4.1% and various other assumptions, management estimates that AEP Texas’ Postretirement Plan credits will approximate $6 million, $6 million and $7 million in 2017, 2018 and 2019, respectively. Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans.  The actuarial assumptions used may differ materially from actual results.  The effects of a 50 basis point change to selective actuarial assumptions are included in the “Effect if Different Assumptions Used” section below.

The value of AEP’s Pension Plans’ assets remain unchanged at $4.8 billion as of December 31, 2016 and December 31, 2015 primarily due to investment returns and company contributions offsetting benefit payments from AEP System companies.  During 2016, the Qualified Plan paid $340 million and the Nonqualified Plans paid $7 million in benefits to plan participants.  The value of AEP’s Postretirement Plans’ assets decreased to $1.5 billion as of December 31, 2016 from $1.6 billion as of December 31, 2015 primarily due to benefit payments in excess of investment returns and contributions from AEP System companies and the participants.  The Postretirement Plans paid $130 million in benefits to plan participants during 2016.

Nature of Estimates Required

AEP sponsors pension and other retirement and postretirement benefit plans in various forms covering all employees who meet eligibility requirements.  These benefits are accounted for under “Compensation” and “Plan Accounting” accounting guidance.  The measurement of pension and postretirement benefit obligations, costs and liabilities is dependent on a variety of assumptions.

Assumptions and Approach Used

The critical assumptions used in developing the required estimates include the following key factors:

• Discount rate

• Compensation increase rate

• Cash balance crediting rate

• Health care cost trend rate

• Expected return on plan assets

Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.

45

Effect if Different Assumptions Used

The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants.  These differences may result in a significant impact to the amount of pension and postretirement benefit expense recorded.  If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:

							Other Postretirement
	Pension Plans						Benefit Plans
	+0.5%			-0.5%			+0.5%			-0.5%
	(in millions)
Effect on December 31, 2016 Benefit Obligations
Discount Rate	$	(19.4	)	$	21.2		$	(5.9	)	$	6.4
Compensation Increase Rate	1.6			(1.5		)	NA			NA
Cash Balance Crediting Rate	6.4			(6.0		)	NA			NA
Health Care Cost Trend Rate	NA			NA			2.1			(2.0		)
Effect on 2016 Periodic Cost
Discount Rate	(0.8		)	0.9			(0.2		)	0.2
Compensation Increase Rate	0.4			(0.3		)	NA			NA
Cash Balance Crediting Rate	1.1			(1.0		)	NA			NA
Health Care Cost Trend Rate	NA			NA			0.2			(0.2		)
Expected Return on Plan Assets	(2.0		)	2.0			(0.7		)	0.7

NA Not applicable.

ACCOUNTING PRONOUNCEMENTS

New Accounting Pronouncements Adopted During 2017

The FASB issued ASU 2015-11 “Simplifying the Measurement of Inventory” to simplify the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management adopted ASU 2015-11 prospectively, effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption.

The FASB issued ASU 2016-09 “Compensation – Stock Compensation” simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income.  Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption.

46

Pronouncements Effective in the Future

The FASB issued ASU 2014-09 “Revenue from Contracts with Customers” clarifying 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, 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 flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Evaluation of revenue streams and new contracts continues during the second half of 2017. Given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. Management will also continue to monitor any industry implementation issues that arise and analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018.

The FASB issued ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” enhancing 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. 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 sheet 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. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. 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 2016-01 effective January 1, 2018.

The FASB issued ASU 2016-02 “Accounting for Leases” increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet 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 lease 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. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Multiple lease system options were also evaluated. Management plans to elect certain of the following practical expedients upon adoption:

47

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.
Lease term	Elect to use hindsight to determine the lease term.

Evaluation of new lease contracts continues and a compliant lease system solution will be implemented during the second half of 2017. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019.

The FASB issued ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” 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 effective January 1, 2020.

The FASB issued ASU 2016-18 “Restricted Cash” clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report.

The FASB issued ASU 2017-07 “Compensation - Retirement Benefits” 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 in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard and assessing an implementation program which will likely require changes in the way accounting systems capture and report the required information. Unresolved industry implementation issues also continue to be monitored. Management plans to adopt ASU 2017-07 effective January 1, 2018.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, management cannot determine the impact on the reporting of operations and financial position that may result from any such future changes.  The FASB is currently working on several projects including financial instruments, pension and postretirement benefits, hedge accounting and consolidation policy.  The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.

48

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

On July 26, 2016, the Audit Committee of the Board of Directors (the “Audit Committee”) of AEP determined not to renew the engagement of Deloitte & Touche LLP, the independent registered public accounting firm or independent auditor (“Deloitte”), as applicable, for the audits of the consolidated financial statements as of and for the fiscal year ending December 31, 2017 of AEP and certain of its subsidiaries, including AEP Texas Inc. and subsidiaries (the “Company” or “AEP Texas”). On July 26, 2016, the Audit Committee appointed PricewaterhouseCoopers LLP as the independent registered public accounting firm or independent auditor, as applicable (“PwC”), to audit the financial statements of AEP and such subsidiaries for the fiscal year ending December 31, 2017. The Audit Committee invited several accounting firms to participate in a competitive bidding process, including Deloitte. The decision to retain PwC was made by the Audit Committee. This action effectively dismissed Deloitte as the independent registered public accounting firm or independent auditor, as applicable, of AEP and such subsidiaries effective upon Deloitte’s completion of its procedures on the financial statements of AEP and such subsidiaries as of and for the year ended December 31, 2016. Deloitte’s dismissal as to AEP Texas was effective on November 17, 2017.

Deloitte’s reports on the financial statements of the Company as of December 31, 2016 and 2015 and for the years ended did not contain any adverse opinion or a disclaimer of opinion, nor were such reports qualified or modified as to uncertainty, audit scope or accounting principle. During the period from January 1, 2015 through November 17, 2017, (1) there were no disagreements with Deloitte on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure which, if not resolved to the satisfaction of Deloitte, would have caused Deloitte to make reference thereto in its reports on the financial statements of the Company as of December 31, 2016 and 2015 and for the years then ended, and (2) there have been no “reportable events” as defined in Item 304(a)(1)(v) of Regulation S-K.

We have provided a copy of the above disclosures to Deloitte and requested Deloitte to provide us with a letter addressed to the SEC stating whether or not Deloitte agrees with those disclosures related to Deloitte. A copy of Deloitte’s letter, dated November 17, 2017, is attached as Exhibit 16(a) to the registration statement of which this prospectus forms a part.

During the fiscal years ended December 31, 2014 and 2015 and through the subsequent interim period July 26, 2016, AEP, its subsidiary registrants and AEP Texas did not consult with PwC regarding any of the matters or events set forth in Item 304(a)(2)(i) or (ii) of Regulation S-K.

49

BUSINESS

Overview

AEP Texas is a wholly owned public utility subsidiary of AEP. The Company is engaged in the transmission and distribution of electric power to approximately 1,024,000 retail meters through REPs in its service territory in southern, western and central Texas. AEP Texas was formed by the merger, effective December 31, 2016, of AEP Texas Central Company and AEP Texas North Company into AEP Utilities, Inc. The merger preserved the respective rate structures of the merging entities. AEP Utilities, Inc. changed its name to AEP Texas Inc.

As of December 31, 2016, AEP Texas had approximately 1,500 employees. Among the principal industries served by AEP Texas are chemical and petroleum refining, chemicals and allied products, oil and natural gas extraction, food processing, metal refining, plastics and machinery equipment, agriculture and the manufacturing or processing of cotton seed products, oil products, precision and consumer metal products, meat products and gypsum products. The territory served by AEP Texas also includes several military installations and correctional facilities. AEP Texas is a member of ERCOT, which is an intrastate network of retail customers, investor and municipally owned electric utilities, rural electric cooperatives, river authorities, independent generators, power marketers and retail electric providers. ERCOT is an independent system operator wholly within the State of Texas and subject to the jurisdiction of the PUCT. ERCOT’s control area includes most of the State of Texas, other than a portion of the panhandle, portions of the eastern part of the state bordering Arkansas and Louisiana and the area in and around El Paso. Currently, the Company’s operations are:

• Electric Distribution - Through REPs owned by third parties, the Company provides distribution service to approximately 1,024,000 retail meters in west, central and southern Texas. The Company’s service territory includes 92 counties and covers approximately 100,000 square miles. Distribution services are on a cost-of-service basis at rates approved by the PUCT.

• Electric Transmission - The Company’s electric transmission business provides non-discriminatory wholesale open access transmission service in ERCOT. The Company provides retail transmission service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by FERC consistent with PUCT rules.

• Electric Generation - Under Texas Restructuring Legislation, the Company’s utility predecessors exited the generation business and ceased serving retail load. AEP Texas continues to own part of the Oklaunion Plant operated by Public Service Company of Oklahoma, an affiliate of AEP Texas. AEP Texas has leased its entire portion of the output of the Oklaunion Plant through 2027 to a non-utility affiliate pursuant to the PPA. AEP Texas is evaluating strategic alternatives for its interest in the Oklaunion Plant. Potential alternatives may include, but are not limited to, continued ownership, early termination of the current lease or the sale of its interest in the plant. Management has not made a decision regarding the potential alternatives, nor have they set a specific time frame for a decision. Certain of these alternatives could result in a loss which could reduce future net income and cash flows and impact financial condition.

In addition to the PUCT and the FERC, the Company is also subject to regulation by various federal, state and local governmental agencies.

Business Operations

Distribution

In ERCOT, end users purchase their electricity directly from certificated REPs. We deliver electricity for REPs in our certificated service area by carrying lower-voltage power from the substation to the retail electric customer. Our distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity to end users through distribution feeders. Our operations include construction and maintenance of distribution facilities, metering services, outage response services and call center operations. We provide distribution services under tariffs approved by the PUCT. PUCT rules and market protocols govern the commercial operations of distribution

50

companies and other market participants. Rates for these existing services are established pursuant to rate proceedings conducted before municipalities that have original jurisdiction and the PUCT.

Transmission

On behalf of REPs, we deliver electricity from power plants to substations, from one substation to another and to retail electric customers taking power at or above 69 kilovolts in locations throughout our certificated service territory. We construct and maintain transmission facilities and provide transmission services under tariffs approved by the FERC, consistent with PUCT rules.

Generation

The Company is party to the PPA through the end of 2027 with an affiliate, AEP Energy Partners, Inc. (“AEPEP”), whereby AEP Texas sells AEPEP 100% of its capacity and associated energy from its undivided interest (54.69%) in the Oklaunion Plant. 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. The Company is evaluating strategic alternatives for its interest in the Oklaunion Plant. Potential alternatives may include, but are not limited to, continued ownership, early termination of the current lease or the sale of its interest in the plant. Management has not made a decision regarding the potential alternatives, nor have they set a specific time frame for a decision. Certain of these alternatives could result in a loss which could reduce future net income and cash flows and impact financial condition.

Customers

We serve 372 cities that are located in 92 counties across our approximately 100,000 square mile service territory in west, central and southern Texas. At December 31, 2016, our customers consisted of approximately 100 REPs, which sell electricity to more than one million metered customers in our certificated service area. Each REP is licensed by, and must meet minimum creditworthiness criteria established by the PUCT.

The top three REP customers in our service territory are CPL Retail Energy, LP, TXU Energy Retail Company LLC and Reliant Energy Retail Services, LLC. In 2016, AEP Texas’ largest REP accounted for 18% of its operating revenue, its second largest REP accounted for 18% of its operating revenue and its third largest REP accounted for 10% of its operating revenue. We operate using a continuous billing cycle, with meter readings being conducted and invoices being distributed to REPs each business day.

Employees

As of December 31, 2016, we had approximately 1,500 full-time employees. We have no union employees.

Competition

AEP Texas is the sole distribution provider in the majority of its urban areas, and another provider would be required to obtain PUCT approval to serve in those areas and, depending on the location of the facilities, may also be required to obtain franchises from one or more municipalities. A significant portion of AEP Texas’ rural areas is dually certified with rural electric cooperatives. Distributed generation (i.e., power generation located at or near the point of consumption) could result in a reduction of demand for our electric distribution services but has not been a significant factor to date.

Seasonality

A significant portion of our revenues is derived from rates that we collect from each REP based on the amount of electricity we deliver on behalf of that REP. Thus, our revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues generally being higher during the warmer months.

51

Properties

Our distribution and transmission facilities are located in Texas on real property held in fee, by lease, or by easement grant. The real property rights of the Company may be encumbered by easements, mineral rights and other similar encumbrances that may affect the use of such real property. Our facilities consist primarily of high-voltage electric transmission lines and poles, distribution lines, substations, service centers, service wires and meters. Most of our transmission and distribution lines have been constructed over lands of others pursuant to private easements or along public highways and streets as permitted under state law and municipal franchise agreements.

We hold non-exclusive franchises from certain incorporated municipalities in our service territory. In exchange for the payment of fees, these franchises give us the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain our transmission and distribution system and to use that system to conduct our electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 20 to 40 years.

As of December 31, 2016, we owned 42,716 pole miles of distribution lines and 8,389 circuit miles of overhead transmission lines. We also operate eight regional service centers. These service centers consist of office buildings, warehouses and repair facilities that are used in the business of transmitting and distributing electricity.

REGULATION

State and Local Regulation

We conduct our operations pursuant to a certificate of convenience and necessity issued by the PUCT that covers our present service area and facilities. The PUCT and certain municipalities have the authority to set the rates and terms of service provided by us under cost-of-service rate regulation.

Our distribution rates charged to REPs for residential customers are primarily based on amounts of energy delivered, whereas distribution rates for a majority of commercial and industrial customers are primarily based on peak demand. All REPs in our service area pay the same rates and other charges for transmission and distribution services. Transmission rates charged to distribution companies are based on amounts of energy transmitted under “postage stamp” rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay us the same rates and other charges for transmission services.

ERCOT

We are a member of ERCOT. Within ERCOT, prices for wholesale generation and retail electric sales are unregulated, but services provided by transmission and distribution companies are regulated by the PUCT and FERC. ERCOT serves as the regional reliability coordinating council for member electric power systems in most of Texas. ERCOT membership is open to consumer groups, investor and municipally-owned electric utilities, rural electric cooperatives, independent generators, power marketers, river authorities and REPs. The ERCOT market includes most of the State of Texas, other than a portion of the panhandle, portions of the eastern part of the state bordering Arkansas and Louisiana and the area in and around El Paso. The ERCOT market represents approximately 90% of the demand for power in Texas and is one of the nation’s largest power markets. The ERCOT market included available generating capacity of over 78,000 megawatts as of December 31, 2016. Currently, there are only limited direct current interconnections between the ERCOT market and other power markets in the United States and Mexico.

The ERCOT market operates under the reliability standards set by the NERC and approved by the FERC. Within ERCOT, these reliability standards are administered by the Texas Reliability Entity, Inc. (“TRE”). The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state’s main interconnected power transmission grid. The ERCOT Independent System Operator (“ERCOT ISO”) is responsible for operating the bulk electric power supply system in the ERCOT market. Its responsibilities include ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers.

52

Our electric transmission business, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO. Our transmission business has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated area. We participate with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to increase bulk power transfer capability and to remove existing constraints on the ERCOT transmission grid.

The FERC also has certain responsibilities with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by us and other utilities within ERCOT. The FERC has designated the NERC as the Electric Reliability Organization (“ERO”) to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system (Electric Entities). The ERO and the FERC have authority to (a) impose fines and other sanctions on Electric Entities that fail to comply with approved standards and (b) audit compliance with approved standards. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the TRE. We do not anticipate that the reliability standards proposed by the NERC and approved by the FERC will have a material adverse impact on our operations. To the extent that we are required to make additional expenditures to comply with these standards, we would seek to recover those costs through the transmission charges that are imposed on all distribution service providers within ERCOT for electric transmission provided.

Rate Setting Within ERCOT

We provide wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules. Rates are set using a cost-of-service rate-setting mechanism that allows for the recovery of all operating expenses and establishes an authorized return on equity for each transmission company. These rates provide an opportunity for transmission providers to recover their cost-of-service as well as an allowed return on regulatory asset base. The PUCT rules allow a utility to change its transmission rates twice a year to reflect increased investment in the transmission system. ERCOT provides the peak demands for each distribution company annually to the PUCT, which is used to calculate the wholesale transmission revenue amounts to be collected from the distribution company for the next year.

AEP Texas provides retail transmission and distribution service on a cost-of-service basis at rates approved by the PUCT. The PUCT rules allow a utility to change its distribution rates once a year to reflect increased investment in the distribution system, similar to the mechanism described above for transmission. The PUCT rules also allow for distribution retail rates to be adjusted to recover certain expenses to distribution companies. Distribution rates can also be adjusted once a year to recover expenses associated with administering energy efficiency programs through an Energy Efficiency Cost Recovery Factor.

REP Revenue Collection

Distribution retail revenues are collected from REPs that supply the electricity we distribute to their customers. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for our services or could cause them to delay such payments. We depend on these REPs to remit payments on a timely basis, and any delay or default in payment by REPs could adversely affect our cash flows. In the event of a REP’s default, our tariff provides a number of remedies, including our option to request that the PUCT suspend or revoke the certification of the REP. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. However, we remain at risk for payments related to services provided prior to the shift to the replacement REP or the provider of last resort. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made against us involving payments we had received from such REP. If a REP were to file for bankruptcy, we may not be successful in recovering accrued receivables owed by such REP that are unpaid as of the date the REP filed for bankruptcy. However, PUCT regulations authorize utilities, such as us, to defer bad debts resulting from defaults by REPs for recovery in future rate cases, subject to a review of reasonableness and necessity.

53

Restructuring of the Texas Electric Market

In 1999, the Texas legislature adopted the Texas Electric Choice Plan (“Texas electric restructuring law”). Pursuant to that legislation, integrated electric utilities operating within ERCOT were required to unbundle their integrated operations into separate retail sales, power generation and transmission and distribution companies. The legislation provided for a transition period to move to the new market structure and provided a mechanism for the formerly integrated electric utilities to recover stranded and certain other costs resulting from the transition to competition. Those costs were recoverable after approval by the PUCT either through the issuance of securitization bonds or through the implementation of a competition transition charge as a rider to the utility’s tariff. Our integrated utility business was restructured in accordance with the Texas electric restructuring law and its generating stations, except for Oklaunion and some mothballed plants, were sold to third parties. Ultimately we were authorized to recover our stranded costs, other charges and related interest. Most of that amount was recovered through the issuance of securitization bonds by our special purpose subsidiaries. The securitization bonds are repaid through charges imposed on customers in our service territory. As of December 31, 2016, approximately $1.2 billion aggregate principal amount of securitization bonds were outstanding.

Securitization Bonds

AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of the Company, (collectively, “Transition Funding”) were formed for the sole purpose of issuing and servicing securitization bonds related to Texas restructuring legislation. The Company is required to consolidate Transition Funding in its financial statements. The securitized bonds outstanding totaled $1.1 billion and $1.2 billion as of June 30, 2017 and December 31, 2016, respectively, and are included in current and long-term debt on the balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from the Company under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The holders of the securitization bonds have no recourse to the Company or any other AEP entity.

Capital Expenditures

Our construction program is reviewed continuously and is revised from time to time in response to changes in estimates of customer demand, business and economic conditions, the cost and availability of capital, environmental requirements and other factors. Changes in construction schedules and costs, and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, federal income and other taxes, and other factors affecting cash requirements, may increase or decrease the estimated capital requirements for our construction program. For a discussion of budgeted construction expenditures for the years 2017 through 2019, see “MANAGEMENT’S DISCUSSION AND ANALYSIS - Budgeted Construction Expenditures” appearing elsewhere in this prospectus.

Environmental Matters

The Company is subject to federal, state and local environmental laws and regulations, which impose requirements on wastewater discharges, regulate the issuance of permits for our construction activities, establish standards for the management, treatment, storage, transportation and disposal of solid and hazardous wastes and hazardous materials, and impose obligations to investigate and remediate contamination in certain circumstances.

The Company currently incurs costs to meet the requirements in our permits and satisfy obligations imposed as part of the authorization for the construction of new or expanded facilities. Typically these costs are incorporated into cost of service rates.

Superfund addresses liabilities for costs to clean up contaminated sites due to disposal of hazardous substances. Liabilities relating to investigation and remediation of contamination, as well as other liabilities concerning hazardous materials or contamination, such as claims for personal injury or property damage, can arise at third party sites where such wastes have been treated or disposed of, as well as properties currently owned or operated by us. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site

54

can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites

Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Some of these properties include aboveground or underground storage tanks and associated piping. Our facilities and equipment are often situated on or near property owned by others so that, if they are the source of contamination, others’ property may be affected. We are not aware of any pending or threatened claims against us with respect to environmental contamination relating to our properties, or of any investigation or remediation of contamination at our properties that entail costs likely to materially affect us.

Claims have been made or threatened against electric utilities for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields associated with electric transmission and distribution lines. While we do not believe that a causal link between electromagnetic field exposure and injury has been generally established and accepted in the scientific community, the liabilities and costs imposed on our business could be significant if such a relationship is established or accepted. We are not aware of any pending or threatened claims against us for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields and electric transmission and distribution lines that entail costs likely to have a material adverse effect on our results of operations, financial position or liquidity.

Related Party Transactions

AEP Texas, AEP and their affiliates engage in related party transactions. See Note 14 to AEP Texas’ audited financial statements and related notes appearing elsewhere in this prospectus.

Legal Proceedings

For a discussion of the significant legal proceedings, including, but not limited to, litigation and other matters involving the Company, reference is made to the information in Note 4 and Note 6 to our audited consolidated financial statements, included elsewhere in this prospectus.

In the normal course of business from time to time, other lawsuits, claims, environmental actions and other governmental proceedings can arise against the Company. To the extent that damages are assessed in any of these actions or proceedings, the Company believes that its insurance coverage is adequate. Although we cannot accurately predict the amount of any liability that may ultimately arise with respect to such matters, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of other currently pending or threatened lawsuits and claims will have a material adverse effect on our financial condition or results of operations.

55

MANAGEMENT

Set forth below is information regarding AEP Texas’ executive officers and members of our board of directors. There have been no events under any bankruptcy act, no criminal proceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any executive officer or directors during the past ten years. Some officers serve in the same capacities at AEP and the Company.

Listed below are the executive officers and directors at September 30, 2017.

Nicholas K. Akins

Chairman of the Board and Chief Executive Officer of the Company

Chairman of the Board, President and Chief Executive Officer of AEP

Age 57

Chairman of the Board of AEP since January 2014, President of AEP since January 2011 and Chief Executive Officer of AEP since November 2011

Mr. Akins is a board member of Fifth Third Bancorp.

David M. Feinberg

Director, Vice President and Secretary of the Company

Executive Vice President, General Counsel and Secretary of AEP

Age 47

Executive Vice President of AEP since January 2013. He was Senior Vice President, General Counsel and Secretary of AEP from January 2012 to December 2012.

Brian X. Tierney

Director, Vice President and Chief Financial Officer of the Company

Executive Vice President and Chief Financial Officer of AEP since October 2009.

Age 50

Lisa M. Barton

Director, Vice President of the Company

Executive Vice President - Transmission of AEP

Age 51

Executive Vice President - Transmission of AEPSC since August 2011. Ms. Barton is a board member of Transource Energy, a joint venture with Great Plains Energy. She also serves on the board of directors of Electric Transmission Texas (ETT), a joint venture with Berkshire Hathaway Energy Company.

Paul Chodak, III

Director of the Company

Executive Vice President-Utilities of AEP

Age 53

Executive Vice President-Utilities of AEP since January 2017. He was President and Chief Operating Officer of Indiana Michigan Power Company from July 2010 to December 2016.

Lana L. Hillebrand

Director, Vice President of the Company

Executive Vice President and Chief Administrative Officer of AEP

Age 57

Executive Vice President and Chief Administrative Officer since January 2017. She was Senior Vice President and Chief Administrative Officer of AEP from December 2012 to December 2016. She previously served as South Region leader - Senior Partner at Aon Hewitt from 2010 to 2012.

56

Mark C. McCullough

Director, Vice President of the Company

Executive Vice President- Generation of AEP

Age 57

Executive Vice President-Generation of AEPSC since January 2011.

Charles R. Patton

Director of the Company

Executive Vice President-External Affairs of AEP

Age 58

Executive Vice President-External Affairs of AEP since January 2017. He was President and Chief Operating Officer of Appalachian Power Company from June 2010 to December 2016.

Judith E. Talavera

President and Chief Operating Officer of the Company

Age 44

President and Chief Operating Officer of AEP Texas since June 2016

Director of Regulatory Services for AEP Texas from November 2008 to May 2016

57

COMPENSATION DISCUSSION AND ANALYSIS

The following information relates to AEP. AEP Texas Inc. does not establish its own executive compensation policy and procedures and there is no separate Compensation Committee of its Board of Managers. In this Compensation Discussion and Analysis and the executive compensation tables and narratives that follow, we discuss 2016 compensation paid to our named executive officers for services provided to AEP and us. This section explains AEP’s compensation philosophy, summarizes its compensation programs and reviews compensation decisions for the following named executive officers: It includes information for Mr. Powers who retired from AEP in August 2017.

Name	Title
Mr. Akins	Chairman, Chief Executive Officer and President of AEP
Mr. Tierney	Executive Vice President and Chief Financial Officer of AEP
Mr. Powers	Former Vice Chairman of AEP
Mr. Feinberg	Executive Vice President and General Counsel of AEP
Ms. Barton	Executive Vice President Transmission of AEP
Ms. Hillebrand	Executive Vice President and Chief Administrative Officer of AEP

Executive Summary

2016 Business Performance Highlights.    During 2016, AEP continued its focus on becoming the next premier regulated energy company. AEP executed on its strategy of investing in core regulated businesses to improve service to customers, while demonstrating continuous improvement in its operations. AEP’s Transmission Holding Company business thrived and contributed 54 cents per share to 2016 operating earnings, an increase of 38 percent over 2015. In 2016, AEP also took steps to significantly reduce earnings volatility by reducing exposure to non-regulated businesses. AEP announced the sale of four of our competitive power plants, which was completed in January 2017. This should help AEP produce more consistent earnings by removing the volatility associated with those competitive generation plants and their exposure to the capacity and energy markets. In October 2016, AEP increased its quarterly dividend by 5.4 percent, the seventh consecutive yearly increase.

2016 Incentive Compensation Highlights.    With respect to 2016 annual incentive compensation, the HR Committee:

• Increased the target performance goal for annual incentive compensation by $0.25 per share, a 7.1 percent increase over AEP’s 2015 target and $0.05 above the mid-point of our public operating earnings guidance at the time the HR Committee set the goal.

• Increased the performance needed for a maximum payout from $0.15 to $0.20 per share above the target level, which increased the maximum payout performance level 8.2 percent over the comparable 2015 level.

• Established threshold (33.3 percent of target payout), target and maximum (200 percent of target payout) operating earnings per share performance levels for 2016 annual incentive compensation at $3.65, $3.75 and $3.95 per share, respectively.

AEP’s 2016 operating earnings per share, together with AEP’s performance on strategic measures and safety, produced a score of 170.5 percent of target.

58

With respect to the 2014-2016 performance unit grant, the HR Committee certified the following results and pay outcomes:

• Cumulative operating earnings per share score was 200 percent of target.

• Relative total shareholder return (TSR) placed AEP at the 58th percentile of the S&P 500 Electric Utilities Industry Index, which resulted in a 127.7 percent of a target score.

• These combined equally weighted scores resulted in a payout of 163.9 percent of target for this performance period.

2016 Executive Compensation Changes.    In 2016, the HR Committee made the following key changes in our executive compensation program:

• Increased the CEO’s stock ownership target from five times to six times his base salary.

• Increased the minimum vesting for stock options and stock appreciation rights (SARs) to pro-rata vesting over a period of at least three years, with a carve-out for up to five percent of the shares available under AEP’s Long-term incentive Plan (LTIP).

• Added a “Hold Until Met” requirement for stock options and SARs, which requires AEP executives to hold the net shares they realize through stock option and SAR exercises until such time as they have met their stock ownership requirement.

• Amended AEP’s Recoupment Policy to expand the policy to apply to restatements or corrections in situations where the covered employee is not culpable, and changed the covered employee group to generally include officers who are Senior Vice Presidents and higher.

Other Executive Compensation Changes.    In February 2017, the HR Committee approved another change to LTIP awards to executive officers. Starting with the LTIP grants in 2017, the performance units and the RSUs will both settle in AEP shares, rather than cash.

Compensation Governance Best Practices.    Below is a summary of our executive compensation practices, which we believe align with best practices:

• Significant stock ownership requirements for executive officers, which included a recently increased stock ownership requirement for the CEO of six times base salary;

• A substantial portion of the compensation for executive officers is tied to annual and long-term performance;

• A recoupment policy that allows AEP to claw back incentive compensation;

• An insider trading policy that prohibits our executives and directors from hedging their AEP stock holdings and from pledging AEP stock;

• Long-term incentive awards with double trigger vesting that results in accelerated vesting of these awards only if there is a change in control followed by an involuntary or constructive separation from service;

• No reimbursement or tax gross-up for excise taxes triggered under change in control agreements;

• No company paid country club memberships for executive officers;

• Generally prohibit personal use of AEP provided aircraft, to the extent that such use has an incremental cost to AEP; and

• No tax gross-ups, other than for relocations.

59

Results of 2016 Advisory Vote to Approve Executive Compensation

At AEP’s annual meeting of shareholders held in April 2016, approximately 94 percent of the votes cast on AEP’s say-on-pay proposal voted in favor of the proposal. After consideration of this vote, the HR Committee continued to apply the same principles and philosophy it has used in previous years in determining executive compensation. The HR Committee will continue to consider the outcome of AEP’s say-on-pay vote and other sources of stakeholder feedback when establishing compensation programs and making compensation decisions for the named executive officers.

Overview

The HR Committee oversees and determines AEP’s executive compensation (other than that of the CEO). The HR Committee makes recommendations to the independent members of the board of directors about the compensation of the CEO, and the independent board members determine the CEO’s compensation.

AEP’s executive compensation program is designed to:

• Attract, retain, motivate and reward an outstanding leadership team with market competitive compensation and benefits to achieve both excellent team and individual performance;

• Reflect AEP’s financial and operational size and the complexity of its multi-state operations;

• Provide a substantial portion of executive officers’ total compensation opportunity in the form of performance based incentive compensation;

• Align the interests of AEP’s named executive officers with those of AEP’s shareholders by providing a majority of the total compensation opportunity for executive officers in the form of stock-based compensation with a value that is linked to the total return on AEP’s common stock and by maintaining significant stock ownership requirements for executives;

• Support the implementation of AEP’s business strategy by tying annual incentive awards to operating earnings per share and the achievement of specific strategic and safety objectives; and

• Promote the stability of the management team by creating strong retention incentives with multi-year vesting schedules for long-term incentive compensation.

Overall, AEP’s executive compensation program generally targets each named executive officer’s total direct compensation opportunity (base salary, annual incentive opportunity and long-term incentive opportunity) at the median of AEP’s Compensation Peer Group, as described under “Compensation Peer Group”. The HR Committee’s independent compensation consultant, Meridian Compensation Partners, LLC (Meridian), participates in HR Committee meetings, assists the HR Committee in developing the compensation program and regularly meets with the HR Committee in executive session without management present.

Program Design

The program for executive officers includes base salary, annual incentive compensation, long-term incentive compensation and a comprehensive benefits program. AEP provides a balance of annual and long-term incentive compensation that is consistent with the compensation mix provided by AEP’s Compensation Peer Group. For AEP’s annual incentive compensation, the HR Committee balances meeting AEP’s operating earnings per share target with strategic and safety objectives. For 2016, operating earnings per share had a 75 percent weight for annual incentive compensation and the remaining 25 percent weight was tied to strategic and safety goals.

For 2016, 75 percent of AEP’s long-term incentive compensation was awarded in the form of performance units with three-year performance measures tied to (1) AEP’s total shareholder return as a percentile of the companies in the S&P 500 Electric Utilities Industry Index and (2) AEP’s three-year cumulative operating earnings per share

60

relative to a Board-approved target. The performance units are subject to a three-year vesting period. The remaining 25 percent of AEP’s long-term incentive compensation was awarded as restricted stock units (RSUs) that vest over 40 months in three approximately equal installments on the May 1st following the first, second and third anniversaries of the grant date.

The HR Committee annually reviews the mix of the three elements of total direct compensation: base salary, annual incentive compensation and long-term incentive compensation. In 2016, 69 percent of the target total direct compensation for the CEO was performance-based (target annual incentive compensation and grant date value of performance units). An additional 17 percent of the CEO’s target total direct compensation was provided in the form of time-vesting RSUs (grant date value) which are tied to AEP’s stock price.

Compensation Peer Group

The HR Committee, supported by its independent compensation consultant, Meridian Compensation Partners, LLC (“Meridian”), annually reviews AEP’s executive compensation relative to a peer group of companies that represent the talent markets with which AEP must compete to attract and retain executives. The companies included in the Compensation Peer Group were chosen from electric utility companies that were comparable in size to AEP in terms of revenues and market capitalization. AEP’s Compensation Peer Group for 2016, which was unchanged from 2015, consisted of the 17 utility companies shown below.

AES Corporation Consolidated Edison Inc. DTE Energy Company Edison International Exelon Corporation NextEra Energy, Inc. PPL Corporation Sempra Energy Centerpoint Energy, Inc. Dominion Resources, Inc. Duke Energy Corporation Entergy Corporation FirstEnergy Corp. PG&E Corporation Public Service Enterprise Group Inc. Southern Company Xcel Energy Inc.

The table below shows that, at the time the Compensation Peer Group data was collected in July 2015, AEP’s revenue and market capitalization were above the 50^th percentile, and closer to the 75^th percentile, of the Compensation Peer Group.

2016 Compensation Peer Group

	Revenue(1) ($ million)	Market Cap(1) ($ million)
Compensation Peer Group
25th Percentile	$11,686	$14,441
50th Percentile	$12,919	$21,079
75th Percentile	$17,090	$27,649
AEP	$17,020	$27,751

(1) The HR Committee selected the 2016 Compensation Peer Group in September 2015 based on Fiscal Year-End 2014 revenue, and market capitalization as of July 31, 2015.

Meridian annually provides the HR Committee with an executive compensation study covering each named executive officer position and other executive positions based on survey information derived from the Compensation Peer Group. The Meridian study benchmarked each of our named executive officer’s total direct compensation (and each component of compensation) against the median market value of total direct compensation paid by the Compensation Peer Group to officers serving in similar capacities. The market values were adjusted for AEP’s relative size based on AEP’s revenue or the executive’s revenue responsibility using regression analysis for all positions for which data was available. The HR Committee considers percentiles other than the median and may select any percentile as a benchmark if, in its judgment, such other benchmarks provide a better comparison based on the specific scope of the job being matched or other criteria.

61

If a named executive officer’s total direct compensation opportunity is above or below a +/- 15 percent range around the market median, the HR Committee may adjust elements of the named executive officer’s compensation over time to bring the executive’s total compensation opportunity into the target range.

Executive Compensation Program Detail

Summary of Executive Compensation Components.    The following table summarizes the major components of AEP’s executive compensation program.

Component			Purpose			Key Attributes
Base Salary	Ÿ	To provide a market-competitive and consistent minimum level of compensation that is paid throughout the year.		Ÿ	A 3 percent executive merit budget and an additional 0.5% for other types of salary adjustments was approved by the HR Committee for 2016.
				Ÿ	Merit and other salary increases for executives are awarded by the HR Committee based on a variety of factors.
Annual Incentive Compensation	Ÿ	To focus executive officers on achieving annual earnings and other performance objectives that are critical to AEP’s success, which for 2016 included:		Ÿ	Annual incentive targets are established by the HR Committee based on compensation and performance information provided by the HR Committee’s independent compensation consultant as well as objectives put forth by AEP management and endorsed by the HR Committee.
		Ÿ	Operating Earnings (75 percent weight)
		Ÿ	Safety (10 percent weight), and		Ÿ	Actual awards for employees as a group are capped at 200 percent of target, while awards for individual employees are capped at 250 percent of their target.
		Ÿ	Strategic Initiatives (15 percent weight).
	Ÿ	To communicate and align executives’ and employees’ efforts with AEP’s performance objectives.		Ÿ	Operating earnings per share was chosen as the primary performance measure for 2016.
				Ÿ	The CEO’s award is determined by the independent members of the Board of Directors, and the other named executive officer awards are determined and approved by the HR Committee and based on:
					Ÿ	Achievement against performance objectives, and
					Ÿ	A subjective evaluation of each named executive officer’s individual performance for the year.
Long-Term Incentive Compensation	Ÿ	To motivate AEP management to maximize shareholder value by linking a substantial portion of their potential compensation directly to longer-term shareholder returns.		Ÿ	For 2016, the HR Committee provided long-term incentive awards in the form of three-year performance units for 75 percent of the grant value and restricted stock units (RSUs) for 25 percent of the grant value.
	Ÿ	To help ensure that AEP management remains focused on longer-term results, which the HR Committee considers essential given the large amount of long-term investment in physical assets required in our business.		Ÿ	Long-term incentive award opportunities for named executive officers are based on market data, as reflected in either position based or salary grade-based award guidelines, and subjective consideration of each named executive officer’s potential contribution to shareholder value during the performance period.
	Ÿ	To reduce executive turnover and maintain management consistency.		Ÿ	For the 2016-2018 performance unit awards, the HR Committee established the following equally weighted performance measures:

62

Ÿ	Three-year cumulative operating earnings per share relative to a target approved by the HR Committee, and
Ÿ	Three-year total shareholder return relative to the S&P 500 Electric Utilities Industry Index.

Base Salary.    The HR Committee determines merit and other salary increases for AEP’s named executive officers based on the following factors:

• The current scope and responsibilities of the position;

• AEP’s merit and other increase budgets;

• Sustained individual performance as assessed by each executive’s direct manager;

• The market competitiveness of the executive’s salary, total cash compensation and total compensation;

• Internal comparisons;

• The experience and future potential of each executive; and

• Reporting relationships.

The HR Committee approved merit increases for 2016 base salaries in the 2-4 percent range for our named executive officers.

Annual Incentive Compensation.

Annual Incentive Target Opportunity.    Annual incentive compensation focuses executive officers on achieving annual earnings objectives and other performance objectives that are critical to AEP’s success. The HR Committee, in consultation with Meridian and Company management, establishes the annual incentive target opportunities for each executive officer position primarily based on market competitive compensation for the executive’s position as shown in Meridian’s annual executive compensation study. For 2016, the HR Committee established the following annual incentive target opportunities for the named executive officers:

• 125 percent of base earnings for the CEO (Mr. Akins);

• 80 percent of base earnings for the CFO (Mr. Tierney);

• 80 percent of base earnings for the Vice Chairman (Mr. Powers);

• 70 percent of base earnings for the EVP and General Counsel (Mr. Feinberg); and

• 70 percent of base earnings for the EVP-Transmission (Ms. Barton).

• 70 percent of base earnings for the EVP-Chief Administrative Officer (Ms. Hillebrand).

Annual Performance Objectives.    For 2016, the HR Committee approved the following performance measures for the reasons indicated.

Operating Earnings per Share.    The HR Committee chose operating earnings per share because it largely reflects management’s performance in operating AEP. It is also strongly correlated with shareholder returns and is the primary measure by which AEP communicates its actual and expected future financial performance to the investment community and employees. The operating earnings per share measure is also well understood by both our shareholders

63

and employees. Management and the HR Committee believe that operating earnings per share growth is the primary means for AEP to create long-term shareholder value.

Safety.    With safety as an AEP core value, maintaining the safety of AEP employees and the general public is always a primary consideration. Accordingly, safety measures comprised 10 percent of the 2016 scorecard. 7.5 percent was based on the improvement in AEP’s DART Rate compared to its three-year average DART rate. DART is an acronym for Days Away, Restricted or Job Transfer and is an industry accepted measure that focuses on more serious injuries. The remaining 2.5 percent was a fatality measure. The fatality measure would pay out at target if there was not a fatal work-related employee incident during the year.

Strategic Initiatives.    Fifteen percent of the scorecard was tied to strategic initiatives, including six percent for Business Transformation initiatives, five percent for Customer Experience initiatives and four percent for Culture and Employee Engagement initiatives.

The six percent for Business Transformation initiatives consisted of three measures. The first related to the completion of a strategic business assessment of certain competitive generation units. The second was based on the volume of start-up projects captured by AEP OnSite Partners and AEP Renewables, which are AEP’s competitive subsidiaries focused on building renewable power projects. The last measure was based on expanding AEP’s transmission business.

The five percent for Customer Experience included three measures. The first category measures the reliability of our wires assets: SAIDI (System Average Incident Duration Index), which is a standard measure in our industry. The second category measured improvement in AEP’s rankings in the J.D. Power and Associates Customer Satisfaction Survey. The last measure was for distribution network remediation, and was based on the number of circuit feet replaced.

The four percent for Culture & Employee Engagement consisted of four measures. The Power Up & Lead category measured the number of employees that participated in a cultural education program during the year. The Gallup Survey measured improvements in the overall average score over AEP’s prior year survey. The Diversity category measured improvement in AEP’s female and minority representation rates for each EEO group. The last measure was based on the number of Lean Management System deployments completed and initiated during the year, as well as the number of Introduction to Lean Management Systems events completed during the year.

Performance Score for Annual Incentive Plan.    In 2016, AEP had operating earnings per share of $3.94, which exceeded the upper end of our original operating earnings guidance for the year of $3.60-$3.80 per share. This earnings result, together with AEP’s performance on the measures discussed above (safety and strategic initiatives), produced a result of 170.5 percent of the target award opportunity for executive officers.

For 2016, GAAP earnings per share reported in AEP’s financial statements were $1.24. This is $2.70 per share lower than operating earnings, primarily due to the impairment of certain unregulated merchant generation assets.

64

Balanced Scorecard.    For 2016, the HR Committee approved a balanced scorecard which tied annual incentive awards to AEP’s operating earnings, safety and strategic objectives for the year. The HR Committee used this balanced scorecard because it mitigates the risk that executives will focus on one or a few objectives, such as short-term financial performance, to the detriment of other objectives. The chart below shows the weightings for each performance measure, the threshold, target and maximum performance goals, 2016 actual results and related weighted scores.

	Weight	Threshold	Target	Maximum	Actual Performance Result	Actual Award Score (as a percent of target opportunity)	Weighted Score
Operating Earnings Per Share (75%)	75%	$3.65	$3.75	$3.95	$3.941	195.5%	1.466
Safety (10%)
DART (Days Away, Restricted or Job Transfer) Rate, an industry measure focused on serious injuries	7.5%	0 percent Improvement	10 percent Improvement	20 percent Improvement	0 percent	0.0%	0.000
Fatality Measure (the number of fatal work related employee incidents)	2.5%	One or more	None	None for more than one year	Two employee fatalities	0.0%	0.000
Strategic Initiatives (15%)
Business Transformation Measures (6%)
Strategic Business Assessment of Certain Competitive Generation Plants	2%	Incomplete	Board approves a sale contract or recommendation to retain these plants	Sale contract and Board approves plan for use of proceeds	A sale contract was executed, and the Board approved the plan for use of proceeds	200.0%	0.040
Volume of AEP OnSite Partners and AEP Renewables Start-up Projects	2%	$0 million	$20 million	$50 million	$299 million	200.0%	0.040
Volume of Transmission Investment Opportunities	2%	$100 million	$200 million	$300 million	$485 million	200.0%	0.040
Customer Experience Measures (5%)
Wires Reliability- measure based on a customer weighted average of SAIDI (System Average Incident Duration Index) Performance Scores of AEP operating companies	2%	Generally 80% percent of target	Regulatory targets or a glide path to the regional peer group average	120 percent of target	114.0% Average Operating Company Score	114.0%	0.023
Customer Satisfaction - measure based on a weighted average of J.D. Power Residential Customer Satisfaction Index scores for AEP operating companies	2%	No improvement	Peer Group improvement rate	Glide path improvement to the Regional Peer Group Average	200.0% Average Operating Company Score	200.0%	0.040
Network remediation	1%	286,931 circuit feet replaced	382,575 circuit feet replaced	478,218 circuit feet replaced	>527,000 circuit feet replaced	200.0%	0.020
Culture and Employee Engagement Measures (4%)
Employee Engagement - based on improvement in average overall score of a survey of AEP employees	1%	0.07 improvement	0.10 improvement	0.20 improvement	0.08 Improvement	33.3%	0.003
Employee Diversity - measure based on increased representation of women and minorities in all EEO categories	1%	Higher of 80 percent target or 0 percent improvement	Higher of 100 percent target or 0 percent improvement	Higher of 120 percent of target or 0 percent improvement	Female Representation Score: 65.6% Minority Representation Score: 82.3%	74.0%	0.007
AEP Culture Development - measure based on the number of employees that participated in an employee development program	1%	3,900 participants	5,200 participants	6,500 participants	5,240 participants	103.1%	0.010
Lean Management Sustainability (number of pilot areas and non-pilot areas completed)	1%	1 pilot & 30 non-pilots	3 pilots & 40 non-pilots	3 pilots & 50 non-pilots plus 3 additional pilots initiated	3 pilots and 48 non-pilots completed plus 1 additional pilot initiated	156.7%	0.016
Total Score							1.705

65

2016 Individual Award Calculations.    Based on the results under the Balanced Scorecard, the HR Committee approved a weighted score of 170.5 percent. The HR Committee then subjectively evaluated the individual performance of each named executive officer to determine the actual award payouts. The HR Committee considered the progress made during 2016 focusing AEP on its core regulated businesses for Mr. Akins and the successful performance of the transmission business in 2016 for Ms. Barton.

Name	2016 Base Earnings*		Annual Incentive Target %		Weighted Score Under Performance Score Card		Calculated Annual Incentive Opportunity	2016 Actual Payouts
Mr. Akins	$1,318,442	x	125%	x	170.5%	=	$2,809,930	$3,000,000
Mr. Tierney	$727,257	x	80%	x	170.5%	=	$991,979	$990,000
Mr. Powers	$720,499	x	80%	x	170.5%	=	$982,761	$980,000
Mr. Feinberg	$612,175	x	70%	x	170.5%	=	$730,631	$730,000
Ms. Barton	$529,473	x	70%	x	170.5%	=	$631,926	$650,000
Ms. Hillebrand	$559,427	x	70%	x	170.5%	=	$667,676	$670,000

*    Based on salary paid in 2016, which is slightly different than the salary earned for 2016 shown in the Summary Compensation Table.

The independent members of the Board approved the 2016 annual incentive award for the CEO. The HR Committee approved the 2016 annual incentive awards for the other named executive officers.

Long-Term Incentive Compensation.    The HR Committee grants long-term incentive compensation to executive officers on an annual award cycle. AEP annually reviews the mix of long-term incentive compensation provided to its executives. For the 2016 award cycle, 75 percent of the grant date value of long-term incentives was awarded as three-year performance units and 25 percent of the grant date value was awarded as time-vesting restricted stock units (RSUs). The HR Committee increased the blend of performance units to RSUs in the long-term incentive mix from 70/30 to 75/25 for 2016 to increase the portion of the long-term incentive award that is performance-based.

The HR Committee establishes target long-term incentive award opportunities for each named executive officer based primarily on a market competitive long-term and total compensation analysis provided by Meridian for executives serving in similar positions in AEP’s Compensation Peer Group.

The independent members of the Board approved the 2016 long-term incentive award for the CEO. The HR Committee approved the 2016 long-term incentive awards for the other named executive officers.

2016 Long-Term Incentive Awards

Name	Number of Performance Units Granted (at Target)	Number of RSUs Granted	Total Units Granted	Total Grant Date Fair Value
Mr. Akins	80,306	26,769	107,075	$6,720,027
Mr. Tierney	22,646	7,549	30,195	$1,895,038
Mr. Powers	22,646	7,549	30,195	$1,895,038
Mr. Feinberg	13,467	4,489	17,956	$1,126,919
Ms. Barton	11,987	3,995	15,982	$1,003,030
Ms. Hillebrand	10,787	3,596	14,383	$902,677

Differences in grant date fair value between the awards for individual named executive officers primarily reflect differences in market median compensation for the executives shown in the annual executive compensation study conducted by Meridian.

In February 2017, Mr. Powers announced his retirement from AEP in August 2017. Mr. Powers remained Vice Chairman of AEP until his retirement. Mr. Powers did not receive a 2017 long-term incentive (LTIP) award because

66

of his announced retirement, but AEP provided a cash payment to Mr. Powers instead. In connection with Mr. Powers’ retirement, AEP and Mr. Powers entered into a separation and release of all claims agreement, containing among other things, certain non-solicitation, confidentiality and cooperation agreements. This agreement provided a cash payment of $700,000that provided him (i) an amount to make up for his not receiving a 2017 LTIP award (if it had been granted, a portion of his 2017 - 2019 performance units would have remained outstanding upon his August 2017 retirement), and (ii) a portion of the compensation Mr. Powers would have received if he had remained with AEP through a later retirement date.

Performance Units.    The HR Committee granted 75 percent of the aggregate grant date value of AEP’s 2016 long-term incentive awards as performance unit awards for the 2016 - 2018 performance period. Each performance unit has an economic value equivalent to a share of AEP common stock. AEP grants performance units at the beginning of each year with a three-year performance and vesting period. Vested performance units are paid in cash except to the extent they are voluntarily deferred or are needed to meet an executive’s stock ownership requirement, in which case the vested performance units are mandatorily deferred into AEP Career Shares. AEP Career Shares are not paid to participants until after their employment with AEP ends.

Dividends are reinvested in additional performance units that are subject to the same performance measures and vesting requirements as the underlying performance units on which they were granted. The total number of performance units held at the end of the performance period is multiplied by the equally weighted score for the two performance measures shown below to determine the number of performance units earned. Each unit is then paid out at the average closing price of AEP common stock for the last 20 trading days of the performance period or mandatorily deferred as Career Shares if needed to satisfy an executive officer’s stock ownership requirement. The maximum score for each performance measure is 200 percent. For the 2016-2018 performance units, the cumulative operating earnings per share target is $11.42.

Performance Measures for 2016 - 2018 Performance Units

Performance Measure	Weight	Threshold Performance	Target Performance	Maximum Payout Performance
3-Year Cumulative Operating Earnings Per Share	50%	$10.621 (30% payout)	$11.42 (100% payout)	$12.219 (200% payout)
3-Year Total Shareholder Return vs. S&P 500 Electric Utilities Industry Index	50%	20th Percentile (0% payout)	50th Percentile (100% payout)	80th Percentile (200% payout)

The HR Committee selected a cumulative measure of operating earnings to ensure that earnings for all three years contribute equally to the award calculation. The HR Committee also selected a total shareholder return measure for these awards to provide an external performance comparison that reflects the effectiveness of management’s strategic decisions and actions over the three-year performance period relative to other large electric utilities.

Restricted Stock Units.    Each RSU has an economic value equivalent to one share of AEP common stock. The HR Committee granted 25 percent of the aggregate grant date value of AEP’s 2016 long-term incentive awards as RSUs. These RSUs vest over a forty month period, subject to the executive’s continued employment, in three approximately equal installments on May 1, 2017, May 1, 2018 and May 1, 2019. Dividends are reinvested in additional RSUs that are subject to the same vesting requirements applicable to the underlying RSUs on which they were granted. Upon vesting, these RSUs pay out in cash to executive officers at the average closing price of AEP common stock for the last 20 trading days of the vesting period.

Stock Ownership Requirements.    The HR Committee believes that linking a significant portion of executives’ financial rewards to AEP’s success, as reflected by the value of AEP stock, gives executives a stake similar to that of AEP’s shareholders and encourages long-term management strategies that benefit shareholders. Therefore, the HR Committee requires certain officers (51 individuals as of January 1, 2017), including the named executive officers, to accumulate and hold a specific amount of AEP common stock or stock equivalents. The HR Committee annually reviews the stock ownership level for each executive officer and periodically adjusts these levels. Each named executive officer met his or her stock ownership requirement as of March 1, 2017.

67

During 2016, the HR Committee increased the CEO’s stock ownership requirement from five times to six times his base salary. The other named executive officers’ targets are three times their respective base salaries.

Equity Retention (Holding Period).    Until an executive officer meets his or her stock ownership requirement, performance units awarded under the Long-term Incentive Plan (“LTIP”) are mandatorily deferred into AEP Career Shares to the extent necessary to meet their stock ownership requirement. If an executive has not met his or her stock ownership requirement within five years of the date it became effective or subsequently falls below it, the HR Committee may require the executive to defer a portion of his or her annual incentive compensation award into AEP Career Shares.

In 2016, the LTIP was amended to add a “Hold Until Met” requirement for stock options and SARs, which requires AEP executives to hold the net shares they realize through stock option and SAR exercises until such time as they have met their stock ownership requirement. However, no stock options or SARs were granted or outstanding during 2016.

Benefits.    AEP generally provides the same health and welfare benefits to named executive officers as it provides to other employees. AEP also provides the named executive officers with either four or five weeks of paid vacation, depending on their length of service and position.

AEP’s named executive officers participate in the same tax-qualified defined benefit pension plan and defined contribution savings plan as other eligible employees. AEP’s named executive officers also participate in the AEP’s non-qualified retirement benefit plans, which largely provide “supplemental benefits” that would otherwise be offered through the tax-qualified plans except for the limits imposed by the Internal Revenue Code on those tax-qualified plans. This allows eligible employees to accumulate replacement income for their retirement based on the same benefit formulas as the tax qualified plans but without the limitations that are imposed by the Internal Revenue Code on the tax-qualified plans.

The HR Committee recognizes that the non-qualified plans result in the deferral of the AEP’s income tax deduction related to these benefits until such benefits are paid, but the HR Committee believes that executives generally should be entitled to the same retirement benefits, as a percentage of their eligible pay, as AEP’s other employees and that these benefits are prevalent among similar companies. The HR Committee also provides these benefits as part of a market competitive total rewards package.

AEP limits both the amount and types of compensation that are included in the qualified and non-qualified retirement plans because the HR Committee and AEP management believe that compensation over certain limits and certain types of compensation should not be further enhanced by including it in retirement benefit calculations. Therefore:

• Long-term incentive compensation is not included in the calculations that determine retirement and other benefits under AEP’s benefit plans,

• The cash balance formula of AEP’s non-qualified pension plan (the “AEP Supplemental Benefit Plan”) limits eligible compensation to the greater of $1 million or twice the participant’s base salary, and

• Eligible compensation is also limited to $2 million under the non-qualified Supplemental Retirement Savings Plan.

AEP provides group term life insurance benefits to all employees, including the named executive officers, in the amount of two times their base salary.

For executives whom AEP asks to relocate, it is AEP’s practice to offer relocation assistance to offset their moving expenses. This policy better enables AEP to obtain high quality new hires and to relocate internal job candidates.

Perquisites.    The HR Committee annually reviews the perquisites provided by AEP. In 2016, AEP provided independent financial counseling and tax preparation services to assist executives with financial planning and tax filings. Income is imputed to executives and taxes are withheld for these services.

68

The HR Committee is sensitive to concerns regarding the expense of corporate aircraft and the public perception regarding personal use of such aircraft. Accordingly, the HR Committee generally prohibits personal use of corporate aircraft that has an incremental cost to AEP. AEP allows personal travel on business trips using the corporate aircraft if there is no incremental cost to AEP. Income is imputed and taxes are withheld on the value of personal travel on corporate aircraft in accordance with IRS guidelines.

Other Compensation Information

Recoupment of Incentive Compensation.

In 2016, the Board amended the AEP’s Policy on Recouping Incentive Compensation, commonly referred to as a “clawback” policy. The policy was amended to provide that our executive officers and certain other senior executives would be subject to a ‘no fault’ “clawback”. The Board may recover incentive compensation whether or not the executive’s actions involve misconduct. The Board believes, subject to the exercise of its discretion based on the facts and circumstances of a particular case, that incentive compensation should be reimbursed to AEP if, in the Board’s determination:

• Such incentive compensation was received by an executive where the payment or the award was predicated upon the achievement of financial or other results that were subsequently materially restated or corrected, and

• Such incentive compensation would have been materially lower had the achievement been calculated on such restated or corrected financial or other results.

The Board adopted the initial clawback policy in February 2007, and the HR Committee has directed AEP to design and administer all of its incentive compensation programs in a manner that provides for AEP’s ability to obtain such reimbursement. AEP will seek reimbursement, if and to the extent that, in the Board’s view, such reimbursement is warranted by the facts and circumstances of the particular case or if the applicable legal requirements impose more stringent requirements on AEP to obtain reimbursement of such compensation. AEP may also retain any deferred compensation previously credited to an executive if, when, and to the extent that it otherwise would become payable. This right to reimbursement is in addition to, and not in substitution for, any and all other rights AEP might have to pursue reimbursement or such other remedies against an executive for misconduct in the course of employment by AEP or otherwise based on applicable legal considerations.

Role of the CEO and Compensation Consultant in Determining Executive Compensation.    The HR Committee invites the CEO and all directors to attend HR Committee meetings. The HR Committee regularly holds executive sessions without management present. The Chairman of the Board and the Chair of the HR Committee have the authority to call meetings of the HR Committee.

The CEO has assigned AEP’s Executive Vice President & Chief Administrative Officer and AEP’s Director - Compensation and Executive Benefits to support the HR Committee. These individuals work closely with the HR Committee Chairman, the CEO and Meridian to research and develop requested information, prepare meeting materials, implement the HR Committee’s actions and administer AEP’s executive compensation and benefit programs consistent with the objectives established by the HR Committee. Meetings are held with the CEO, the HR Committee Chairman and Meridian prior to HR Committee meetings to review and finalize the agenda and meeting materials.

The CEO regularly discusses his strategic vision and direction for AEP during HR Committee meetings with Meridian in attendance. Likewise, Meridian regularly discusses compensation strategy alternatives, in light of the CEO’s strategic vision and direction, during HR Committee meetings with the CEO in attendance. The HR Committee believes that this open dialogue and exchange of ideas is important to the development and implementation of a successful executive compensation strategy.

The CEO discusses the individual performance of the named executive officers with the HR Committee and recommends their compensation to the HR Committee. The CEO also has substantial input into salary budgets and

69

changes to incentive targets. The CEO also has substantial input into the development of employment offers for outside candidates for executive positions, although the HR Committee must approve all employment offers for executive officers.

Change In Control Agreements.    The HR Committee provides Change In Control agreements to specified executives, including all the named executive officers, to help align the interests of these executives with those of AEP’s shareholders by mitigating the financial impact that would occur to them if their employment was terminated as a result of a change in control. The HR Committee also considers change in control agreements as an important tool for attracting and retaining executives for some positions. The HR Committee limits participation to those executives whose full support and sustained contributions would be needed during a lengthy and complex corporate transaction.

While the HR Committee believes these agreements are consistent with the practices of its peer companies, the most important reason for these agreements is to protect AEP and the interests of shareholders in the event of an anticipated or actual change in control. During such transitions, retaining and continuing to motivate AEP’s key executives would be critical to protecting shareholder value. In a change of control situation, outside competitors are more likely to try to recruit top performers away from AEP, and our executive officers may consider other opportunities when faced with uncertainty about retaining their positions. Therefore, the HR Committee uses these agreements to provide security and protection to our officers in such circumstances for the long-term benefit of AEP and its shareholders.

The Board has adopted a policy that requires shareholder approval of future executive severance agreements that provide benefits generally exceeding 2.99 times the sum of the named executive officer’s salary plus annual incentive compensation. In consultation with Meridian, the HR Committee periodically reviews change in control agreement practices of companies in our Compensation Peer Group. The HR Committee has found that change in control agreements are common among these companies, and that 2.99 or 3 multiples are the most common for named executive officers. Therefore, the HR Committee approved change in control multiples of 2.99 times base salary and annual incentive compensation for each of the named executive officers. Most of the other executives covered by change in control agreements have a lesser multiple of 2.0 times base salary and annual incentive compensation. All of the agreements have a “double trigger,” which means the severance payments and benefits would be provided only upon a change in control accompanied by an involuntary termination or constructive termination within two years after the change in control.

None of AEP’s Change In Control agreements provide a tax gross-up for excise taxes.

Long-term incentive compensation may also vest in the event of a change in control. In the event an executive’s employment is terminated within one year after a change in control under qualifying conditions, such as by AEP without cause or by the executive for good reason, then all of the executive’s outstanding performance units will vest and be paid at the target performance score. All outstanding RSU awards have a double trigger change in control provision.

Other compensation and benefits provided to executive officers in the event their employment is terminated as a result of a change in control are consistent with that provided in the event an executive’s employment is terminated due to a consolidation, restructuring or downsizing as described below.

Other Employment Separations.

AEP has an Executive Severance Plan that provides severance benefits to selected officers of AEP, including the named executive officers, who agree to its terms, including confidentiality, non-solicitation and non-disparagement obligations. Executives remain eligible for benefits under the general severance plan described below; however, any benefits provided under the Executive Severance Plan will be reduced by any amounts provided under the general severance plan. Benefits for our named executive officers under the Executive Severance Plan (which would be triggered by a good reason resignation or an involuntary termination) include pay continuation of two times their base salary and target annual incentive award payable over two years, and are conditioned on the executive officer’s release of claims against AEP and agreement not to compete with AEP for two years.

AEP also maintains a broad-based severance plan that provides two weeks of base pay per year of service to all employees, including named executive officers, if their employment is terminated due to a consolidation,

70

restructuring or downsizing, subject to the employee’s agreement to waive claims against AEP. In addition, our severance benefits for all employees include outplacement services and access to health benefits at active employee rates for up to 18 months (and at Company-subsidized retiree rates thereafter until age 65 for employees who are at least age 50 with 10 years of service at the time of their employment termination).

Named executive officers and other employees remain eligible for an annual incentive award based on their eligible pay for the year reflecting the portion of the year worked, if they separate from service prior to year-end due to their retirement (on or after age 55 with at least five years of service, except employees who retire as part of a voluntary or involuntary severance program). In the event of a participant’s death, this amount is paid to their estate.

A prorated portion of outstanding performance units vest if a participant retires, which is defined as a termination, other than for cause, after the executive reaches age 55 with five years of service or if a participant is severed. A prorated portion of outstanding performance units would also vest to a participant’s heirs in the event of the participant’s death. The pro-rated performance units are not payable until the end of the performance period and remain subject to all the performance objectives.

In 2016, executive officers were also entitled to 12 months of continued financial counseling service in the event they are severed from service as the result of a restructuring, consolidation or downsizing or they retire (after age 55 and 5 years of AEP service). In the event of their death, their spouse or the executor of their estate would be eligible for this benefit.

Insider Trading, Hedging and Pledging.    AEP’s insider trading policy prohibits directors and executive officers from hedging their AEP stock holdings through short sales and the use of options, warrants, puts and calls or similar instruments. The policy also prohibits directors and executive officers from pledging AEP stock as collateral for any loan.

Tax Considerations.    Section 162(m) of the Internal Revenue Code (Section 162 (m)) limits AEP’s ability to deduct compensation in excess of $1,000,000 paid in any year to AEP’s CEO or any of the next three highest compensated named executive officers other than the CFO (the “162m Officers”). The HR Committee considers the limits imposed by Section 162(m) when designing compensation and benefit programs.

Performance units, which were granted under the shareholder approved Long-Term Incentive Plan, are consistent with the Section 162(m) requirements for tax deductibility by AEP as performance-based compensation. AEP’s Shareholders approved the Long-Term Incentive Plan in 2015; therefore, payments for performance units are potentially tax deductible for AEP.

AEP’s RSUs are not considered to be performance-based under Section 162(m). Therefore, any amounts attributable to those RSUs are not tax deductible if and to the extent that such units cause the compensation of the covered named executive officer to exceed $1,000,000 for the year.

No assurance can be given that awards intended by the HR Committee to satisfy the requirements for qualified performance-based compensation under Section 162(m) will in fact do so. The HR Committee has and may continue to grant awards that may not constitute qualified performance-based compensation under Section 162(m) if the HR Committee determines that granting such awards is in the best interests of AEP.

71

Executive Compensation

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 ($)(2)	Non- Equity Incentive Plan Compen- sation ($)(3)	Change in Pension Value and Non- qualified Deferred Compen- sation Earnings ($)(4)	All Other Compen- sation ($)(5)	Total ($)
Nicholas K. Akins-	2016	1,325,077	0	6,720,027	3,000,000	323,949	103,687	11,472,740
Chairman of the Board and Chief Executive Officer	2015	1,279,900	0	6,719,981	3,150,000	199,027	103,658	11,452,566
	2014	1,240,754	0	6,720,019	2,950,000	359,787	102,960	11,373,520
Brian X. Tierney-	2016	730,800	0	1,895,038	990,000	131,575	95,026	3,842,439
Executive Vice President and Chief Financial Officer	2015	709,246	0	1,907,216	1,100,000	0	84,125	3,800,587
	2014	695,339	0	1,881,251	1,050,000	269,994	82,448	3,979,032
Robert P. Powers-	2016	723,773	0	1,895,038	980,000	335,960	93,931	4,028,702
Former Vice Chairman	2015	709,246	0	1,888,008	1,075,000	0	90,234	3,762,488
	2014	695,339	0	1,881,251	1,012,000	746,589	82,706	4,417,885
David M. Feinberg-	2016	615,358	0	1,126,919	730,000	85,179	75,435	2,632,891
Executive Vice President and General Counsel	2015	591,426	0	998,394	800,000	59,069	68,163	2,517,052
	2014	568,679	0	962,482	675,000	69,384	63,293	2,338,838
Lisa M. Barton-	2016	532,039	0	1,003,030	650,000	95,020	68,007	2,348,096
Executive Vice President- Transmission	2015	516,750	0	998,394	686,000	49,931	59,042	2,310,117
	2014	452,735	0	804,984	540,000	71,814	47,919	1,917,452
Lana L. Hillebrand-	2016	562,154	0	902,677	670,000	139,726	73,753	2,348,310
Executive Vice President and Chief Administrative Officer	2015	545,530	0	902,420	740,000	101,326	62,382	2,351,658
	2014	490,680	0	896,889	560,000	147,547	55,902	2,151,018

(1) Amounts in the salary column are composed of executive salaries earned for the year shown, which include 261 days of pay for 2016. This is one day more than the standard 260 calendar work days and holidays in a year.

(2) The amounts reported in this column reflect the aggregate grant date fair value, calculated in accordance with FASB ASC Topic 718, of performance units and RSUs granted under AEP’s Long-Term Incentive Plan. See Note 15 the Consolidated Financial Statements included in AEP’s Form 10-K for the year ended December 31, 2016 for a discussion of the relevant assumptions used in calculating these amounts. With respect to the performance units, the estimates of the grant date fair values determined in accordance with FASB ASC Topic 718 assumes the vesting of 100% of the performance units awarded. The value realized for the performance units, if any, will depend on AEP’s performance during a three-year performance and vesting period. The potential payout can range from 0 percent to 200 percent of the target number of performance units, plus any dividend equivalents. Therefore, the maximum amount payable for the 2016 performance units is equal to $10,080,010 for Mr. Akins; $2,842,526 for each of Messrs. Tierney and Powers; $1,690,378 for Mr. Feinberg, $1,504,608 for Ms. Barton, and $1,353,984 for Ms. Hillebrand; and the maximum amount payable for the 2015 performance units is equal to $9,407,974 for Mr. Akins, $2,670,090 for Mr. Tierney, $2,643,716 for Mr. Powers, $1,397,704 for Mr. Feinberg, $1,397,704 for Ms. Barton, and $1,263,376 for Ms. Hillebrand. The RSUs vest over a forty month period.

(3) The amounts shown in this column are annual incentive compensation paid under the Annual Incentive Compensation Plan for 2016 and the Senior Officer Incentive Plan for 2015 and 2014. 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 under this plan.

(4) 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 AEP’s financial statements. See Note 8 to the Consolidated Financial Statements included in AEP’s Form 10-K for the year ended December 31, 2016 for a discussion of the relevant assumptions. None of the named executive officer received preferential or above-market earnings on deferred compensation.

(5) Amounts shown in the All Other Compensation column for 2016 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	Robert P.    Powers	David M. Feinberg	Lisa M.  Barton	Lana L. Hillebrand
Retirement Savings Plan Match	$11,629	$11,925	$11,925	$11,925	$11,925	$11,925
Supplemental Retirement Savings Plan Match	$78,075	$70,302	$68,873	$51,623	$42,771	$46,549
Perquisites	$13,983	$12,799	$13,133	$11,887	$13,311	$15,279
Total	$103,687	$95,026	$93,931	$75,435	$68,007	$73,753

72

Perquisites provided in 2016 included: financial counseling and tax preparation services, and, for Mr. Akins, director’s accidental death insurance premium, and for Ms. Hillebrand, included personal use of Company aircraft. 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).

Grants of Plan-Based Awards for 2016

The following table provides information on plan-based awards granted in 2016 to each of our named executive officers.

Name	Grant Date	Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1)			Estimated Future Payouts Under Equity Incentive Plan Awards(3)			All Other Stock Awards: Number of Shares of Stock or Units (#)(6)	Grant Date Fair Value of Stock and Option Awards    ($)(7)
		Threshold    ($)	Target    ($)	Maximum    ($)(2)	Threshold    (#)(4)	Target    (#)	Maximum    (#)(5)
Nicholas K. Akins
2016 Annual Incentive Compensation Plan		0	1,648,053	4,120,133
2016 - 2018 Performance Units	2/23/16				12,046	80,306	160,612		5,040,005
Restricted Stock Units	2/23/16							26,769	1,680,022
Brian X. Tierney
2016 Annual Incentive Compensation Plan		0	581,806	1,454,515
2016 - 2018 Performance Units	2/23/16				3,397	22,646	45,292		1,421,263
Restricted Stock Units	2/23/16							7,549	473,775
Robert P. Powers
2016 Annual Incentive Compensation Plan		0	576,399	1,440,998
2016 - 2018 Performance Units	2/23/16				3,397	22,646	45,292		1,421,263
Restricted Stock Units	2/23/16							7,549	473,775
David M. Feinberg
2016 Annual Incentive Compensation Plan		0	428,523	1,071,308
2016 - 2018 Performance Units	2/23/16				2,020	13,467	26,934		845,189
Restricted Stock Units	2/23/16							4,489	281,730
Lisa M. Barton
2016 Annual Incentive Compensation Plan		0	370,631	926,578
2016 - 2018 Performance Units	2/23/16				1,798	11,987	23,974		752,304
Restricted Stock Units	2/23/16							3,995	250,726
Lana L. Hillebrand
2016 Annual Incentive Compensation Plan		0	391,599	978,998
2016 - 2018 Performance Units	2/23/16				1,618	10,787	21,574		676,992
Restricted Stock Units	2/23/16							3,596	225,685

(1) Represents potential payouts under the 2016 Annual Incentive Compensation Plan (ICP), which are based on base earnings paid during the year.

(2) The amounts shown in this column represent 250 percent of the target award for each of the named executive officers, which is maximum amount generally payable to any individual employee under the ICP.

(3) Represents performance units awarded under AEP’s Long-Term Incentive Plan for the 2016-2018 performance period. These awards generally vest at the end of the three year performance period based on our attainment of specified performance measures. For further information on these awards, see the description under 2016 Stock Award Grants below. The number of performance units does not include additional units that may accrue due to dividend credits.

(4) The amounts shown in the Threshold column represent 15% of the target award for each of the named executive officers because the Operating Earnings per Share measure has a 30% payout for threshold performance, the Total Shareholder Return measure has a 0% payout for threshold performance and these measures are equally weighted. However, the Operating Earnings per Share threshold does not guarantee a minimum payout because the score would be 0% of target if threshold performance is not achieved.

(5) The amounts shown in this column represent 200 percent of the target award for each of the named executive officers, which is the maximum overall score for the 2016-2018 performance units.

(6) Represents restricted stock units awarded under the Long-Term Incentive Plan. These awards generally vest in three equal installments on May 1, 2017, May 1, 2018 and May 1, 2019. The number of restricted stock units does not include additional units that may accrue due to dividend credits.

(7) Amount represents the grant date fair value of performance units and RSUs measured in accordance with FASB ASC Topic 718, utilizing the assumptions discussed in Note 15 to AEP’s consolidated financial statements for the fiscal year ended December 31, 2016, without taking into account estimated forfeitures. With respect to performance units, the grant date fair value assumes the target number of performance units granted will vest. The actual number of performance units earned will depend on AEP’s performance over the 2016 through 2018 period, which could vary from 0 percent to 200 percent of the target award plus dividend credits. The value of performance units earned will be equal to AEP’s average closing share price for the last 20 trading days of the performance period multiplied by the number of performance units earned.

73

Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table

2016 Stock Award Grants.    Effective February 23, 2016, the named executive officers were granted long-term incentive awards as part of AEP’s regular annual grant cycle. These awards were granted with double trigger change in control provisions that provide early vesting of awards in the event of a change in control and a covered separation from service. Of these awards, 75 percent were granted in the form of performance units for the 2016-2018 three-year performance period that generally vest, subject to the participant’s continued AEP employment, at the end of the performance period. Performance units are generally equivalent in value to shares of AEP common stock. Dividend equivalents are reinvested in additional performance units with the same vesting conditions as the underlying performance units.

The 2016-2018 performance units, including the dividend credits, are subject to two equally weighted performance measures for the three-year performance period, which are:

• Three-year total shareholder return relative to the S&P 500 Electric Utilities Industry Index, and

• Three-year cumulative operating earnings per share relative to a performance objective established by the HR Committee.

The scores for these performance measures determine the percentage of the performance units earned at the end of the performance period, which can range from zero percent to 200 percent. Generally, recipients must remain employed by AEP through the end of the vesting period to receive a payout.

The remaining 25 percent of AEP’s long-term incentive awards were granted in the form of RSUs that generally vest, subject to the executive officer’s continued employment, in three equal installments on May 1, 2017, May 1, 2018 and May 1, 2019. Generally, recipients must remain employed by AEP through the vesting date to receive a payout for the RSUs that vest on such date. Upon vesting, the RSUs pay out in cash to executive officers.

Employment Agreements.

Mr. Powers has an agreement with AEP, which credits him with 17 additional years of service under AEP’s Supplemental Benefit Plan. In 1997, AEP granted additional years of credited service to Mr. Powers when he joined AEP to offset pension benefits that he would have been able to earn from his prior employer due to his length of service at that company.

74

Outstanding Equity Awards at Fiscal Year-End for 2016

The following table provides information with respect to holdings of restricted stock units and performance units by the named executive officers at December 31, 2016. The named executive officers do not have any outstanding stock options.

	Stock Awards
Name	Number of Shares or Units of Stock That Have Not Vested (#)	Market Value of Shares or Units of Stock That Have Not Vested    ($)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested    (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)(1)
Nicholas K. Akins
2015 - 2017 Performance Units(2)			85,513	10,767,797
2016 - 2018 Performance Units(2)			83,201	10,476,670
2014 Restricted Stock Units(3)	16,294	1,025,870
2015 Restricted Stock Units(4)	24,432	1,538,239
2016 Restricted Stock Units(5)	27,734	1,746,133
Brian X. Tierney
2015 - 2017 Performance Units(2)			24,270	3,056,078
2016 - 2018 Performance Units(2)			23,462	2,954,335
2014 Restricted Stock Units(3)	4,562	287,224
2015 Restricted Stock Units(4)	6,935	436,628
2016 Restricted Stock Units(5)	7,821	492,410
Robert P. Powers
2015 - 2017 Performance Units(2)			24,025	3,025,228
2016 - 2018 Performance Units(2)			23,462	2,954,335
2014 Restricted Stock Units(3)	4,562	287,224
2015 Restricted Stock Units(4)	6,865	432,220
2016 Restricted Stock Units(5)	7,821	492,410
David M. Feinberg
2015 - 2017 Performance Units(2)			12,704	1,599,688
2016 - 2018 Performance Units(2)			13,952	1,756,836
2014 Restricted Stock Units(3)	2,334	146,949
2015 Restricted Stock Units(4)	3,631	228,608
2016 Restricted Stock Units(5)	4,651	292,827
Lisa M. Barton
2015 - 2017 Performance Units(2)			12,704	1,599,688
2016 - 2018 Performance Units(2)			12,419	1,563,800
2014 Restricted Stock Units(3)	1,952	122,898
2015 Restricted Stock Units(4)	3,631	228,608
2016 Restricted Stock Units(5)	4,139	260,591
Lana L. Hillebrand
2015 - 2017 Performance Units(2)			11,775	1,482,708
2016 - 2018 Performance Units(2)			11,459	1,442,917
2014 Restricted Stock Units(3)	2,194	138,134
2015 Restricted Stock Units(4)	3,338	210,160
2016 Restricted Stock Units(5)	3,800	239,248

(1) Pursuant to applicable SEC rules, the market value of the performance units reported in this column was computed by multiplying the closing price of AEP’s common stock on December 31, 2016 ($62.96) by the maximum number of performance units issuable (200% of the target amount set forth in the preceding column) because the results for 2016 were above target for the performance units. However, the actual number of performance units credited upon vesting will be based on AEP’s actual performance over the applicable three year period.

(2) AEP currently grants performance units at the beginning of each year with a three-year performance and vesting period. This results in awards for overlapping successive three-year performance periods. These awards generally vest at the end of the three year performance period. The performance units awarded for the 2014 - 2016 performance period, including associated dividend credits, vested at December 31, 2016 and are shown in the Options Exercises and Stock Vested for 2016 table below. The awards shown for the 2015 - 2017 and 2016 - 2018 performance periods include performance units resulting from reinvested dividends which are subject to the same performance criteria.

(3) Amounts include RSUs resulting from reinvested dividends. They will generally vest, subject to the executive officer’s continued employment, on May 1, 2017. These RSUs were granted on December 10, 2013.

(4) Amounts include RSUs resulting from reinvested dividends. They will generally vest, subject to the executive officer’s continued employment, in two equal installments, on May 1, 2017 and May 1, 2018. These RSUs were granted on February 24, 2015.

(5) These RSUs were granted on February 23, 2016 and include restricted stock units resulting from reinvested dividends. They will generally vest, subject to the executive officer’s continued employment, in three equal installments, on May 1, 2017, May 1, 2018 and May 1, 2019.

75

Option Exercises and Stock Vested for 2016

The following table provides information with respect to the vesting of RSUs and performance units in 2016 that were granted to our named executive officers in previous years. The named executive officers did not exercise any stock options in 2016.

	Option Awards		Stock Awards
Name	Number of Shares Acquired on Exercise     (#)	Value Realized on Exercise     ($)	Number of Shares Acquired on Vesting    (#)(1)	Value Realized on Vesting ($)    (2)
Nicholas K. Akins	0	0	231,032	14,607,502
Brian X. Tierney	0	0	64,751	4,094,107
Robert P. Powers	0	0	64,717	4,091,919
David M. Feinberg	0	0	33,114	2,093,732
Lisa M. Barton	0	0	29,601	1,871,621
Lana L. Hillebrand	0	0	33,209	2,102,401

(1) This column includes the following performance units and related dividend equivalents for the 2014 - 2016 performance period that vested on December 31, 2016: 186,941 for Mr. Akins; 52,334 for each of Messrs. Tierney and Powers; 26,775 for Mr. Feinberg; 22,393 for Ms. Barton and 24,950 for Ms. Hillebrand. This column also includes the following RSUs that vested on May 2, 2016: 44,091 for Mr. Akins; 12,417 for Mr. Tierney; 12,383 for Mr. Powers; 6,339 for Mr. Feinberg; 4,680 for Ms. Barton and 8,259 for Ms. Hillebrand. This column also includes 2,528 RSUs that vested on October 3, 2016 for Ms. Barton.

(2) As is required, the value included in this column for the 2014-2016 performance units is computed by multiplying the number of units by the closing price of AEP’s common stock on the vesting date of December 31, 2016 ($62.96). However, the actual value realized from these units was based on the 20-day average closing market price of AEP common stock prior to the vesting date ($61.86). Also as required, this column includes the value of RSUs that vested on May 2, 2016 computed by multiplying the number of units vesting by the closing price of AEP’s common stock on this date, which was $64.36 per share. However, the actual value realized from these units was based on the 20-day average closing market price of AEP common stock prior to the vesting date ($64.776).This column also included the value of RSUs for Ms. Barton that vested on October 3, 2016, which had a market value of $63.51 per share (the closing price of AEP’s common stock on the vesting date).

2014 - 2016 Performance Units

Performance units that were granted for the 2014 - 2016 performance period vested on December 31, 2016. The combined score for the 2014-2016 performance period was 163.9 percent of target. The final score calculation for these performance measures is shown in the chart below.

Performance Measures	Threshold Performance	Target Performance	Maximum Payout Performance	Actual Performance	Score	Weight	Weighted Score
3-Year Cumulative Operating Earnings Per Share	$9.90 (30% payout)	$10.250 (100% Payout)	$10.97 (200% Payout)	$11.056	200.0%	50%	100.0%
3-Year Total Shareholder Return vs. S&P Electric Utilities	20th Percentile (0% Payout)	50th Percentile (100% Payout)	80th Percentile (200% Payout)	58.3 Percentile	127.7%	50%	63.9%
Composite Result							163.9%

76

Pension Benefits for 2016

The following table provides information regarding the pension benefits for our named executive officers under AEP’s pension plans. The material terms of the plans are described following the table.

Name	Plan Name	Number of Years Credited Service (#)	Present Value of Accumulated Benefit($)(1)	Payments During Last Fiscal Year($)
Nicholas K Akins	AEP Retirement Plan	34.6	599,058	0
	CSW Executive Retirement Plan	34.6	1,344,710	0
Brian X. Tierney	AEP Retirement Plan	18.7	326,573	0
	AEP Supplemental Benefit Plan	18.7	1,013,205	0
Robert P. Powers	AEP Retirement Plan	18.5	603,373	0
	AEP Supplemental Benefit Plan	35.5 (2)	3,901,685	0
David M. Feinberg	AEP Retirement Plan	5.7	81,087	0
	AEP Supplemental Benefit Plan	5.7	211,716	0
Lisa M. Barton	AEP Retirement Plan	10.1	153,106	0
	AEP Supplemental Benefit Plan	10.1	210,420	0
Lana L. Hillebrand	AEP Retirement Plan	21.6 (3)	432,578	0
	AEP Supplemental Benefit Plan	21.6	233,148	0

(1) The Present Value of Accumulated Benefits is based on the benefit accrued under the applicable plan through December 31, 2016, and the following assumptions (which are consistent with those used in AEP’s financial statements):

• The named executive officer retires at normal retirement age (age 65), except for Mr. Tierney, whose benefit is calculated at age 62 because he is eligible for an unreduced annuity benefit when he reaches that age, and Mr. Powers whose benefit is calculated as of December 31, 2016 because he is eligible for an unreduced annuity benefit because he has already reached age 62.

• The named executive commences the payment of benefits (the “accrued benefit”) immediately upon retirement.

• The value of the annuity benefit at the named executive officer’s assumed retirement age is determined based upon the accrued benefit, an assumed interest rate of 4.05 percent, 3.85 percent and 3.85 percent for the benefits accrued under the AEP Retirement Plan, AEP Supplemental Benefit Plan and the CSW Executive Retirement Plan, respectively, and assumed mortality based upon modified versions of the RP-2014 mortality tables. Base mortality rates are derived from the RP-2014 table factored to 2006 with no collar adjustment for the qualified pension benefits and a white collar adjustment for non-qualified pension benefits. Mortality improvements are projected generationally with rates that grade linearly by year from MP-2014 in 2007 to 0.75% in 2015 and thereafter and that also grade linearly by age to zero at age 95 from age 85. The value of the lump sum benefit at that assumed retirement age is determined based upon the accrued benefit, an assumed interest rate of 4.20 percent and assumed mortality based on current law IRS lump sum mortality. The present value of each named executive officer’s benefits is determined by discounting the value of benefits described above at the assumed retirement age to each executive’s current age using an assumed interest rate of 4.05 percent, 3.85 percent and 3.85 percent for the benefits accrued under the AEP Retirement Plan, AEP Supplemental Benefit Plan and CSW Executive Retirement Plan, respectively.

• For the AEP Retirement Plan, the present value of the accrued benefit is weighted based on 75 percent lump sum and 25 percent annuity (or 40 percent lump sum and 60 percent annuity for Mr. Powers due to his eligibility for early retirement under the final average pay benefit formula), based on the assumption that participants elect those benefit options in that proportion. For the AEP Supplemental Benefit Plan and the CSW Executive Retirement Plan, the present value of the accrued benefits is weighted based on 100 percent lump sum.

(2) Under a letter agreement negotiated pursuant to his hire in 1998, AEP credits Mr. Powers with 17 years of service in addition to his actual years of service with AEP to offset pension benefits that he would have been able to earn from his prior employer due to his length of service at that company. The additional years of service credit have augmented the present value of his accumulated benefits under the AEP Supplemental Benefit Plan by $2,308,901. The benefits enhanced under this letter agreement were frozen as of December 31, 2010 (see Final Average Pay Formula below).

77

 (3) The benefit available to Ms. Hillebrand from the AEP Retirement Plan consists of two pieces: one under the Central and South West Corporation Cash Balance Retirement Plan (the “CSW Retirement Plan”) attributable to her prior period of service between December 15, 1982 and June 30, 2000 (her “CSW Retirement Plan Benefit”) and one under the cash balance formula since her return on December 17, 2012. Her CSW Retirement Plan Benefit will be paid to     her either as a lump sum or in one of the annuity options offered by the plan. The amount available to her as a lump sum would be the greater of (i) her CSW Retirement Plan cash balance account ($336,635 as of December 31, 2016), or (ii) the lump sum value of her CSW Retirement Plan protected minimum normal retirement annuity (which had accrued during the 14.5 year period until her traditional pension formula benefit became frozen effective July 1, 1997), calculated using a factor based on then applicable interest and mortality assumptions as well as an assumed future cost of living adjustment rate of 3.00%. The payment available to her as an annuity would be based on the greater of (i) her CSW Retirement Plan protected minimum normal retirement annuity ($3, 279 per month) or (II) the life annuity equivalent of her then CSW Retirement Plan cash balance account, calculated using a factor based on then applicable interest and mortality assumptions.

Overview.    AEP maintains tax-qualified and nonqualified defined benefit pension plans for eligible employees. The nonqualified plans provide (i) benefits that cannot be paid under the tax-qualified plan because of maximum limitations imposed on such plans by the Internal Revenue Code and (ii) benefits pursuant to an individual agreement with one of the named executive officers (Mr. Powers). The plans are designed to provide a retirement income to executives and their spouses, as well as a market competitive benefit opportunity as part of a market competitive total rewards package.

AEP Retirement Plan.    The AEP Retirement Plan is a tax-qualified defined benefit pension plan under which benefits are generally determined by reference to a cash balance formula. The AEP Retirement Plan also encompasses the Central and South West Corporation Cash Balance Retirement Plan (the “CSW Retirement Plan”), which was merged into the AEP Retirement Plan effective December 31, 2008. As of December 31, 2016, each of the named executive officers was vested in their AEP Retirement Plan benefit.

In addition, employees who have continuously participated in the AEP Retirement Plan (but not the CSW Retirement Plan) since December 31, 2000 (“Grandfathered AEP Participants,” which includes Mr. Tierney and Mr. Powers) remain eligible for an alternate pension benefit calculated by reference to a final average pay formula. The benefits under this final average pay formula were frozen as of December 31, 2010.

Cash Balance Formula.    Under the cash balance formula, each participant has an account established to which dollar credits are allocated each year.

1. Company Credits.    Each year, participants’ accounts are credited with an amount equal to a percentage of their salary for that year and annual incentive award for the prior year. The applicable percentage is based on the participant’s age and years of service. The following table shows the applicable percentage:

Sum of Age Plus Years of Service	Applicable Percentage
Less than 30	3.0%
30-39	3.5%
40-49	4.5%
50-59	5.5%
60-69	7.0%
70 or more	8.5%

Each year, the IRS calculates a limit on the amount of eligible pay that can be used to calculate pension benefits in a qualified plan. For 2016, the limit was $265,000.

2. Interest Credits.    All amounts in the cash balance accounts earn interest at the average interest rate on 30-year Treasury securities for the month of November of the prior year, with a floor of 4 percent. For 2016, the interest rate was 4 percent.

Final Average Pay Formula.    Grandfathered AEP Participants receive their benefits under the cash balance formula or the final average pay formula, whichever provides the higher benefit. On December 31, 2010, the final

78

average pay benefit payable at the Grandfathered AEP Participant’s normal retirement age was frozen, meaning that their final average pay formula benefit is not affected by the participant’s service or compensation subsequent to this date. This frozen final average pay normal retirement benefit is based on the following calculation as of December 31, 2010: the participant’s then years of service times the sum of (i) 1.1 percent of the participant’s then high 36 consecutive months of base pay (“High 36”); plus (ii) 0.5 percent of the amount by which the participant’s then High 36 exceeded the participant’s applicable average Social Security covered compensation.

Grandfathered AEP Participants may become entitled to a subsidized early retirement benefit under the final average pay formula if they remain employed with AEP through age 55 with at least three years of service. The early retirement benefit payable under the final average pay formula is the unreduced normal retirement age benefit if it commences at age 62 or later. The early retirement benefit is reduced by 3 percent for each year prior to age 62 that the benefits are commenced. Mr. Powers is eligible for an unreduced early retirement benefit.

AEP Supplemental Benefit Plan.    The AEP Supplemental Benefit Plan is a nonqualified defined benefit pension plan. It generally provides eligible participants with benefits that are in excess of those provided under the AEP Retirement Plan (without regard to the provisions now included as the result of the merger of the CSW Retirement Plan into the AEP Retirement Plan) as determined upon the participant’s termination of employment. These excess benefits are calculated under the terms of the AEP Retirement Plan described above with the following modifications: (i) additional years of service or benefit credits are taken into account; (ii) annual incentive pay was taken into account for purposes of the frozen final average pay formula; and (iii) the limitations imposed by the Internal Revenue Code on annual compensation and annual benefits are disregarded. However, eligible pay taken into account under the cash balance formula is limited to the greater of $1 million or two times the participant’s year-end base salary.

Mr. Powers negotiated 17 additional years of service under the AEP Supplemental Benefit Plan when he joined AEP in 1997 to offset pension benefits that he would have been able to earn from his prior employer due to his length of service at that company.

Participants do not become vested in their AEP Supplemental Plan benefit until they become vested in their AEP Retirement Plan benefit or upon a change in control. As of December 31, 2016, each of the named executive officers was fully vested in their AEP Supplemental Benefit Plan benefit.

CSW Executive Retirement Plan.    The CSW Executive Retirement Plan is a nonqualified defined benefit pension plan. It generally provides eligible participants with benefits that are in excess of those provided under the terms of the former CSW Retirement Plan (which was merged into the AEP Retirement Plan) as determined upon the participant’s termination of employment. The excess benefits are calculated without regard to the limitations imposed by the Internal Revenue Code on annual compensation and annual benefits. As of December 31, 2016, Mr. Akins was fully vested in his CSW Executive Retirement Plan benefit.

79

Nonqualified Deferred Compensation for 2016

The following table provides information regarding contributions, earnings and balances for our named executive officers under AEP’s three non-qualified deferred compensation plans which are each further described below.

Name	Plan Name(1)	Executive Contributions in Last FY(2)     ($)	Registrant Contributions in Last FY(3)     ($)	Aggregate Earnings in Last FY(4)     ($)	Aggregate Withdrawals/ Distributions     ($)	Aggregate Balance at Last FYE(5)     ($)
Nicholas K. Akins	SRSP	104,100	78,075	46,755	0	1,599,366
	ICDP	0	0	11,906	0	326,005
	SORP	0	0	753,815	0	6,569,464
Brian X. Tierney	SRSP	156,226	70,302	237,843	0	3,441,925
	SORP	0	0	134,642	0	1,173,398
Robert P. Powers	SRSP	91,830	68,873	277,992	0	3,825,841
	ICDP	0	0	65,611	0	976,618
	SORP	0	0	378,673	0	3,300,123
David M. Feinberg	SRSP	68,831	51,623	12,614	0	466,395
	SORP	9,418	0	224,737	0	1,958,577
Lisa M. Barton	SRSP	57,028	42,771	11,798	0	432,741
	ICDP	0	0	447	0	27,648
	SORP	502,170	0		0	1,484,825
Lana L. Hillebrand	SRSP	62,066	46,549	10,911	0	369,055
	SORP	1,328,782	0	210,355	0	1,539,137

(1) “SRSP” is the American Electric Power System Supplemental Retirement Savings Plan, “ICDP” is the American Electric Power System Incentive Compensation Deferral Plan, and “SORP” is the American Electric Power System Stock Ownership Requirement Plan.

(2) The amounts set forth under “Executive Contributions in Last FY” for the SRSP are reported in the Summary Compensation Table as either (i) Salary for 2016 or (ii) the Non-Equity Incentive Plan Compensation for 2015. The amount set forth under “Executive Contributions in Last FY” for the SORP for Mr. Feinberg was reported in the Summary Compensation Table in the Stock Awards column for 2013.

(3) The amounts set forth under “Registrant Contributions in Last FY” for the SRSP are reported in the All Other Compensation column of the Summary Compensation Table.

(4) No amounts set forth under “Aggregate Earnings in Last FY” have been reported in the Summary Compensation Table as there were no above market or preferential earnings credited to any named executive officer’s account in any of the plans.

(5) The amounts set forth in the “Aggregate Balance at Last FYE” column for the SRSP include the SRSP amounts reported in the “Executive Contributions in Last FY” and “Registrant Contributions in Last FY” columns. In addition, the “Aggregate Balance at Last FYE” for the SRSP includes the following amounts for prior years: $813,631 for Mr. Akins, $941,978 for Mr. Tierney, $952,146 for Mr. Powers and $314,546 for Mr. Feinberg. The amounts set forth in the “Aggregate Balance at Last FYE” for the SORP include the SORP amounts reported in the “Executive Contributions in Last FY.” In addition, the “Aggregate Balance at Last FYE” for the SORP includes the following amounts for prior years: $2,670,419 for Mr. Akins, $5,297 for Mr. Tierney, $4,980 for Mr. Powers and $1,607,646 for Mr. Feinberg.

Overview.    AEP maintains non-qualified deferred compensation plans that allow eligible employees, including the named executive officers, to defer receipt of a portion of their base salary, annual incentive compensation and performance unit awards. The plans are unfunded. Participants have an unsecured contractual commitment from AEP to pay the amounts due under the plans from the general assets of AEP. AEP maintains the following non-qualified deferred compensation plans for eligible employees:

• The American Electric Power System Supplemental Retirement Savings Plan;

• The American Electric Power System Incentive Compensation Deferral Plan; and

• The American Electric Power System Stock Ownership Requirement Plan.

80

Supplemental Retirement Savings Plan.    This plan allows eligible participants to save on a pre-tax basis and to continue to receive AEP matching contributions beyond the limits imposed by the Internal Revenue Code on qualified plans of this type.

• Participants can defer up to 50 percent of their base salary and annual incentive award in excess of the IRS’ eligible compensation limit for qualified plans, which was $265,000 for 2016, up to $2,000,000.

• AEP matches 100 percent of the participant’s contributions up to 1 percent of eligible compensation and 70 percent of the participant’s contributions from the next 5 percent of eligible compensation (for a total AEP match of up to 4.5% of eligible compensation).

• Participants may not withdraw any amount credited to their account until their termination of employment with AEP. Participants may elect a distribution of their account as a lump-sum or annual installment payments over a period of up to 10 years. Participants may delay the commencement of distributions for up to five years from the date of their termination of employment.

• Participants may direct the investment of their plan account among the core investment options that are available to all employees in AEP’s qualified Retirement Savings Plan and one additional option that provides interest at a rate set each December at 120 percent of the applicable federal long-term rate with monthly compounding. There were no above-market or preferential earnings with respect to the Supplemental Retirement Savings Plan.

Incentive Compensation Deferral Plan.    This plan allows eligible employees to defer payment of up to 80 percent of vested performance units.

• AEP does not offer any matching contributions.

• Participants may direct the investment of their plan accounts among the core investment options that are available to all employees in AEP’s qualified Retirement Savings Plan. There were no above-market or preferential earnings with respect to the Incentive Compensation Deferral Plan in 2016.

• Generally, participants may not withdraw any amount credited to their account until their termination of employment with AEP. However, participants may make one withdrawal of amounts attributable to their pre-2005 contributions prior to termination of employment. The withdrawal amount would be subject to a 10 percent withdrawal penalty. Participants may elect among the same payment options for the distributions of their account value as described above for the Supplemental Retirement Savings Plan.

Stock Ownership Requirement Plan.    This plan assists executives in achieving their minimum stock ownership requirements. It does this primarily by tracking the executive’s AEP Career Shares. AEP Career Shares are a form of deferred compensation, which are unfunded and unsecured general obligations of AEP. The rate of return on AEP Career Shares is equivalent to the total return on AEP stock with dividends reinvested. Participants may not withdraw any amount credited to their account until their termination of employment with AEP. Participants may elect among the same payment options for the distribution of the value of their AEP Career Shares as described above for the Supplemental Retirement Savings Plan.

Potential Payments Upon Termination of Employment or Change in Control

AEP has entered into agreements and maintains plans that will require AEP to provide compensation to the named executive officers in the event of a termination of their employment or a change in control of AEP. Actual payments will depend on the circumstances and timing of any termination of employment or change of control. In addition, in connection with any actual termination or change in control transaction, we may enter into agreements or establish arrangements that provide additional or alternative benefits or amounts from those described below. The agreements and plans summarized below are complex legal documents with terms and conditions having precise meanings, which are designed to address many possible but currently hypothetical situations.

81

Severance.    AEP currently provides full-time employees, including the named executive officers, with severance benefits if their employment is terminated as the direct result of a restructuring or downsizing (“Severance-Eligible Employees”) and the employee releases AEP from any and all claims. These severance benefits include:

• A lump sum severance payment equal to two weeks of base pay for each year of AEP service, with a minimum of 8 weeks for employees with at least one year of AEP service;

• Continued eligibility for medical and dental benefits at the active employee rates for eighteen months or until the participant becomes eligible for coverage from another employer, whichever occurs first;

• For employees who are at least age 50 with 10 years of AEP service and who do not qualify for AEP’s retiree medical benefits or who will be bridged to such retiree benefit eligibility (described below), AEP also provides medical and dental benefit eligibility at rates equivalent to those provided to retirees until age 65 or until the participant becomes eligible for coverage from another employer, whichever occurs first; and

• Outplacement services, the incremental cost of which may be up to $28,000 for executive officers.

Severance-Eligible Employees who have enough weeks of severance (up to one year) and vacation to cover a period that would allow them to become eligible for retiree medical benefits, which is available to those employees who are at least age 55 with at least 10 years of service (“Retirement-Eligible Employees”) are retained as employees on a paid leave of absence until they become retirement eligible. This benefit applies in lieu of severance and unused vacation payments that these employees would otherwise receive. AEP pays any remaining severance and vacation pay at the time of their retirement. This delay of an employee’s termination date does not apply to the plans providing nonqualified deferred compensation, which define a participant’s termination date by reference to Internal Revenue Code Section 409A.

A Severance-Eligible executive’s termination entitles that executive to a pro-rata portion of any outstanding unvested performance units that the executive has held for at least six months and to the payment of a pro-rata portion of any RSUs to the extent not already vested and paid. The pro-rated performance units will not become payable until the end of the performance period and remain subject to all performance objectives.

Severance-Eligible executives may continue financial counseling and tax preparation services for one year following their termination up to a maximum annual incremental cost to AEP for 2016 of $13,390 plus related incidental expenses of the advisor.

AEP also has an Executive Severance Plan (Executive Severance Plan) that provides severance benefits to selected officers of AEP, including the named executive officers, subject to the executive’s agreement to comply with the provisions of the plan, including confidentiality, non-solicitation, cooperation and non-disparagement provisions during their employment and following termination. Executives remain eligible for benefits under the general severance plan described above; however, any benefits provided under the Executive Severance Plan will be reduced by any amounts provided under the general severance plan. Benefits under the Executive Severance Plan would be triggered by a resignation for “good reason” or an involuntary termination by AEP without “cause” (each as defined below).

The term “cause” with respect to the Executive Severance Plan means:

(i) Failure or refusal to perform a substantial part of the executive’s assigned duties and responsibilities following notice and a reasonable opportunity to cure (if such failure is capable of cure);

(ii) Commission of an act of willful misconduct, fraud, embezzlement or dishonesty either in connection with the executive’s duties to AEP or which otherwise is injurious to the best interest or reputation of AEP;

(iii) Repeated failure to follow specific lawful directions of the Board or any officer to whom the executive reports;

82

(iv) A violation of any of the material terms and conditions of any written agreement or agreements the executive may from time to time have with AEP;

(v) A material violation of any of the rules of conduct of behavior of AEP;

(vi) Conviction of, or plea of guilty or nolo contendere to, (A) a felony, (B) a misdemeanor involving an act of moral turpitude, or (C) a misdemeanor committed in connection with the executive’s employment with AEP which is injurious to the best interest or reputation of AEP; or

(vii) Violation of any applicable confidentiality, non-solicitation, or non-disparagement covenants or obligations relating to AEP (including the provisions to which the executive agreed when enrolling in the plan).

An executive’s termination of employment that is covered by his or her change in control agreement (described in the next section) or due to mandatory retirement, disability or death would not be considered an involuntary termination that may trigger the payment of benefits under the Executive Severance Plan.

An executive would have “good reason” for resignation under the Executive Severance Plan if there is any reduction in the executive’s then current annual base salary without the executive’s consent; provided, however, that a uniform percentage reduction of 10% or less in the annual base salary of all executives participating in the Executive Severance Plan who are similarly situated would not be considered good reason for resignation. Also, AEP must be given 10 days following receipt of written notice from the executive to restore the executive’s base salary before his or resignation may trigger plan benefits.

If benefits under the Executive Severance Plan are triggered, the affected named executive officers would receive two times their base salary and target annual incentive payable over two years. In addition, a pro-rated portion of their outstanding unvested performance units and RSUs would vest. The pro-rated performance units will not become payable until the end of the performance period and remain subject to all performance objectives. Any severance benefits payable under the Executive Severance Plan and prorated vesting of RSUs are conditioned on the execution of an agreement by the executive officer releasing claims against AEP and committing to a non-competition obligation.

Change In Control.    AEP defines “change in control” under its change in control agreements and Long-Term Incentive Plan as:

• The acquisition by any person of the beneficial ownership of securities representing more than one-third of AEP’s voting stock;

• A merger or consolidation of AEP with another corporation unless AEP’s voting securities outstanding immediately before such merger or consolidation continue to represent at least two-thirds of the total voting power of the surviving entity outstanding immediately after such merger or consolidation; or

• Approval by the shareholders of the liquidation of AEP or the disposition of all or substantially all of the assets of AEP.

AEP has a change in control agreement with each of the named executive officers that is triggered if there is a Qualifying Termination of the named executive officer’s employment. A “Qualifying Termination” for this purpose generally occurs when the executive’s employment is terminated in connection with that change in control (i) by AEP without “cause” or (ii) by the named executive officer for “good reason”, each as defined below. Such termination must be no later than two years after the change in control. These agreements provide for:

• A lump sum payment equal to 2.99 times the named executive officer’s annual base salary plus target annual incentive compensation award under the annual incentive program as in effect at the time of termination; and

• Outplacement services.

83

The term “cause” with respect to AEP’s change in control agreements means:

(i) The willful and continued failure of the executive to perform the executive’s duties after a written demand for performance is delivered to the executive by the Board; or

(ii) The willful conduct or omission by the executive, which the Board determines to be illegal; gross misconduct that is injurious to AEP; or a breach of the executive’s fiduciary duty to AEP.

The term “good reason” with respect to AEP’s change in control agreements means:

(i) An adverse change in the executive’s status, duties or responsibilities from that in effect immediately prior to the change in control;

(ii) AEP’s failure to pay in a timely fashion the salary or benefits to which the executive is entitled under any employment agreement in effect on the date of the change in control;

(iii) The reduction of the executive’s salary as in effect on the date of the change in control;

(iv) Any action taken by AEP that would substantially diminish the aggregate projected value of the executive’s awards or benefits under AEP’s benefit plans or policies;

(v) A failure by AEP to obtain from any successor the assent to the change in control agreement; or

(vi) The relocation, without the executive’s prior approval, of the office at which the executive is to perform services to a location that is more than fifty (50) miles from its location immediately prior to the change in control.

AEP must be given notice and an opportunity to cure any of these circumstances before they would be considered to be “good reason.”

All awards under the Long-Term Incentive Plan will vest upon a “Qualifying Termination”, which may occur coincident with or within one year after a change in control. The term “Qualifying Termination” with respect to long-term incentive awards generally is the same as that described for the change in control agreements, except that an executive’s mandatory retirement at age 65 is explicitly excluded, and “Cause” is defined more broadly to encompass:

(i) Failure or refusal to perform assigned duties and responsibilities in a competent or satisfactory manner;

(ii) Commission of an act of dishonesty, including, but not limited to, misappropriation of funds or any property of AEP;

(iii) Engagement in activities or conduct injurious to the best interest or reputation of AEP;

(iv) Insubordination;

(v) Violation of any material term or condition of any written agreement with AEP;

(vi) Violation of any of AEP’s rules of conduct of behavior;

(vii) Commission of a felony, a misdemeanor involving an act of moral turpitude, or a misdemeanor committed in connection with employment at AEP which is injurious to the best interest or reputation of AEP; or

(viii) Disclosure, dissemination, or misappropriation of confidential, proprietary, and/or trade secret information.

84

In addition, performance units would be deemed to have been fully earned at 100 percent of the target score upon a “Qualifying Termination” following a change in control. The value of each vested performance unit following a “Qualifying Termination” would be (1) the closing price of a share of AEP common stock on the date of the Qualifying Termination or (2) if the date of the Qualifying Termination is coincident with the change in control and if the change in control is the result of a tender offer, merger, or sale of all or substantially all of the assets of AEP, the price paid per share of common stock in that transaction.

The AEP Supplemental Benefit Plan also provides that all accrued supplemental retirement benefits to the extent then unvested become fully vested upon a change in control.

Termination Scenarios

The following tables show the incremental compensation and benefits that would have been paid to each named executive officer who was employed by AEP on December 31, 2016 assuming the hypothetical circumstances cited in each column occurred on December 31, 2016 and calculated in accordance with the methodology required by the SEC. In connection with any actual termination or change in control, AEP may enter into agreements or establish arrangements that provide additional benefits or amounts, or may alter the terms of benefits described below.

With respect to annual incentive compensation for the completed year, the initial calculated annual incentive opportunity is shown, before any individual discretionary adjustment, which varies from the actual value paid and reported in the Summary Compensation Table.

The values shown in the change in control column are triggered only if the named executive officer’s employment is terminated under the circumstances (described above under Change In Control) that trigger the payment or provision of each of the types of compensation and benefits shown.

No information is provided for terminations due to disability because it is not generally AEP’s practice to terminate the employment of any employee so long as they remain eligible for AEP’s long-term disability benefits. AEP successively provides sick pay and then long-term disability benefits for up to two years to employees with a disability that prevents them from returning to their job. Such disability benefits continue for employees that cannot perform any occupation for which they are reasonably qualified generally until the employee reaches age 65. Because disabled participants remain employed by AEP, they continue to vest in long-term incentive awards while they are disabled. AEP treats a participant’s disability as a termination to the extent required by the regulations issued under Internal Revenue Code Section 409A, but such terminations only trigger the payment of benefits that had previously vested. Employment may be terminated due to disability under a separate definition of employment termination that applies to restricted stock unit awards and compensation and benefit programs that may be considered non-qualified deferred compensation under Section 409A of the Internal Revenue Code. However restricted stock unit awards allow participants terminated due to disability to continue to vest as if their employment had continued so long as they remain continuously disabled.

85

Potential Incremental Compensation and Benefits

That Would Have Been Provided as the Result of Employment Termination

as of December 31, 2016

For Nicholas K. Akins

Executive Benefits and Payments Upon Termination	Resignation or Retirement	Severance	Involuntary Termination   for Cause	Change In    Control	Death
Compensation:
Base Salary ($1,320,000)	$ 0	$2,640,000	$0	$3,946,800	$ 0
Annual Incentive for Completed Year(1)	$2,809,930	$2,809,930	$0	$2,809,930	$2,809,930
Other Payment for Annual Incentives(2)	$ 0	$3,300,000	$0	$4,933,500	$ 0
Long-Term Incentives:(3)
2015-2017 Performance Units(4)	$3,589,266	$3,589,266	$0	$5,383,898	$3,589,266
2016-2018 Performance Units(4)	$1,746,112	$1,746,112	$0	$5,238,335	$1,746,112
2014 Restricted Stock Units	$ 0	$ 695,680	$0	$1,025,870	$1,025,870
2015 Restricted Stock Units	$ 0	$ 610,652	$0	$1,538,239	$1,538,239
2016 Restricted Stock Units	$ 0	$ 523,840	$0	$1,746,133	$1,746,133
Benefits:
Financial Counseling	$ 0	$ 13,390	$0	$ 13,390	$	13,390
Outplacement Services(5)	$ 0	$ 28,000	$0	$ 28,000	$	0
Total Incremental Compensation and Benefits	$8,145,308	$15,956,870	$0	$26,664,095	$12,468,940

Notes for the Potential Incremental Termination Scenario tables are provided collectively following the last such table.

Potential Incremental Compensation and Benefits

That Would Have Been Provided as the Result of Employment Termination

as of December 31, 2016

For Brian X. Tierney

Executive Benefits and Payments Upon Termination	Resignation or Retirement	Severance	Involuntary Termination  for Cause	Change In    Control	Death
Compensation:
Base Salary ($728,000)	$ 0	$1,456,000	$0	$2,176,720	$ 0
Annual Incentive for Completed Year(1)	$991,979	$ 991,979	$0	$ 991,979	$ 991,979
Other Payment for Annual Incentives(2)	$ 0	$1,164,800	$0	$1,741,376	$ 0
Long-Term Incentives:(3)
2015-2017 Performance Units(4)	$ 0	$1,018,693	$0	$1,582,039	$1,018,693
2016-2018 Performance Units(4)	$ 0	$ 492,389	$0	$1,477,168	$ 492,389
2014 Restricted Stock Units	$ 0	$ 194,755	$0	$ 287,224	$ 287,224
2015 Restricted Stock Units	$ 0	$ 173,314	$0	$ 436,628	$ 436,628
2016 Restricted Stock Units	$ 0	$ 147,723	$0	$ 492,410	$ 492,410
Benefits:
Financial Counseling	$ 0	$ 13,390	$0	$ 13,390	$ 13,390
Outplacement Services(5)	$ 0	$ 28,000	$0	$ 28,000	$ 0
Total Incremental Compensation and Benefits	$991,979	$5,681,043	$0	$9,172,394	$3,732,713

Notes for the Potential Incremental Termination Scenario tables are provided collectively following the last such table.

86

Potential Incremental Compensation and Benefits

That Would Have Been Provided as the Result of Employment Termination

as of December 31, 2016

For Robert P. Powers

Executive Benefits and Payments Upon Termination	Resignation or Retirement	Severance	Involuntary Termination for Cause	Change-In-   Control	Death
Compensation:
Base Salary ($721,000)	$ 0	$1,442,000	$0	$2,155,790	$ 0
Annual Incentive for Completed Year(1)	$ 982,761	$ 982,761	$0	$ 982,761	$ 982,761
Other Payment for Annual Incentives(2)	$ 0	$1,153,600	$0	$1,724,632	$ 0
Long-Term Incentives:(3)
2015-2017 Performance Units(4)	$1,008,409	$1,008,409	$0	$1,512,614	$1,008,409
2016-2018 Performance Units(4)	$492,389	$ 492,389	$0	$1,477,168	$ 492,389
2014 Restricted Stock Units	$ 0	$ 194,755	$0	$ 287,224	$ 287,224
2015 Restricted Stock Units	$ 0	$ 171,566	$0	$ 432,220	$ 432,220
2016 Restricted Stock Units	$ 0	$ 147,723	$0	$ 492,410	$ 492,410
Benefits:
Financial Counseling	$ 0	$ 13,390	$0	$ 13,390	$ 13,390
Outplacement Services(5)	$ 0	$ 28,000	$0	$ 28,000	$ 0
Total Incremental Compensation and Benefits	$2,483,559	$5,634,593	$0	$9,106,209	$3,708,803

Notes for the Potential Incremental Termination Scenario tables are provided collectively following the last such table.

Potential Incremental Compensation and Benefits

That Would Have Been Provided as the Result of Employment Termination

as of December 31, 2016

For David M. Feinberg

Executive Benefits and Payments Upon Termination	Resignation or Retirement	Severance	Involuntary Termination   for Cause	Change In    Control	Death
Compensation:
Base Salary ($613,000)	$ 0	$1,226,000	$0	$1,832,870	$ 0
Annual Incentive for Completed    Year(1)	$730,631	$ 730,631	$0	$ 730,361	$ 730,361
Other Payment for Annual    Incentives(2)	$ 0	$ 858,200	$0	$1,283,009	$ 0
Long-Term Incentives:(3)
2015-2017 Performance Units(4)	$ 0	$ 533,229	$0	$ 799,844	$ 533,229
2016-2018 Performance Units(4)	$ 0	$ 292,806	$0	$ 878,418	$ 292,806
2014 Restricted Stock Units	$ 0	$ 99,637	$0	$ 146,949	$ 146,949
2015 Restricted Stock Units	$ 0	$ 90,725	$0	$ 228,608	$ 228,608
2016 Restricted Stock Units	$ 0	$ 87,848		$ 292,827	$ 292,827
Benefits:
Financial Counseling	$ 0	$ 13,390	$0	$ 13,390	$ 13,390
Outplacement Services(5)	$ 0	$ 28,000	$0	$ 28,000	$ 0
Total Incremental Compensation and Benefits	$730,631	$3,960,466	$0	$6,234,546	$2,238,440

Notes for the Potential Incremental Termination Scenario tables are provided collectively following the last such table.

87

Potential Incremental Compensation and Benefits

That Would Have Been Provided as the Result of Employment Termination

as of December 31, 2016

For Lisa M. Barton

Executive Benefits and Payments Upon Termination	Resignation or Retirement	Severance	Involuntary Termination   for Cause	Change-In- Control	Death
Compensation:
Base Salary ($530,000)	$ 0	$1,060,000	$0	$1,584,700	$ 0
Annual Incentive for Completed    Year(1)	$631,926	$ 631,926	$0	$ 631,926	$ 631,926
Other Payment for Annual    Incentives(2)	$ 0	$ 742,000	$0	$1,109,290	$ 0
Long-Term Incentives:(3)
2015-2017 Performance Units(4)	$ 0	$ 533,229	$0	$ 799,844	$ 533,229
2016-2018 Performance Units(4)	$ 0	$ 260,633	$0	$ 781,900	$ 260,633
2014 Restricted Stock Units	$ 0	$ 83,338	$0	$ 122,898	$ 122,898
2015 Restricted Stock Units		$ 90,725		$ 228,608	$ 228,608
2016 Restricted Stock Units	$ 0	$ 78,177	$0	$ 260,591	$ 260,591
Benefits:
Financial Counseling	$ 0	$ 13,390	$0	$ 13,390	$ 13,390
Outplacement Services(5)	$ 0	$ 28,000	$0	$ 28,000	$ 0
Total Incremental Compensation and Benefits	$631,926	$3,521,418	$0	$5,561,147	$2,051,275

88

Potential Incremental Compensation and Benefits

That Would Have Been Provided as the Result of Employment Termination

as of December 31, 2016

For Lana L. Hillebrand

Executive Benefits and Payments Upon Termination	Resignation or Retirement	Severance	Involuntary Termination   for Cause	Change-In- Control	Death
Compensation:
Base Salary ($560,000)	$ 0	$1,120,000	$0	$1,674,400	$ 0
Annual Incentive for Completed    Year(1)	$667,676	$ 667,676	$0	$ 667,676	$ 667,676
Other Payment for Annual    Incentives(2)	$ 0	$ 784,000	$0	$1,172,080	$ 0
Long-Term Incentives:(3)
2015-2017 Performance Units(4)	$ 0	$ 494,236	$0	$ 741,354	$ 494,236
2016-2018 Performance Units(4)	$ 0	$ 240,486	$0	$ 721,459	$ 240,486
2014 Restricted Stock Units	$ 0	$ 93,274	$0	$ 138,134	$ 138,134
2015 Restricted Stock Units		$ 82,866		$ 210,160	$ 210,160
2016 Restricted Stock Units	$ 0	$ 71,774	$0	$ 239,248	$ 239,248
Benefits:
Financial Counseling	$ 0	$ 13,390	$0	$ 13,390	$ 13,390
Outplacement Services(5)	$ 0	$ 28,000	$0	$ 28,000	$ 0
Total Incremental Compensation and Benefits	$667,696	$2,928,026	$0	$5,605,901	$2,003,330

(1) Executive officers and all other employees are eligible for an annual incentive award based on their earnings for the year if they remain employed with AEP through year-end, if they die or if they incur a retirement-eligible termination. The amount shown is the calculated annual incentive opportunity, but annual incentives for executive officers are awarded at the discretion of the HR Committee or independent members of the Board pursuant to the award determination process described in the Compensation Discussion and Analysis.

(2) The amount shown in the Severance column is two times the target annual incentive opportunity for each of the named executive officers. The amount shown in the Change-In-Control column is 2.99 times the target annual incentive opportunity for each of the named executive officers.

(3) The long-term incentive values shown represent the values that would be paid under such circumstances shown in each column based on the closing price of AEP common stock on December 31, 2016, which is the methodology required by the SEC. These amounts differ from the values calculated in accordance with FASB ASC Topic 718. These amounts also differ from the amounts that would actually be paid under such circumstances, which would be based on the 20-day average closing market price of AEP common stock as of the end of the performance period for performance units and as of the termination date for Restricted Stock Units.

(4) The target value of performance unit awards are shown. The actual value paid in the event of resignation or retirement, severance or death, if any, will depend on the actual performance score for the full performance period. Any payments for awards under those circumstances are not paid until the end of the three year performance period. In the event of a qualifying termination in connection with a change in control, awards would be paid at a target performance score as soon as administratively practical after the change in control.

(5) Represents the maximum cost of AEP-paid outplacement services, which AEP provides through an unaffiliated third party vendor.

89

The following table shows the value of previously earned and vested compensation and benefits as of December 31, 2016, that would have been provided to each named executive officer following a termination of his or her employment on December 31, 2016. These amounts were generally earned or vested over multiple years of service to AEP.

Non-Incremental Post-Termination Compensation and Benefits on December 31, 2016

Name	Long-Term Incentives		Benefits
	Vested Performance Units (1)	AEP Career Shares (2)	Vacation Payout (3)	Post Retirement Benefits (4)	Deferred Compensation (5)
Nicholas K. Akins	$11,769,805	$6,686,289	$76,154	$1,928,163	$1,925,371
Brian X. Tierney	$ 3,294,949	$1,194,288	$26,642	$1,270,763	$3,441,925
Robert P. Powers	$ 3,294,949	$3,358,790	$13,750	$4,779,432	$4,802,459
David M. Feinberg	$ 1,685,754	$1,993,377	$42,144	$ 288,832	$ 466,395
Lisa M. Barton	$ 1,409,863	$1,511,229	$15,798	$ 357,706	$ 460,389
Lana L. Hillebrand	$ 1,565,500	$ 1,566,506	$21,000	$ 619,441	$ 369,055

(1) Represents the value of performance units that vested on December 31, 2016 calculated using the market value of these shares on December 31, 2016. However, the actual value realized or deferred from these performance units was based on the 20-day average closing market price of AEP common stock on the vesting date.

(2) Represents the value of AEP share equivalents deferred mandatorily into the AEP Stock Ownership Requirement Plan calculated using the market value of these shares on December 31, 2016. However, the actual value that would have been realized from these AEP share equivalents would have been based on the 20-day average closing market price of AEP common stock at the end of the month of employment termination.

(3) Represents accumulated but unused vacation.

(4) Represents the lump sum benefit calculated for the named executive officer pursuant to the terms of the AEP Retirement Plan, the AEP Supplemental Benefit Plan and the CSW Executive Retirement Plan, as applicable.

(5) Includes balances from the Supplemental Retirement Savings Plan and the Incentive Compensation Deferral Plans, but does not include AEP Career Share balances, which are listed separately in column (2).

90

TRANSACTIONS WITH RELATED PERSONS

The American Electric Power Company, Inc. Related Person Transaction Approval Policy was adopted by AEP’s Board in December 2006. The written Policy is administered by AEP’s Board of Directors’ Committee on Directors and Corporate Governance (“Corporate Governance Committee”).

The Policy defines a “Transaction with a Related Person” as any transaction or series of transactions in which (i) the Company or a subsidiary is a participant, (ii) the aggregate amount involved exceeds $120,000 and (iii) any “Related Person” has a direct or indirect material interest. A “Related Person” is any director or executive officer of AEP and any immediate family member of any such person.

The Corporate Governance Committee considers all of the relevant facts and circumstances in determining whether or not to approve a Transaction with a Related Person and approves only those transactions that it believes are in the best interests of the Company and its shareholders. The Corporate Governance Committee considers various factors, including, among other things: the nature of the Related Person’s interest in the transaction; whether the transaction involves arm’s-length bids or market prices and terms; the materiality of the transaction to each party; the availability of the product or services through other sources; whether the transaction would impair the judgment of a director or executive officer to act in the best interest of the Company; the acceptability of the transaction to the Company’s regulators; and in the case of a non-employee director, whether the transaction would impair his or her independence or status as an “outside” or “non-employee” director.

If Company management determines it is impractical or undesirable to wait until a meeting of the Corporate Governance Committee to consummate a Transaction with a Related Person, the Chair of the Corporate Governance Committee may review and approve the Transaction with a Related Person. Any such approval is reported to the Corporate Governance Committee at or before its next regularly scheduled meeting.

No approval or ratification of a Transaction with a Related Person supersedes the requirements of AEP’s Principles of Business Conduct applicable to any executive officer. To the extent applicable, any Transaction with a Related Person is also considered in light of the requirements set forth in those documents.

Since January 1, 2017, there have been no transactions, and there are no currently proposed transactions, involving an amount exceeding $120,000 in which AEP was or is expected to be a participant and in which any Related Person had a direct or indirect material interest.

None of the managers of the Company are independent.

91

THE EXCHANGE OFFERS

Purpose and Effect of the Exchange Offers

The Outstanding Notes were issued on September 22, 2017 and sold to the initial purchasers pursuant to a purchase agreement in transactions not requiring registration under the Securities Act. The initial purchasers subsequently sold the Outstanding Notes to qualified institutional buyers (as defined in Rule 144A under the Securities Act) in reliance on Rule 144A, and to persons in offshore transactions in reliance on Regulation S under the Securities Act.

We entered into a registration rights agreement with representatives of the initial purchasers of the Outstanding Notes in which we agreed, under certain circumstances, to file a registration statement relating to offers to exchange the Outstanding Notes for Exchange Notes and to use commercially reasonable efforts to cause such registration statement to be declared effective under the Securities Act no later than 270 days after the original issue date of the Outstanding Notes and to pay additional interest as described below if we do not consummate the Exchange Offers within 315 days after the issue date of the Outstanding Notes. The Exchange Notes will have terms identical in all material respects to the Outstanding Notes of the related series, except that the Exchange Notes will not contain certain terms with respect to transfer restrictions, registration rights and additional interest for failure to observe certain obligations in the registration rights agreement.

Under the circumstances set forth below, we will use commercially reasonable efforts to cause the SEC to declare effective a shelf registration statement with respect to the resale of the Outstanding Notes within the time periods specified in the registration rights agreement and keep the statement effective for one year from the original issue date of the Outstanding Notes, or such shorter period as described in the registration rights agreement. These circumstances include:

• if a change in law or in applicable interpretations of the staff of the SEC does not permit us to effect a registered exchange offer;

• if a registered exchange offer is not consummated within 315 days after the date of issuance of the Outstanding Notes;

• if any initial purchaser of the Outstanding Notes so requests with respect to Notes not eligible to be exchanged for Exchange Notes in the Exchange Offer and held by it following consummation of the Exchange Offer; or

• if any holder (other than a holder that is a broker-dealer electing to exchange Outstanding Notes acquired for its own account as a result of market making activities or other trading activities) notifies us during the 20 business days following consummation of an Exchange Offer that it was not eligible to participate in such Exchange Offer or any holder (other than a holder that is a broker-dealer electing to exchange Outstanding Notes acquired for its own account as a result of market making activities or other trading activities) who participates in an Exchange Offer does not receive freely tradeable Exchange Notes in such Exchange Offer.

Except for certain circumstances specified in the registration rights agreement, we will pay additional interest if:

• neither a registration statement relating to offers to exchange the Outstanding Notes for Exchange Notes nor a shelf registration statement with respect to the resale of the Outstanding Notes (if required) is filed by us within the applicable time periods specified above;

• neither the Exchange Offer registration statement nor a shelf registration statement (if required) is declared effective by the SEC within the applicable time periods specified above;

• the applicable Exchange Offer is not consummated within 315 days after the initial issuance of the Outstanding Notes (or if the 315th day is not a business day, by the first business day thereafter); or

92

• after the Exchange Offer registration statement or the shelf registration statement, as the case may be, is declared effective, such Exchange Offer registration statement or shelf registration statement thereafter ceases to be effective or usable (subject to certain exceptions) in connection with resales of Exchange Notes or Outstanding Notes, as the case may be, as provided in and during the periods specified in the registration rights agreement.

We sometimes refer to an event referred to in the first through fourth bullet items above as a Registration Default.

Additional interest, if payable, will be payable on the Outstanding Notes at a rate of 0.25% per annum for the first 90 days from and including the date on which any Registration Default occurs, and such additional interest rate shall increase by an additional 0.25% per annum thereafter; provided, however, that the additional interest rate on the Outstanding Notes will not at any time exceed 0.50% per annum. Additional interest will cease to accrue on and after the date on which all Registration Defaults have been cured. Any such additional interest payable will be payable on interest payment dates in addition to interest payable from time to time on the Outstanding Notes and Exchange Notes.

If you wish to exchange your Outstanding Notes for Exchange Notes in any of the Exchange Offers, you will be required to make the following written representations:

• you are not our affiliate within the meaning of Rule 405 of the Securities Act;

• you have no arrangement or understanding with any person to participate in a distribution (within the meaning of the Securities Act) of the Exchange Notes in violation of the provisions of the Securities Act;

• you are not engaged in, and do not intend to engage in, a distribution of the Exchange Notes; and you are acquiring the Exchange Notes in the ordinary course of your business.

Each broker-dealer that receives Exchange Notes for its own account in exchange for Outstanding Notes, where the broker-dealer acquired the Outstanding Notes as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Notes and that it did not purchase its Outstanding Notes from us or any of our affiliates. See “Plan of Distribution.”

Resale of Exchange Notes

We have not requested, and do not intend to request, an interpretation by the staff of the SEC as to whether the Exchange Notes issued pursuant to the Exchange Offers in exchange for the Outstanding Notes may be offered for sale, resold or otherwise transferred by any holder without compliance with the registration and prospectus delivery provisions of the Securities Act. Instead, based on interpretations by the SEC set forth in no-action letters issued to third parties, we believe that you may resell or otherwise transfer Exchange Notes issued in the Exchange Offers without complying with the registration and prospectus delivery provisions of the Securities Act if:

• you are acquiring the Exchange Notes in the ordinary course of your business;

• you have no arrangements or understanding with any person to participate in the distribution of the Exchange Notes within the meaning of the Securities Act;

• you are not our “affiliate,” as defined in Rule 405 of the Securities Act; and

• you are not engaged in, and do not intend to engage in, a distribution of the Exchange Notes.

If you are our affiliate, or are engaging in, or intend to engage in, or have any arrangement or understanding with any person to participate in, a distribution of the Exchange Notes, or are not acquiring the Exchange Notes in the ordinary course of your business:

93

• you cannot rely on the position of the SEC set forth in Morgan Stanley & Co. Incorporated (available June 5, 1991) and Exxon Capital Holdings Corporation (available May 13, 1988), as interpreted in the SEC’s letter to Shearman & Sterling, (available July 2, 1993), or similar no-action letters; and

• in the absence of an exception from the position stated immediately above, you must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the Exchange Notes.

This prospectus may be used for an offer to resell or transfer the Exchange Notes only as specifically set forth in this prospectus. With regard to broker-dealers, only broker-dealers that acquired the Outstanding Notes as a result of market-making activities or other trading activities may participate in the Exchange Offers. Each broker-dealer that receives Exchange Notes for its own account in exchange for Outstanding Notes, where such Outstanding Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of the Exchange Notes. Read “Plan of Distribution” for more details regarding the transfer of Exchange Notes.

Our belief that the Exchange Notes may be offered for resale without compliance with the registration or prospectus delivery provisions of the Securities Act is based on interpretations of the SEC for other exchange offers that the SEC expressed in some of its no-action letters to other issuers in exchange offers like ours. We have not sought a no-action letter in connection with the Exchange Offers, and we cannot guarantee that the SEC would make a similar decision about our Exchange Offers. If our belief is wrong, or if you cannot truthfully make the representations mentioned above, and you transfer any Exchange Note issued to you in the Exchange Offers without meeting the registration and prospectus delivery requirements of the Securities Act, or without an exemption from such requirements, you could incur liability under the Securities Act. We are not indemnifying you for any such liability.

Terms of the Exchange Offers

On the terms and subject to the conditions set forth in this prospectus and in the accompanying letters of transmittal, we will accept for exchange in the Exchange Offers any Outstanding Notes that are validly tendered and not validly withdrawn prior to the Expiration Date. Outstanding Notes may only be tendered in minimum denominations of $2,000 and integral multiples of $1,000 in excess of $2,000, and any untendered Outstanding Notes must also be in a minimum denomination of $2,000. We will issue Exchange Notes in principal amount identical to Outstanding Notes surrendered in the Exchange Offers.

The form and terms of the Exchange Notes will be identical in all material respects to the form and terms of the Outstanding Notes of the related series except the Exchange Notes will be registered under the Securities Act, will not bear legends restricting their transfer and will not provide for any payment of additional interest upon our failure to fulfill our obligations under the registration rights agreement to complete the Exchange Offers, or file, and cause to be effective, a shelf registration statement, if required thereby, within the specified time period. The Exchange Notes will evidence the same debt as the Outstanding Notes of the related series. The Exchange Notes will be issued under and entitled to the benefits of the Indenture. For a description of the Indenture, see “Description of the Exchange Notes.”

No interest will be paid in connection with the exchange. The Exchange Notes will bear interest from the last Interest Payment Date (as defined under “Description of the Exchange Notes-Maturity; Interest”) on the Outstanding Notes surrendered in the Exchange Offers. Accordingly, the holders of Outstanding Notes that are accepted for exchange will not receive accrued but unpaid interest on Outstanding Notes at the time of tender. Rather, that interest will be payable on the Exchange Notes delivered in exchange for the Outstanding Notes on the first Interest Payment Date after the Expiration Date (as defined below under “Expiration Date, Extensions and Amendments”).

The Exchange Offers are not conditioned upon any minimum aggregate principal amount of Outstanding Notes being tendered for exchange.

As of the date of this prospectus, $400,000,000 aggregate principal amount of our 2.40% Senior Notes, Series A due 2022 and $300,000,000 aggregate principal amount of our 3.80% Senior Notes, Series B due 2047 are outstanding. This prospectus and the letters of transmittal are being sent to all registered holders of Outstanding Notes. There will

94

be no fixed record date for determining registered holders of Outstanding Notes entitled to participate in the Exchange Offers. We intend to conduct the Exchange Offers in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the rules and regulations of the SEC. Outstanding Notes that are not tendered for exchange in the Exchange Offers will remain outstanding and continue to accrue interest and will be entitled to the rights and benefits such holders have under the Indenture relating to such holders’ series of Outstanding Notes except we will not have any further obligation to you to provide for the registration of the Outstanding Notes under the registration rights agreement.

We will be deemed to have accepted for exchange properly tendered Outstanding Notes when we have given written notice of the acceptance to the Exchange Agent. The Exchange Agent will act as agent for the tendering holders for the purposes of receiving the Exchange Notes from us and delivering Exchange Notes to holders. Subject to the terms of the registration rights agreement, we expressly reserve the right to amend or terminate the Exchange Offers and to refuse to accept Exchange Notes upon the occurrence of any of the conditions specified below under “Conditions to the Exchange Offers.”

If you tender your Outstanding Notes in the Exchange Offers, you will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes with respect to the exchange of Outstanding Notes. We will pay all charges and expenses, other than certain applicable taxes described below in connection with the Exchange Offers. It is important that you read “Fees and Expenses” below for more details regarding fees and expenses incurred in the Exchange Offers.

If you are a broker-dealer and receive Exchange Notes for your own account in exchange for Outstanding Notes that you acquired as a result of market-making activities or other trading activities, you must acknowledge that you will deliver this prospectus in connection with any resale of the Exchange Notes and that you did not purchase your Outstanding Notes from us or any of our affiliates. Read “Plan of Distribution” for more details regarding the transfer of Exchange Notes.

We make no recommendation to you as to whether you should tender or refrain from tendering all or any portion of your Outstanding Notes into these Exchange Offers. In addition, no one has been authorized to make this recommendation. You must make your own decision whether to tender into these Exchange Offers and, if so, the aggregate amount of Outstanding Notes to tender after reading this prospectus and the letter of transmittal and consulting with your advisors, if any, based on your financial position and requirements.

Expiration Date, Extensions and Amendments

The Exchange Offers expire at 5:00 p.m., New York City time, on __________, 2017, which we refer to as the “Expiration Date.” However, if we, in our sole discretion, extend the period of time for which the Exchange Offers are open, the term “Expiration Date” will mean the latest time and date to which we shall have extended the expiration of the Exchange Offers.

To extend the period of time during which the Exchange Offers are open, we will notify the Exchange Agent of any extension by written notice, followed by notification by press release or other public announcement to the registered holders of the Outstanding Notes no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date. During any extension, all Outstanding Notes previously tendered and not accepted for exchange will remain subject to the applicable Exchange Offer unless validly withdrawn.

95

We also reserve the right, in our sole discretion:

• to delay accepting for exchange any Outstanding Notes (only in the case that we amend or extend the Exchange Offers);

• to extend the Expiration Date and retain all Outstanding Notes tendered in the Exchange Offers, subject to your right to withdraw your tendered Outstanding Notes as described under “Withdrawal Rights”;

• to terminate any of the Exchange Offers if we determine that any of the conditions set forth below under “Conditions to the Exchange Offers” have not been satisfied; and

• subject to the terms of the registration rights agreement, to amend the terms of any of the Exchange Offers in any manner or waive any condition to the Exchange Offers.

Any delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by written notice to the registered holders of the Outstanding Notes. If we amend any of the Exchange Offers in a manner that we determine to constitute a material change, we will promptly disclose the amendment by press release or other public announcement as required by Rule 14e-1(d) of the Exchange Act, and we will extend such Exchange Offer to the extent required by law.

In the event we terminate the Exchange Offers, all Outstanding Notes previously tendered will be returned promptly to the tendering holders.

Conditions to the Exchange Offers

Despite any other term of the Exchange Offers, we will not be required to accept for exchange, or to issue Exchange Notes in exchange for, any Outstanding Notes and we may terminate or amend any of the Exchange Offers as provided in this prospectus prior to the Expiration Date if in our reasonable judgment:

• the Exchange Offers or the making of any exchange by a holder violates any applicable law or interpretation of the SEC; or

• any action or proceeding has been instituted or threatened in writing in any court or by or before any governmental agency with respect to the Exchange Offers that, in our judgment, would reasonably be expected to impair our ability to proceed with the Exchange Offers.

In addition, we will not be obligated to accept for exchange the Outstanding Notes of any holder that has not made to us:

• the representations described under “Purpose and Effect of the Exchange Offers”; or

• any other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to make available to us an appropriate form for registration of the Exchange Notes under the Securities Act.

We expressly reserve the right at any time or at various times to extend the period of time during which the Exchange Offers are open. Consequently, we may delay acceptance of any Outstanding Notes by giving notice by press release or other public announcement as required by Rule 14e-1(d) of the Exchange Act of such extension to the holders. We will return any Outstanding Notes that we do not accept for exchange for any reason without expense to the tendering holder promptly after the expiration or termination of the Exchange Offers. We also expressly reserve the right to amend or terminate any of the Exchange Offers and to reject for exchange any Outstanding Notes not previously accepted for exchange, if we determine that any of the conditions of the Exchange Offers specified above have not been satisfied. We will give notice by press release or other public announcement as required by Rule 14e-1(d) of the Exchange Act of any extension, amendment, non-acceptance or termination to the holders of the Outstanding Notes

96

as promptly as practicable. If we amend an Exchange Offer in a manner that we determine to constitute a material change, including the waiver of a material condition, we will promptly disclose the amendment by press release or other public announcement as required by Rule 14e-1(d) of the Exchange Act and will extend the offer period if necessary so that at least five business days remain in the offer following notice of the material change. In the case of any extension, such notice will be issued no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.

We reserve the right to waive any defects, irregularities or conditions to the exchange as to particular Outstanding Notes. These conditions are for our sole benefit, and we may assert them regardless of the circumstances that may give rise to them or waive them in whole or in part at any or at various times prior to the expiration of the Exchange Offers in our sole discretion. If we fail at any time to exercise any of the foregoing rights, this failure will not constitute a waiver of such right. Each such right will be deemed an ongoing right that we may assert at any time or at various times prior to the expiration of the Exchange Offers.

In addition, we will not accept for exchange any Outstanding Notes tendered, and will not issue Exchange Notes in exchange for any such Outstanding Notes, if at such time any stop order is threatened or in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the Indenture under the Trust Indenture Act of 1939, as amended.

Procedures for Tendering Outstanding Notes

To tender your Outstanding Notes in the Exchange Offers, you must comply with either of the following:

• complete, sign and date the letter of transmittal, or a facsimile of the letter of transmittal, have the signature(s) on the letter of transmittal guaranteed if required by the letter of transmittal and mail or deliver such letter of transmittal or facsimile thereof to the Exchange Agent at the address set forth below under “Exchange Agent” prior to the Expiration Date; or

• comply with DTC’s Automated Tender Offer Program procedures described below.

In addition:

• the Exchange Agent must receive certificates for Outstanding Notes along with the letter of transmittal prior to the expiration of the Exchange Offers;

• the Exchange Agent must receive a timely confirmation of book-entry transfer of Outstanding Notes into the Exchange Agent’s account at DTC according to the procedures for book-entry transfer described below and a properly transmitted Agent’s Message (defined below) prior to the expiration of the Exchange Offers; or

• you must comply with the guaranteed delivery procedures described below.

The term “Agent’s Message” means a message transmitted by DTC, received by the Exchange Agent and forming part of the book-entry confirmation, which states that:

• DTC has received an express acknowledgment from a participant in its Automated Tender Offer Program that is tendering Outstanding Notes that are the subject of the book-entry confirmation;

• the participant has received and agrees to be bound by the terms of the letter of transmittal or, in the case of an Agent’s Message relating to guaranteed delivery, that such participant has received and agrees to be bound by the notice of guaranteed delivery; and

• we may enforce that agreement against such participant. DTC is referred to herein as a “book-entry transfer facility.”

97

Your tender, if not withdrawn prior to the expiration of the Exchange Offers, constitutes an agreement between us and you upon the terms and subject to the conditions described in this prospectus and in the letter of transmittal.

The method of delivery of Outstanding Notes, letters of transmittal and all other required documents to the Exchange Agent is at your election and risk. Delivery of such documents will be deemed made only when actually received by the Exchange Agent. We recommend that instead of delivery by mail, you use an overnight or hand delivery service, properly insured. If you determine to make delivery by mail, we suggest that you use properly insured, registered mail with return receipt requested. In all cases, you should allow sufficient time to assure timely delivery to the Exchange Agent before the expiration of the Exchange Offers. Letters of transmittal and certificates representing Outstanding Notes should be sent only to the Exchange Agent, and not to us or to DTC or any other book-entry transfer facility. No alternative, conditional or contingent tenders of Outstanding Notes will be accepted, except as described below under “Guaranteed Delivery Procedures.” You may request that your broker, dealer, commercial bank, trust company or nominee effect the above transactions for you.

If you are a beneficial owner whose Outstanding Notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your Outstanding Notes, you should promptly contact the registered holder and instruct the registered holder to tender on your behalf. If you wish to tender the Outstanding Notes yourself, you must, prior to completing and executing the letter of transmittal and delivering your Outstanding Notes, either:

• make appropriate arrangements to register ownership of the Outstanding Notes in your name; or

• obtain a properly completed bond power from the registered holder of Outstanding Notes.

The transfer of registered ownership may take considerable time and may not be able to be completed prior to the expiration of the Exchange Offers.

Signatures on the letter of transmittal or a notice of withdrawal (as described below in “Withdrawal Rights”), as the case may be, must be guaranteed by a member firm of a registered national securities exchange or of the Financial Industry Regulatory Authority, a commercial bank or trust company having an office or correspondent in the United States or another “eligible guarantor institution” within the meaning of Rule 17A(d)-15 under the Exchange Act unless the Outstanding Notes surrendered for exchange are tendered:

• by a registered holder of the Outstanding Notes who has not completed the box entitled “Special Registration Instructions” or “Special Delivery Instructions” on the letter of transmittal; or

• for the account of an eligible guarantor institution.

If the letter of transmittal is signed by a person other than the registered holder of any Outstanding Notes listed on the Outstanding Notes, such Outstanding Notes must be endorsed or accompanied by a properly completed bond power. The bond power must be signed by the registered holder as the registered holder’s name appears on the Outstanding Notes, and an eligible guarantor institution must guarantee the signature on the bond power.

If the letter of transmittal, any certificates representing Outstanding Notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, those persons should also indicate when signing and, unless waived by us, they should also submit evidence satisfactory to us of their authority to so act.

The Exchange Agent and DTC have confirmed that any financial institution that is a participant in DTC’s system may use DTC’s Automated Tender Offer Program to tender Outstanding Notes. Participants in the program may, instead of physically completing and signing the letter of transmittal and delivering it to the Exchange Agent, electronically transmit their acceptance of Outstanding Notes for exchange by causing DTC to transfer the Outstanding Notes to the Exchange Agent in accordance with DTC’s Automated Tender Offer Program procedures for transfer. DTC will then send an Agent’s Message to the Exchange Agent.

98

Book-Entry Delivery Procedures

Any financial institution that is a participant in the book-entry transfer facility’s system may make book-entry delivery of the Outstanding Notes by causing the book-entry transfer facility to transfer those Outstanding Notes into the Exchange Agent’s account at the facility in accordance with the facility’s procedures for such transfer. To be timely, book-entry delivery of Outstanding Notes requires receipt of a confirmation of a book-entry transfer, or a “book-entry confirmation,” prior to the Expiration Date.

In addition, in order to receive Exchange Notes for tendered Outstanding Notes, an Agent’s Message in connection with a book-entry transfer into the Exchange Agent’s account at the book-entry transfer facility or the letter of transmittal or a manually signed facsimile thereof, together with any required signature guarantees and any other required documents must be delivered or transmitted to and received by the Exchange Agent at its address set forth on the cover page of the letter of transmittal prior to the expiration of the Exchange Offers. Holders of Outstanding Notes who are unable to deliver confirmation of the book-entry tender of their Outstanding Notes into the Exchange Agent’s account at the book-entry transfer facility or an Agent’s Message or a letter of transmittal or a manually signed facsimile thereof in lieu thereof and all other documents required by the letter of transmittal to the Exchange Agent prior to the expiration of the Exchange Offers must tender their Outstanding Notes according to the guaranteed delivery procedures described below. Tender will not be deemed made until such documents are received by the Exchange Agent. Delivery of documents to the book-entry transfer facility does not constitute delivery to the Exchange Agent.

Guaranteed Delivery Procedures

If you wish to tender your Outstanding Notes but your Outstanding Notes are not immediately available or you cannot deliver your Outstanding Notes, the letter of transmittal or any other required documents to the Exchange Agent or comply with the procedures under DTC’s Automatic Tender Offer Program in the case of Outstanding Notes, prior to the Expiration Date, you may still tender if:

• the tender is made through an eligible guarantor institution;

• prior to the Expiration Date, the Exchange Agent receives from such eligible guarantor institution either a properly completed and duly executed notice of guaranteed delivery, by facsimile transmission, mail, or hand delivery or a properly transmitted Agent’s Message and notice of guaranteed delivery, that (1) sets forth your name and address, the certificate number(s) of such Outstanding Notes and the principal amount of Outstanding Notes tendered; (2) states that the tender is being made thereby; and (3) guarantees that, within three New York Stock Exchange trading days after the Expiration Date, the letter of transmittal, or facsimile thereof, together with the Outstanding Notes or a book-entry confirmation (including an Agent’s Message), and any other documents required by the letter of transmittal, will be deposited by the eligible guarantor institution with, or transmitted by the eligible guarantor to, the Exchange Agent; and

• the Exchange Agent receives the properly completed and executed letter of transmittal or facsimile thereof, with any required signature guarantees, as well as certificate(s) representing all tendered Outstanding Notes in proper form for transfer or a book-entry confirmation of transfer of the Outstanding Notes (including an Agent’s Message) into the Exchange Agent’s account at DTC and all other documents required by the letter of transmittal within three New York Stock Exchange trading days after the Expiration Date.

Upon request, the Exchange Agent will send to you a notice of guaranteed delivery if you wish to tender your Outstanding Notes according to the guaranteed delivery procedures.

Acceptance of Outstanding Notes for Exchange

In all cases, we will promptly issue Exchange Notes of the applicable series for Outstanding Notes that we have accepted for exchange under the Exchange Offers only after the Exchange Agent timely receives:

99

• Outstanding Notes or a timely book-entry confirmation of such Outstanding Notes into the Exchange Agent’s account at the book-entry transfer facility; and

• a properly completed and duly executed letter of transmittal and all other required documents or a properly transmitted Agent’s Message.

In addition, each broker-dealer that is to receive Exchange Notes for its own account in exchange for Outstanding Notes must represent that such Outstanding Notes were acquired by that broker-dealer as a result of market-making activities or other trading activities and must acknowledge that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the Exchange Notes. The letters of transmittal state that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. See “Plan of Distribution.”

We will interpret the terms and conditions of the Exchange Offers, including the letters of transmittal and the instructions to the letters of transmittal, and will resolve all questions as to the validity, form, eligibility, including time of receipt, and acceptance of Outstanding Notes tendered for exchange. Our determinations in this regard will be final and binding on all parties. We reserve the absolute right to reject any and all tenders of any particular Outstanding Notes not properly tendered or to not accept any particular Outstanding Notes if the acceptance might, in our or our counsel’s judgment, be unlawful. We also reserve the right to waive any defects or irregularities as to any particular Outstanding Notes prior to the expiration of the Exchange Offers.

Unless waived, any defects or irregularities in connection with tenders of Outstanding Notes for exchange must be cured within such reasonable period of time as we determine. Neither the Company, the Exchange Agent nor any other person will be under any duty to give notification of any defect or irregularity with respect to any tender of Outstanding Notes for exchange, nor will any of them incur any liability for any failure to give notification. Any certificates representing Outstanding Notes received by the Exchange Agent that are not properly tendered and as to which the irregularities have not been cured or waived will be returned by the Exchange Agent to the tendering holder, unless otherwise provided in the letter of transmittal, promptly after the expiration or termination of the Exchange Offers.

Withdrawal Rights

Except as otherwise provided in this prospectus, you may withdraw your tender of Outstanding Notes at any time prior to 5:00 p.m., New York City time, on the Expiration Date.

For a withdrawal to be effective:

• the Exchange Agent must receive a written notice, which may be by facsimile or letter, of withdrawal at its address set forth below under “Exchange Agent”; or

• you must comply with the appropriate procedures of DTC’s Automated Tender Offer Program system for such withdrawal.

Any notice of withdrawal must:

• specify the name of the person who tendered the Outstanding Notes to be withdrawn;

• identify the Outstanding Notes to be withdrawn, including the certificate numbers and principal amount of the Outstanding Notes; and

• where certificates for Outstanding Notes have been transmitted, specify the name in which such Outstanding Notes were registered, if different from that of the withdrawing holder.

100

If certificates for Outstanding Notes have been delivered or otherwise identified to the Exchange Agent, then, prior to the release of such certificates, you must also submit:

• the serial numbers of the particular certificates to be withdrawn; and

• a signed notice of withdrawal with signatures guaranteed by an eligible institution unless you are an eligible guarantor institution.

If Outstanding Notes have been tendered pursuant to the procedures for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at the book-entry transfer facility to be credited with the withdrawn Outstanding Notes and otherwise comply with the procedures of the facility. We will determine all questions as to the validity, form and eligibility, including time of receipt of notices of withdrawal, and our determination will be final and binding on all parties. Any Outstanding Notes so withdrawn will be deemed not to have been validly tendered for exchange for purposes of the Exchange Offers. Any Outstanding Notes that have been tendered for exchange but that are not exchanged for any reason will be returned to their holder, without cost to the holder, or, in the case of book-entry transfer, the Outstanding Notes will be credited to an account at the book-entry transfer facility, promptly after withdrawal, rejection of tender or termination of the Exchange Offers. Properly withdrawn Outstanding Notes may be retendered by following the procedures described under “-Procedures for Tendering Outstanding Notes” above at any time prior to the expiration of the Exchange Offers.

Exchange Agent

The Bank of New York Mellon Trust Company, N.A. has been appointed as the Exchange Agent for the Exchange Offers. The Bank of New York Mellon Trust Company, N.A. also acts as trustee under the Indenture. You should direct all executed letters of transmittal and all questions and requests for assistance with respect to accepting or withdrawing from the Exchange Offers, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery to the Exchange Agent addressed as follows:

By Mail, Hand or Courier
The Bank of New York Mellon Trust Company, N.A., as Exchange Agent c/o The Bank of New York Mellon Corporation Corporate Trust Operations-Reorganization Unit 111 Sanders Creek Parkway East Syracuse, NY 13057 Attn: Eric Herr Tel: 315-414-3362 By Facsimile Transmission (eligible institutions only)
(732) 667-9408
To Confirm by Telephone
(315) 414-3349
Email: CT_REORG_UNIT_INQUIRIES @BNYMELLON.COM

If you deliver the letter of transmittal to an address other than the one set forth above or transmit instructions via facsimile to a number other than the one set forth above, that delivery or those instructions will not be effective.

Fees and Expenses

The registration rights agreement provides that we will bear all expenses in connection with the performance of our obligations relating to the registration of the Exchange Notes and the conduct of the Exchange Offers. These expenses include registration and filing fees, accounting and legal fees and printing costs, among others. We will pay the Exchange Agent reasonable and customary fees for its services and reasonable out-of-pocket expenses. We will also reimburse brokerage houses and other custodians, nominees and fiduciaries for customary mailing and handling expenses incurred by them in forwarding this prospectus and related documents to their clients that are holders of Outstanding Notes and for handling or tendering for such clients.

We have not retained any dealer-manager in connection with the Exchange Offers and will not pay any fee or commission to any broker, dealer, nominee or other person for soliciting tenders of Outstanding Notes pursuant to the Exchange Offers.

101

Accounting Treatment

We will record the Exchange Notes in our accounting records at the same carrying value as the Outstanding Notes, which is the aggregate principal amount as reflected in our accounting records on the date of exchanges. Accordingly, we will not recognize any gain or loss for accounting purposes upon the consummation of the Exchange Offers. We will record the costs of the Exchange Offers as incurred.

Transfer Taxes

We will pay all transfer taxes, if any, applicable to the exchanges of Outstanding Notes under the Exchange Offers. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if:

• certificates representing Outstanding Notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be issued in the name of, any person other than the registered holder of Outstanding Notes tendered;

• tendered Outstanding Notes are registered in the name of any person other than the person signing the letter of transmittal; or

• a transfer tax is imposed for any reason other than the exchange of Outstanding Notes under the Exchange Offers.

If satisfactory evidence of payment of such taxes is not submitted with the letter of transmittal, the amount of such transfer taxes will be billed to that tendering holder.

Holders who tender their Outstanding Notes for exchange will not be required to pay any transfer taxes. However, holders who instruct us to register Exchange Notes in the name of, or request that Outstanding Notes not tendered or not accepted in the Exchange Offers be returned to, a person other than the registered tendering holder will be required to pay any applicable transfer tax.

Consequences of Failure to Exchange

If you do not exchange your Outstanding Notes for Exchange Notes under the Exchange Offers, your Outstanding Notes will remain subject to the restrictions on transfer of such Outstanding Notes:

• as set forth in the legend printed on the Outstanding Notes as a consequence of the issuance of the Outstanding Notes pursuant to the exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws; and

• as otherwise set forth in the offering memorandum distributed in connection with the private offerings of the Outstanding Notes.

In general, you may not offer or sell your Outstanding Notes unless they are registered under the Securities Act or if the offer or sale is exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the Outstanding Notes under the Securities Act.

102

Other

Participating in the Exchange Offers is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered Outstanding Notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any Outstanding Notes that are not tendered in the Exchange Offers or to file a registration statement to permit resales of any untendered Outstanding Notes.

103

DESCRIPTION OF THE EXCHANGE NOTES

The following summary description sets forth certain terms and provisions of the Exchange Notes. Because this description is a summary, it does not describe every aspect of the Exchange Notes or the Indenture (as defined below) under which the Exchange Notes will be issued, and which is filed as an exhibit to the registration statement of which this prospectus is a part. The Indenture and its associated documents contain the full legal text of the matters described in this section. This summary is subject to and qualified in its entirety by reference to all of the provisions of the Exchange Notes and the Indenture, including definitions of certain terms used in the Indenture. We also include references in parentheses to certain sections of the Indenture. Whenever we refer to particular sections or defined terms of the Indenture in this prospectus, such sections or defined terms are incorporated by reference herein.

General

The form and terms of the Exchange Notes are identical in all material respects to the form and terms of the Outstanding Notes except the Exchange Notes will:

• be registered under the Securities Act;

• not be subject to the restrictions on transfer applicable to the Outstanding Notes (except for the limited restrictions described under “Form; Transfers and Exchanges”);

• not be entitled to any registration rights that are applicable to the Outstanding Notes under the registration rights agreement, including any right to additional interest; and

• bear different CUSIP numbers.

We will issue the Exchange Notes under an indenture dated as of September 1, 2017 between us and The Bank of New York Mellon Trust Company, N.A., as trustee, as supplemented by supplemental indentures or company orders (the “Indenture”). This prospectus briefly outlines some provisions of the Indenture. If you would like more information on these provisions, you should review the Indenture and any supplemental indentures or company orders. See “AVAILABLE INFORMATION” on how to locate these documents.

The Indenture does not limit the amount of notes that may be issued. The Indenture permits us to issue notes in one or more series or tranches upon the approval of our board of directors and as provided in one or more company orders or supplemental indentures. Each series of notes may differ as to their terms. We may from time to time, without consent of the holders of the Exchange Notes, issue additional notes having the same ranking, interest rate, maturity and other terms as the Exchange Notes (except for the issue date and the issue price). These additional notes, together with the Exchange Notes, will be a single series of notes under the Indenture.

The Exchange Notes are our senior unsecured obligations and will rank equally with our senior unsecured obligations. As of November 1, 2017, we had no secured indebtedness outstanding.

The Exchange Notes will be denominated in U.S. dollars and we will pay principal and interest in U.S. dollars. The Exchange Notes of each series will be issuable in minimum denominations of $2,000 and in multiples of $1,000 in excess thereof. The Exchange Notes will not be subject to any conversion, amortization or sinking fund.

The Exchange Notes will not be guaranteed by, or otherwise be obligations of, AEP or any of its direct or indirect subsidiaries other than AEP Texas.

104

Principal Amount, Maturity and Interest

The 2022 Exchange Notes will be initially issued in aggregate principal amount of $400,000,000 and the 2047 Exchange Notes will be initially issued in aggregate principal amount of $300,000,000.

The 2022 Exchange Notes will mature and become due and payable, together with any accrued and unpaid interest, on October 1, 2022 and will bear interest at the rate of 2.40% per annum from September 22, 2017 until October 1, 2022. The 2047 Exchange Notes will mature and become due and payable, together with any accrued and unpaid interest, on October 1, 2047 and will bear interest at the rate of 3.80% per annum from September 22, 2017 until October 1, 2047.

Interest on each note will be payable semi-annually in arrears on each April 1 and October 1 and at redemption, if any, or maturity. The initial interest payment date is April 1, 2018. Each payment of interest shall include interest accrued through the day before such interest payment date. Interest on the Exchange Notes will be computed on the basis of a 360-day year consisting of twelve 30-day months.

We will pay interest on the Exchange Notes of each series (other than interest payable at redemption, if any, or maturity) in immediately available funds to the owners of the Exchange Notes as of the Regular Record Date (as defined below) for each interest payment date. We will pay the principal of the Exchange Notes and any premium and interest payable at redemption, if any, or maturity in immediately available funds at the office of the Trustee at 2 North LaSalle Street, 7^th Floor, Chicago, Illinois 60602.

If any interest payment date, redemption date or the maturity is not a Business Day (as defined below), we will pay all amounts due on the next succeeding Business Day and no additional interest will be paid.

The “Regular Record Date” will be the March 15 or September 15 prior to the relevant interest payment date, whether or not such day is a Business Day.

“Business Day” means any day that is not a day on which banking institutions in New York City are authorized or required by law or regulation to close.

Optional Redemption

We may redeem any or all series of the Exchange Notes in whole or in part by delivering written notice to the noteholders no more than 60, and not less than 30, days prior to redemption. If we do not redeem all the Exchange Notes of a series at one time, the Trustee will select the Exchange Notes to be redeemed in a manner it determines to be fair, provided that if the Exchange Notes are represented by one or more global notes, the Exchange Notes to be redeemed will be selected in accordance with the procedures of DTC.

At any time prior to September 1, 2022, we may redeem the 2022 Exchange Notes either as a whole or in part at a redemption price equal to the greater of (1) 100% of the principal amount of the 2022 Exchange Notes being redeemed and (2) the sum of the present values of the remaining scheduled payments of principal and interest on the 2022 Exchange Notes being redeemed that would be due if such 2022 Exchange Notes matured on September 1, 2022 (excluding the portion of any such interest accrued to, but excluding, the date of redemption), discounted (for purposes of determining present value) to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined below) plus 10 basis points, plus, in each case, accrued and unpaid interest thereon to, but excluding, the date of redemption.

At any time prior to April 1, 2047, we may redeem the 2047 Exchange Notes either as a whole or in part at a redemption price equal to the greater of (1) 100% of the principal amount of the 2047 Exchange Notes being redeemed and (2) the sum of the present values of the remaining scheduled payments of principal and interest on the 2047 Exchange Notes being redeemed that would be due if such 2047 Exchange Notes matured on April 1, 2047 (excluding the portion of any such interest accrued to, but excluding, the date of redemption), discounted (for purposes of determining present value) to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve

105

30-day months) at the Treasury Rate (as defined below) plus 20 basis points, plus, in each case, accrued and unpaid interest thereon to, but excluding, the date of redemption.

At any time on or after September 1, 2022, we may redeem the 2022 Exchange Notes in whole or in part at 100% of the principal amount of the 2022 Exchange Notes being redeemed, plus accrued and unpaid interest thereon to but excluding the date of redemption. At any time on or after April 1, 2047, we may redeem the 2047 Exchange Notes in whole or in part at 100% of the principal amount of the 2047 Exchange Notes being redeemed, plus accrued and unpaid interest thereon to but excluding the date of redemption.

“Comparable Treasury Issue,” applicable to each series, means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term (“remaining life”) of the Exchange Notes (assuming, for this purpose, that the 2022 Exchange Notes matured on September 1, 2022 and the 2047 Exchange Notes matured on April 1, 2047) that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining life of the Exchange Notes.

“Comparable Treasury Price,” applicable to each series, means, with respect to any redemption date, (1) the average of the Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest of such Reference Treasury Dealer Quotations, or (2) if we obtain fewer than four of such Reference Treasury Dealer Quotations, the average of all such quotations.

“Independent Investment Banker” means one of the Reference Treasury Dealers appointed by us and notified by usto the Trustee.

“Reference Treasury Dealer” means a primary U.S. Government securities dealer or dealers selected by us and notified by us to the Trustee.

“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by us and notified to the Trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to us andthe Trustee by such Reference Treasury Dealer at or before 3:30 p.m., New York City time, on the third Business Day preceding such redemption date.

“Treasury Rate” means, with respect to any redemption, the rate per annum equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, calculated using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date.

Agreement to Provide Information

So long as any Exchange Notes are outstanding under the Indenture, during such periods as we are not subject to the periodic reporting requirements of Section 13 or 15(d) of the Exchange Act, we will furnish to prospective purchasers of the Notes, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act for compliance with Rule 144A.

Consolidation, Merger or Sale

We may merge or consolidate with any corporation or sell all or substantially all of our assets as an entirety as long as the successor or purchaser of such assets expressly assumes the payment of principal, and premium, if any, and interest on the Notes.

106

Limitation on Secured Debt

So long as any of the Notes are outstanding, we will not create or permit to be created or to exist any additional mortgage, pledge, security interest, or other lien (collectively, “Liens”) on any of our utility properties or tangible assets now owned or hereafter acquired to secure any indebtedness for borrowed money (“Secured Debt”), without providing that the outstanding Notes will be similarly secured. This restriction does not apply to our subsidiaries, nor will it prevent any of them from creating or permitting to exist Liens on their property or assets to secure any secured debt. In addition, this restriction does not prevent the creation or existence of:

• Liens on property existing at the time of acquisition or construction of such property (or created within one year after completion of such acquisition or construction), whether by purchase, merger, construction or otherwise, or to secure the payment of all or any part of the purchase price or construction cost thereof, including the extension of any Liens to repairs, renewals, replacements substitutions, betterments, additions, extensions and improvements then or thereafter made on the property subject thereto;

• Financing of our accounts receivable for electric service;

• Any extensions, renewals or replacements (or successive extensions, renewals or replacements), in whole or in part, of Liens permitted by the foregoing clauses;

• The pledge of any bonds or other securities at any time issued under any of the Secured Debt permitted by the above clauses; and

• the creation or existence of leases (operating or capital) made, or existing on property acquired, in the ordinary course of business.

In addition to the permitted issuances above, Secured Debt not otherwise so permitted may be issued; provided that amount of such Secured Debt that does not exceed 15% of Net Tangible Assets as defined below.

“Net Tangible Assets” means the total of all assets (including revaluations thereof as a result of commercial appraisals, price level restatement or otherwise) appearing on our balance sheet, net of applicable reserves and deductions, but excluding goodwill, trade names, trademarks, patents, unamortized debt discount, energy trading contracts, regulatory assets, deferred charges and all other like intangible assets (which term shall not be construed to include such revaluations), less the aggregate of our current liabilities appearing on such balance sheet. For purposes of this definition, our balance sheet does not include assets and liabilities of our subsidiaries.

Restrictions on Transfer

The Notes will be subject to restrictions on transfer and will bear a restrictive legend substantially as described in “NOTICE TO INVESTORS.”

Events of Default

“Event of Default” means, with respect to any particular series of notes, any of the following:

• failure to pay for three Business Days the principal of (or premium, if any, on) any note of that series when due and payable;

• failure to pay for 30 days any interest on any note of that series when due and payable;

• failure to perform any other requirements in any notes of that series, or in the Indenture in regard to such notes, for 90 days after notice; or

• certain events of bankruptcy or insolvency.

107

An Event of Default for a particular series of notes does not necessarily mean that an Event of Default has occurred for any other series of notes issued under the Indenture. If an Event of Default occurs and continues, the Trustee or the holders of at least 33% of the principal amount of the notes of the series affected may require us to repay the entire principal of the notes of such series immediately (Repayment Acceleration). In most instances, the holders of at least a majority in aggregate principal amount of the notes of the affected series may rescind a previously triggered Repayment Acceleration. However, if we cause an Event of Default because we have failed to pay (unaccelerated) principal, premium, if any, or interest, Repayment Acceleration may be rescinded only if we have first cured our default by depositing with the Trustee enough money to pay all (unaccelerated) past due amounts and penalties, if any.

The Trustee must within 90 days after a default occurs, notify the holders of the notes of the series of default unless such default has been cured or waived. We are required to file an annual certificate with the Trustee, signed by an officer, concerning our compliance with the conditions and covenants of the Indenture and specifying any default by us under any provisions of the Indenture.

Subject to the provisions of the Indenture relating to its duties in case of default, the Trustee shall be under no obligation to exercise any of its rights or powers under the Indenture at the request, order or direction of any holders unless such holders offer the Trustee indemnity satisfactory to the Trustee. Subject to the provisions of the Indenture, the holders of a majority in principal amount of the notes of any series may direct the time, method and place of conducting any proceedings for any remedy available to, or exercising any trust or power conferred on, the Trustee with respect to such notes.

Modification of Indenture

Under the Indenture, our rights and obligations and the rights of the holders of any notes may be changed. Any change affecting the rights of the holders of any series of notes requires the consent of the holders of not less than a majority in aggregate principal amount of the outstanding Notes of all series affected by the change, voting as one class. However, we cannot change the terms of payment of principal or interest, or a reduction in the percentage required for changes or a waiver of default, unless the affected holders consent. We may issue additional series of notes and take other action that does not affect the rights of holders of any series by executing supplemental indentures without the consent of any noteholders.

Legal Defeasance

We will be discharged from our obligations on the Notes, including the Exchange Notes, of any series at any time if:

• we deposit with the Trustee sufficient cash or government securities to pay the principal, interest, any premium and any other sums due to the stated maturity date or a redemption date of the Notes of the series,

• immediately after such deposit, no default exists, and

• we deliver to the Trustee an opinion of counsel, who may be an employee of, or counsel for, the Company, stating that the United States federal income tax obligations of noteholders of that series will not change as a result of our performing the action described above, with such opinion based upon a ruling of the Internal Revenue Service (“IRS”) issued to us or a change of law or regulation occurring after September 19, 2017.

If this happens, the noteholders of the series will not be entitled to the benefits of the Indenture except for registration of transfer and exchange of Notes and replacement of lost, stolen or mutilated Notes.

108

Covenant Defeasance

We will be discharged from our obligations under any restrictive covenant applicable to the Notes of a particular series if:

• we deposit with the Trustee cash or government securities sufficient to pay the principal, interest and any premium due on or prior to maturity,

• immediately after such deposit, no default exists, and

• we deliver to the Trustee an opinion of counsel, who may be an employee of, or counsel for, the Company, stating that the United States federal income tax obligations of noteholders of that series will not change as a result of our performing the action described above.

If this happens, any later breach of that particular restrictive covenant will not result in Repayment Acceleration. If we cause an Event of Default apart from breaching that restrictive covenant, there may not be sufficient money or government obligations on deposit with the Trustee to pay all amounts due on the Notes of that series. In that instance, we would remain liable for such amounts.

Governing Law

The Indenture and Exchange Notes will be governed by the laws of the State of New York.

Concerning the Trustee

We and our affiliates use or will use some of the banking services of the Trustee and other services of its affiliates in the normal course of business.

Book-Entry Only Issuance-The Depository Trust Company

DTC will act as the initial securities depository for the Exchange Notes. The Exchange Notes issued in exchange for Outstanding Notes will be issued as fully-registered securities registered in the name of Cede & Co. (DTC’s partnership nominee) or such other name as may be requested by an authorized representative of DTC. One fully-registered note certificate will be issued for each issue of the Exchange Notes, each in the aggregate principal amount of such issue, and will be deposited with DTC.

DTC, the world’s largest securities depository, is a limited-purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code, and a “clearing agency” registered pursuant to the provisions of Section 17A of the Securities Exchange Act of 1934, as amended. DTC holds and provides asset servicing for over 3.5 million issues of U.S. and non-U.S. equity issues, corporate and municipal debt issues, and money market instruments (from over 100 countries) that DTC’s participants (“Direct Participants”) deposit with DTC. DTC also facilitates the post-trade settlement among Direct Participants of sales and other securities transactions in deposited securities, through electronic computerized book-entry transfers and pledges between Direct Participants’ accounts. This eliminates the need for physical movement of securities certificates. Direct Participants include both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, clearing corporations, and certain other organizations. DTC is a wholly-owned subsidiary of The Depository Trust & Clearing Corporation (“DTCC”). DTCC is the holding company for DTC, National Securities Clearing Corporation and Fixed Income Clearing Corporation, all of which are registered clearing agencies. DTCC is owned by the users of its regulated subsidiaries. Access to the DTC system is also available to others such as both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, and clearing corporations that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly (“Indirect Participants”). The DTC Rules applicable to its Participants are on file with the SEC. More information about DTC can be found at www.dtcc.com. The contents of such website do not constitute part of this prospectus.

109

Purchases of Exchange Notes under the DTC system must be made by or through Direct Participants, which will receive a credit for the Exchange Notes on DTC’s records. The ownership interest of each actual purchaser of each note (“Beneficial Owner”) is in turn to be recorded on the Direct and Indirect Participants’ records. Beneficial Owners will not receive written confirmation from DTC of their purchase. Beneficial Owners are, however, expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the Direct or Indirect Participant through which the Beneficial Owner entered into the transaction. Transfers of ownership interests in the Exchange Notes are to be accomplished by entries made on the books of Direct and Indirect Participants acting on behalf of Beneficial Owners. Beneficial Owners will not receive certificates representing their ownership interests in Exchange Notes, except in the event that use of the book-entry system for the Exchange Notes is discontinued.

To facilitate subsequent transfers, all Exchange Notes deposited by Direct Participants with DTC are registered in the name of DTC’s partnership nominee, Cede & Co., or such other name as may be requested by an authorized representative of DTC. The deposit of Exchange Notes with DTC and their registration in the name of Cede & Co. or such other DTC nominee do not effect any change in beneficial ownership. DTC has no knowledge of the actual Beneficial Owners of the Exchange Notes; DTC’s records reflect only the identity of the Direct Participants to whose accounts such Exchange Notes are credited, which may or may not be the Beneficial Owners. The Direct and Indirect Participants will remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by DTC to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to Beneficial Owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time. Beneficial Owners of Exchange Notes may wish to take certain steps to augment the transmission to them of notices of significant events with respect to the Exchange Notes, such as redemptions, tenders, defaults, and proposed amendments to the Exchange Notes documents. For example, Beneficial Owners of Exchange Notes may wish to ascertain that the nominee holding the Exchange Notes for their benefit has agreed to obtain and transmit notices to Beneficial Owners. In the alternative, Beneficial Owners may wish to provide their names and addresses to the registrar and request that copies of notices be provided directly to them.

Redemption notices shall be sent to DTC. If less than all of the Exchange Notes are being redeemed, DTC’s practice is to determine by lot the amount of the interest of each Direct Participant in such issue to be redeemed.

Neither DTC nor Cede & Co. (nor any other DTC nominee) will consent or vote with respect to the Exchange Notes unless authorized by a Direct Participant in accordance with DTC’s MMI Procedures. Under its usual procedures, DTC mails an Omnibus Proxy to us as soon as possible after the record date. The Omnibus Proxy assigns Cede & Co.’s consenting or voting rights to those Direct Participants to whose accounts the Exchange Notes are credited on the record date (identified in a listing attached to the Omnibus Proxy).

Redemption proceeds and distributions on the Exchange Notes will be made to Cede & Co., or such other nominee as may be requested by an authorized representative of DTC. DTC’s practice is to credit Direct Participants’ accounts upon DTC’s receipt of funds and corresponding detail information from us or the Trustee on the payable date in accordance with their respective holdings shown on DTC’s records. Payments by Participants to Beneficial Owners will be governed by standing instructions and customary practices, as is the case with Exchange Notes held for the accounts of customers in bearer form or registered in “street name”, and will be the responsibility of such Participant and not of DTC, the Trustee or us, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment of redemption proceeds and distributions to Cede & Co. (or such other nominee as may be requested by an authorized representative of DTC) is our or the Trustee’s responsibility, disbursement of such payments to Direct Participants will be the responsibility of DTC, and disbursement of such payments to the Beneficial Owners will be the responsibility of Direct and Indirect Participants.

A Beneficial Owner shall give notice to elect to have its Exchange Notes purchased or tendered, through its Participant, to the Tender/Remarketing Agent, and shall effect delivery of such Exchange Notes by causing the Direct Participant to transfer the Participant’s interest in the Exchange Notes, on DTC’s records, to the Tender/Remarketing Agent. The requirement for physical delivery of the Exchange Notes in connection with an optional tender or a mandatory purchase will be deemed satisfied when the ownership rights in the Exchange Notes are transferred by

110

Direct Participants on DTC’s records and followed by a book-entry credit of tendered Exchange Notes to the Tender/Remarketing Agent’s DTC account.

DTC may discontinue providing its services as depository with respect to the Exchange Notes at any time by giving reasonable notice to us. Under such circumstances, in the event that a successor depository is not obtained, note certificates are required to be printed and delivered.

We may decide to discontinue use of the system of book-entry only transfers through DTC (or a successor securities depository). In that event, note certificates will be printed and delivered to DTC.

The information in this section concerning DTC and DTC’s book-entry system has been obtained from sources that we believe to be reliable, but we take no responsibility for the accuracy thereof.

111

MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES OF THE EXCHANGE OFFERS

The exchange of Outstanding Notes for Exchange Notes of the corresponding series in the Exchange Offers will not constitute a taxable event to holders for United States federal income tax purposes. Consequently, no gain or loss will be recognized by a holder upon receipt of an Exchange Note, the holding period of the Exchange Note will include the holding period of the Outstanding Note exchanged therefor and the basis of the Exchange Note will be the same as the basis of the Outstanding Note immediately before the exchange.

In any event, persons considering the exchange of Outstanding Notes for Exchange Notes should consult their own tax advisors concerning the United States federal income tax consequences in light of their particular situations as well as any consequences arising under the laws of any other taxing jurisdiction.

PLAN OF DISTRIBUTION

Each broker-dealer that receives Exchange Notes for its own account pursuant to the Exchange Offers must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Notes received in exchange for Outstanding Notes where such Outstanding Notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the Expiration Date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, all dealers effecting transactions in the Exchange Notes may be required to deliver a prospectus.

We will not receive any proceeds from any sale of Exchange Notes by broker-dealers. Exchange Notes received by broker-dealers for their own account pursuant to the Exchange Offers may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the Exchange Notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer and/or the purchasers of any such Exchange Notes. Any broker-dealer that resells Exchange Notes that were received by it for its own account pursuant to the Exchange Offers and any broker or dealer that participates in a distribution of such Exchange Notes may be deemed to be an “underwriter” within the meaning of the Securities Act, and any profit on any such resale of Exchange Notes and any commission or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of 180 days after the Expiration Date, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. Subject to certain limitations set forth in the registration rights agreement, we have agreed to pay all expenses incident to the Exchange Offers (including the expenses of one counsel for the holders of the Outstanding Notes) other than commissions or concessions of any brokers or dealers and will indemnify you (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

LEGAL MATTERS

Thomas G. Berkemeyer or William E. Johnson, Associate General Counsel and Senior Counsel, respectively, of American Electric Power Service Corporation, our service company affiliate, will issue an opinion about the legality of the Exchange Notes for us.

EXPERTS

The consolidated financial statements included in this Prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein.  Such consolidated

112

financial statements are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

AVAILABLE INFORMATION

We have filed with the SEC a registration statement on Form S-4 under the Securities Act with respect to the Exchange Notes. This prospectus, which forms a part of the registration statement, does not contain all of the information set forth in the registration statement. For further information with respect to us and the Exchange Notes, reference is made to the registration statement. Statements contained in this prospectus as to the contents of any contract or other document are not complete.

We have agreed to make certain information available to holders of the Notes, as described under “Description of the Exchange Notes-Agreement to Provide Information.”

The Company is not currently subject to the informational requirements of the Exchange Act. As a result of the offering of the Exchange Notes, we will become subject to the informational requirements of the Exchange Act and, in accordance therewith, will file reports and other information with the SEC. These reports and other information can be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also read and copy these SEC filings by visiting the SEC’s website at http://www.sec.gov.

You may request additional copies of our reports or copies of our other SEC filings at no cost by writing or telephoning us at the following address:

AEP Texas Inc.

1 Riverside Plaza

Columbus, Ohio 43215

Attention: Investor Relations

Telephone: (614) 716-1000

113

AEP Texas and Subsidiaries

INDEX TO FINANCIAL STATEMENTS

Audited Consolidated Financial Statements as of December 31, 2016 and 2015 and for Years Ended December 31, 2016, 2015 and 2014.

	Page Number
Glossary of Terms	F-1
Report of Independent Registered Public Accounting Firm	F-3
Consolidated Statements of Income	F-4
Consolidated Statements of Comprehensive Income (Loss)	F-5
Consolidated Statements of Changes in Common Shareholder’s Equity	F-6
Consolidated Balance Sheets	F-7
Consolidated Statements of Cash Flows	F-9
Index of Notes to Consolidated Financial Statements	F-10

Unaudited Condensed Consolidated Financial Statements as of September 30, 2017 and December 31, 2016 and for the Three and Nine Months Ended September 30, 2017 and 2016.

	Page Number
Glossary of Terms	F-64
Condensed Consolidated Statements of Income	F-65
Condensed Consolidated Statements of Comprehensive Income (Loss)	F-66
Condensed Consolidated Statements of Changes in Common Shareholder’s Equity	F-67
Condensed Consolidated Balance Sheets	F-68
Condensed Consolidated Statements of Cash Flows	F-70
Index of Notes to Condensed Consolidated Financial Statements	F-71

114

AEP Texas and Subsidiaries

2016 Annual Report

Audited Consolidated Financial Statements

GLOSSARY OF TERMS

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

Term	Meaning
AEP	American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority owned consolidated subsidiaries and consolidated affiliates.
AEP System	American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP Texas	AEP Texas, an AEP electric utility subsidiary.
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 an affiliated 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, asset management and commercial and industrial sales in the deregulated Texas market.
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.
ASU	Accounting Standards Update.
CWIP	Construction Work in Progress.
EIS	Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entity of AEP.
ERCOT	Electric Reliability Council of Texas regional transmission organization.
ETT	Electric Transmission Texas, LLC, an equity interest joint venture between Parent and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
FASB	Financial Accounting Standards Board.
Federal EPA	United States Environmental Protection Agency.
FERC	Federal Energy Regulatory Commission.
FGD	Flue Gas Desulfurization or scrubbers.
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.
Nonutility Money Pool	Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
OPEB	Other Postretirement Benefit Plans.
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.
TCC	AEP Texas Central Company, an AEP electric utility subsidiary.

F-1

Term	Meaning
Texas Restructuring Legislation	Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC	AEP Texas North Company, an AEP electric utility subsidiary.
Transition Funding	AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.
Utility Money Pool	Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE	Variable Interest Entity.
Wind Farms	Desert Sky and Trent Wind Farms, previously owned by a subsidiary of AEP Utilities, Inc., were transferred to an affiliated company on December 31, 2016.

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

AEP Texas Inc.

We have audited the accompanying consolidated balance sheets of AEP Texas Inc. and subsidiaries (the "Company") as of December 31, 2016 and 2015, and the related consolidated statements of income, comprehensive income (loss), changes in common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of AEP Texas Inc. and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Columbus, Ohio

April 26, 2017

(November 17, 2017 as to Note 17)

F-3

AEP TEXAS AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2016, 2015 and 2014

(in millions)

	Years Ended December 31,
	2016			2015			2014
REVENUES
Electric Transmission and Distribution	$	1,383.2		$	1,374.1		$	1,331.6
Sales to AEP Affiliates	75.7			78.5			92.8
Other Revenues	2.5			5.4			4.2
TOTAL REVENUES	1,461.4			1,458.0			1,428.6
EXPENSES
Fuel and Other Consumables Used for Electric Generation	32.1			32.1			45.0
Other Operation	454.5			439.9			406.7
Maintenance	73.7			91.0			80.3
Depreciation and Amortization	413.9			468.9			444.1
Taxes Other Than Income Taxes	107.6			105.3			100.0
TOTAL EXPENSES	1,081.8			1,137.2			1,076.1
OPERATING INCOME	379.6			320.8			352.5
Other Income (Expense):
Interest Income	10.9			0.8			0.2
Allowance for Equity Funds Used During Construction	9.2			6.7			4.8
Interest Expense	(144.4		)	(148.4		)	(152.0		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	255.3			179.9			205.5
Income Tax Expense	59.9			58.2			78.4
INCOME FROM CONTINUING OPERATIONS	195.4			121.7			127.1
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF TAX	(48.8		)	(1.4		)	0.8
NET INCOME	$	146.6		$	120.3		$	127.9
The common stock of AEP Texas is wholly-owned by Parent.
See Notes to Consolidated Financial Statements beginning on page F-10.

F-4

AEP TEXAS AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2016, 2015 and 2014

(in millions)

	Years Ended December 31,
	2016		2015		2014
Net Income	$	146.6	$	120.3	$	127.9
OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.6, $0.6 and $0.7 in 2016, 2015 and 2014, Respectively	1.1		1.2		1.2
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0.2, $0.2 and $0.3 in 2016, 2015 and 2014, Respectively	0.3		0.3		0.6
Pension and OPEB Funded Status, Net of Tax of $0.5, $0.1 and $0.9 in 2016, 2015 and 2014, Respectively	0.9		0.2		1.8
TOTAL OTHER COMPREHENSIVE INCOME	2.3		1.7		3.6
TOTAL COMPREHENSIVE INCOME	$	148.9	$	122.0	$	131.5
See Notes to Consolidated Financial Statements beginning on page F-10.

F-5

AEP TEXAS AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY

For the Years Ended December 31, 2016, 2015 and 2014

(in millions)

	Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2013	$	532.6	$	702.8		$	(22.5	)	$	1,212.9
Common Stock Dividends			(35.0		)				(35.0		)
Net Income			127.9						127.9
Other Comprehensive Income						3.6			3.6
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2014	532.6		795.7			(18.9		)	1,309.4
Capital Contribution from Parent	272.3								272.3
Common Stock Dividends			(29.0		)				(29.0		)
Net Income			120.3						120.3
Other Comprehensive Income						1.7			1.7
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2015	804.9		887.0			(17.2		)	1,674.7
Capital Contribution from Parent	53.0								53.0
Common Stock Dividends			(34.0		)				(34.0		)
Net Income			146.6						146.6
Other Comprehensive Income						2.3			2.3
Distribution of CSW Energy, Inc. to Parent			(185.5		)				(185.5		)
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2016	$	857.9	$	814.1		$	(14.9	)	$	1,657.1
See Notes to Consolidated Financial Statements beginning on page F-10.

F-6

AEP TEXAS AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2016 and 2015

(in millions)

	December 31,
	2016			2015
CURRENT ASSETS
Cash and Cash Equivalents	$	0.6		$	0.5
Restricted Cash for Securitized Transition Funding	146.3			203.4
Advances to Affiliates	8.6			147.6
Accounts Receivable:
Customers	94.4			94.7
Affiliated Companies	11.8			8.4
Accrued Unbilled Revenues	64.8			45.6
Miscellaneous	0.1			0.9
Allowance for Uncollectible Accounts	(0.6		)	(1.7		)
Total Accounts Receivable	170.5			147.9
Fuel	9.8			10.2
Materials and Supplies	49.0			54.5
Risk Management Assets	0.2			—
Assets From Discontinued Operations	—			83.7
Prepayments and Other Current Assets	4.2			3.7
TOTAL CURRENT ASSETS	389.2			651.5
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	349.6			342.5
Transmission	2,623.6			2,352.9
Distribution	3,527.2			3,343.6
Other Property, Plant and Equipment	436.4			407.7
Construction Work in Progress	385.9			293.5
Total Property, Plant and Equipment	7,322.7			6,740.2
Accumulated Depreciation and Amortization	1,542.0			1,480.4
TOTAL PROPERTY, PLANT AND EQUIPMENT –NET	5,780.7			5,259.8
OTHER NONCURRENT ASSETS
Regulatory Assets	347.2			299.8
Securitized Transition Assets
(December 31, 2016 and 2015 Amounts Include $1,088.3 and $1,297.5, Respectively, Related to Transition Funding)	1,118.7			1,335.9
Assets From Discontinued Operations	—			128.3
Deferred Charges and Other Noncurrent Assets	73.3			207.2
TOTAL OTHER NONCURRENT ASSETS	1,539.2			1,971.2
TOTAL ASSETS	$	7,709.1		$	7,882.5
See Notes to Consolidated Financial Statements beginning on page F-10.

F-7

AEP TEXAS AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

December 31, 2016 and 2015

(dollars in millions)

	December 31,
	2016			2015
CURRENT LIABILITIES
Advances from Affiliates	$	169.5		$	52.5
Accounts Payable:
General	129.5			102.5
Affiliated Companies	30.5			31.1
Long-term Debt Due Within One Year – Nonaffiliated
(December 31, 2016 and 2015 Amounts Include $222.2 and $253.7, Respectively, Related to Transition Funding)	263.1			428.7
Risk Management Liabilities	—			0.3
Accrued Taxes	68.2			90.8
Accrued Interest
(December 31, 2016 and 2015 Amounts Include $20.2 and $25.3, Respectively, Related to Transition Funding)	41.5			46.6
Liabilities From Discontinued Operations	—			72.4
Other Current Liabilities	94.8			88.1
TOTAL CURRENT LIABILITIES	797.1			913.0
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated
(December 31, 2016 and 2015 Amounts Include $1,023.6 and $1,243.5, Respectively, Related to Transition Funding)	2,954.6			3,015.0
Deferred Income Taxes	1,531.7			1,477.4
Regulatory Liabilities and Deferred Investment Tax Credits	660.8			635.5
Oklaunion Purchase Power Agreement	51.5			50.2
Liabilities From Discontinued Operations	—			19.0
Deferred Credits and Other Noncurrent Liabilities	56.3			97.7
TOTAL NONCURRENT LIABILITIES	5,254.9			5,294.8
TOTAL LIABILITIES	6,052.0			6,207.8
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
COMMON SHAREHOLDER’S EQUITY
Paid-in Capital	857.9			804.9
Retained Earnings	814.1			887.0
Accumulated Other Comprehensive Income (Loss)	(14.9		)	(17.2		)
TOTAL COMMON SHAREHOLDER’S EQUITY	1,657.1			1,674.7
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	7,709.1		$	7,882.5
See Notes to Consolidated Financial Statements beginning on page F-10.

F-8

AEP TEXAS AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2016, 2015 and 2014

(in millions)

	Years Ended December 31,
	2016			2015			2014
OPERATING ACTIVITIES
Net Income	$	146.6		$	120.3		$	127.9
Income (Loss) from Discontinued Operations	(48.8		)	(1.4		)	0.8
Income from Continuing Operations	195.4			121.7			127.1
Adjustments to Reconcile Income from Continuing Operations to Net Cash Flows from Continuing Operating Activities:
Depreciation and Amortization	413.9			468.9			444.1
Deferred Income Taxes	29.5			(7.1		)	2.6
Allowance for Equity Funds Used During Construction	(9.2		)	(6.7		)	(4.8		)
Mark-to-Market of Risk Management Contracts	(0.5		)	(0.7		)	1.0
Pension Contributions to Qualified Plan Trust	(8.2		)	(8.5		)	(7.4		)
Change in Other Noncurrent Assets	(45.0		)	(72.4		)	(34.0		)
Change in Other Noncurrent Liabilities	(10.3		)	(43.1		)	23.9
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(22.6		)	9.9			(4.3		)
Fuel, Materials and Supplies	5.9			(4.4		)	(0.8		)
Accounts Payable	(3.0		)	(12.3		)	2.5
Accrued Taxes, Net	(22.6		)	46.9			11.0
Other Current Assets	(0.2		)	(0.1		)	0.1
Other Current Liabilities	(6.5		)	3.1			(3.0		)
Net Cash Flows from Continuing Operating Activities	516.6			495.2			558.0
INVESTING ACTIVITIES
Construction Expenditures	(640.9		)	(593.4		)	(579.0		)
Change in Restricted Cash for Securitized Transition Funding	57.1			2.3			(8.8		)
Change in Advances to Affiliates, Net	139.0			(138.0		)	0.6
Other Investing Activities	10.4			29.1			21.3
Net Cash Flows Used for Continuing Investing Activities	(434.4		)	(700.0		)	(565.9		)
FINANCING ACTIVITIES
Capital Contribution from Parent	53.0			272.3			—
Issuance of Long-term Debt – Nonaffiliated	199.2			370.1			298.6
Change in Advances from Affiliates, Net	117.0			(142.0		)	3.8
Retirement of Long-term Debt – Nonaffiliated	(428.7		)	(273.7		)	(258.1		)
Principal Payments for Capital Lease Obligations	(3.4		)	(2.9		)	(2.9		)
Dividends Paid on Common Stock	(34.0		)	(29.0		)	(35.0		)
Other Financing Activities	0.8			0.3			1.2
Net Cash Flows from (Used for) Continuing Financing Activities	(96.1		)	195.1			7.6
Net Cash Flows from Discontinued Operating Activities	42.4			0.6			14.3
Net Cash Flows from (Used for) Discontinued Investing Activities	11.7			18.8			(14.5		)
Net Cash Flows from (Used for) Discontinued Financing Activities	(44.6		)	(15.9		)	0.2
Net Decrease in Cash and Cash Equivalents	(4.4		)	(6.2		)	(0.3		)
Cash and Cash Equivalents at Beginning of Period	5.0			11.2			11.5
Cash and Cash Equivalents at End of Period	$	0.6		$	5.0		$	11.2
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	145.6		$	144.0		$	147.7
Net Cash Paid for Income Taxes	38.2			8.1			80.1
Noncash Acquisitions Under Capital Leases	7.1			6.1			3.9
Construction Expenditures Included in Current Liabilities as of December 31,	100.1			72.8			45.6
Noncash Distribution of CSW Energy, Inc. to Parent	185.5			—			—
See Notes to Consolidated Financial Statements beginning on page F-10.

F-9

INDEX OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note	Page Number
Organization and Summary of Significant Accounting Policies	F-11
New Accounting Pronouncements	F-20
Comprehensive Income	F-23
Rate Matters	F-25
Effects of Regulation	F-26
Commitments, Guarantees and Contingencies	F-27
Impairment and Disposition	F-29
Benefit Plans	F-31
Derivatives and Hedging	F-41
Fair Value Measurements	F-44
Income Taxes	F-46
Leases	F-50
Financing Activities	F-52
Related Party Transactions	F-56
Variable Interest Entities	F-58
Property, Plant and Equipment	F-60
Business Segments	F-62

F-10

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

Effective December 31, 2016, TCC and TNC merged into AEP Utilities, Inc., as approved by the FERC and the PUCT. Upon merger, AEP Utilities, Inc. changed its name to AEP Texas Inc. As a public utility, AEP Texas engages in the transmission and distribution of electric power to 1,024,000 retail customers through REPs in its service territory in southern, western and central Texas. AEP Texas consolidates AEP Texas North Generation Company, LLC, AEP Texas Central Transition Funding LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, its wholly-owned subsidiaries.

Under the Texas Restructuring Legislation, TCC and TNC exited the generation business and ceased serving retail load. However, AEP Texas continues as part owner in the Oklaunion Plant operated by PSO but has leased its entire portion of the output of the plant through 2027 to a non-utility affiliate.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

AEP Texas’ transmission and distribution operations and related rates are regulated by the PUCT. The FERC 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 its affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system.

The PUCT also regulates AEP Texas’ wholesale transmission operations and rates. The FERC claims jurisdiction over retail transmission rates when retail rates are unbundled in connection with restructuring. AEP Texas’ retail transmission rates in Texas are unbundled. Although AEP Texas’ retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT.

Principles of Consolidation

AEP Texas’ financial statements include AEP Texas and its wholly-owned subsidiaries. Intercompany items are eliminated in consolidation. AEP Texas also has a generating unit that is jointly-owned with an affiliated company and nonaffiliated companies. AEP Texas’ proportionate share of the operating costs associated with that facility is included in the financial statements and the assets and liabilities are reflected on the balance sheets. See “Oklaunion PPA between AEP Texas and AEP Energy Partners” section within Note 14 for detail of AEP Texas’ agreement to sell its portion of the Oklaunion generation to AEPEP. See Note 15 - Variable Interest Entities.

Accounting for the Effects of Cost-Based Regulation

As a rate-regulated electric public utility company, 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,” AEP Texas records regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) 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.

F-11

Use of Estimates

The preparation of these financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) 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 temporary cash investments with original maturities of three months or less.

Restricted Cash for Securitized Transition Funding

Restricted Cash for Securitized Transition Funding includes funds held by trustees primarily for the payment of securitization bonds and to secure the payments of the REPs.

Inventory

Fossil fuel inventories are carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost.

Accounts Receivable

Customer accounts receivable primarily includes receivables from REPs and receivables related to other revenue-generating activities.

Revenue is recognized when power is delivered. To the extent that deliveries have occurred but a bill has not been issued, AEP Texas accrues and recognizes, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for deliveries since the last billing.

Allowance for Uncollectible Accounts

AEP Texas records bad debt reserves 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 has significant customers which on a combined basis account for the following percentages of total operating revenues for the years ended December 31 and Accounts Receivable – Customers as of December 31:

Significant Customers of AEP Texas:
Centrica, Just Energy and Reliant Energy	2016		2015		2014
Percentage of Operating Revenues	46	%	53	%	55	%
Percentage of Accounts Receivable – Customers	42	%	43	%	44	%

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

F-12

Property, Plant and Equipment

Regulated

Electric utility property, plant and equipment for AEP Texas’ rate-regulated transmission and distribution 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 poles, transformers, 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 typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued.

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, 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.

Nonregulated

The generation operations of AEP Texas generally follow the policies of its rate-regulated operations listed above but with the following exceptions. Property, plant and equipment are stated at fair value at acquisition (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense.

Allowance for Funds Used During Construction

For AEP Texas’ regulated operations, 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.  AEP Texas records the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense.  For AEP Texas’ nonregulated operations, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable and Accounts Payable approximate fair value because of the short-term maturity of these instruments.

F-13

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. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.

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 trusts. 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 and Restricted Cash for Securitized Transition Fundingare 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 domestic 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 and cash equivalent funds. 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. Benefit plan assets included in Level 3 are primarily real estate, infrastructure

F-14

and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate and infrastructure investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate, infrastructure or private equity investment.

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) 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.

When regulatory assets are probable of recovery through regulated rates, AEP Texas records them as assets on its balance sheets. AEP Texas tests 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, AEP Texas writes off that regulatory asset as a charge against income.

Electricity Supply and Delivery Activities

AEP Texas recognizes revenues from electricity transmission and distribution delivery services. AEP Texas recognizes the revenues on the statements of income upon delivery of the energy to the customer and includes unbilled as well as billed amounts.

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

Maintenance costs are expensed 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 their recovery in cost-based regulated revenues.

Income Taxes and Investment Tax Credits

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.

When the flow-through method of accounting for temporary differences is 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.

F-15

Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP Texas and other AEP subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. This change had no financial impact to AEP Texas.

Deferred ITC is amortized to income tax expense over the life of the asset. 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 Other Operation expense.

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 recognize 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 is refinanced, the reacquisition costs 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. The net amortization expense is included in Interest Expense on the statements of income.

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 accounts for its participation in these plans as multiple-employer plans.  See Note 8 - 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.

F-16

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	65	%
Fixed Income	33	%
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.

F-17

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 development risk 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. Commingled private equity funds are used to enhance the holdings’ diversity.

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 providing modest incremental income with a limited increase in risk.

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 nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).

Earnings Per Share (EPS)

AEP Texas is owned by a wholly-owned subsidiary of AEP. Therefore, AEP Texas is not required to report EPS.

F-18

Supplementary Income Statement Information

The following table provides the components of Depreciation and Amortization:

	Years Ended December 31,
Depreciation and Amortization	2016			2015		2014
	(in millions)
Depreciation and Amortization of Property, Plant and Equipment	$	204.0		$	193.3	$	177.4
Amortization of Securitized Transition Assets	210.3			275.5		266.9
Amortization of Regulatory Assets and Liabilities	(0.4		)	0.1		(0.2		)
Total Depreciation and Amortization	$	413.9		$	468.9	$	444.1

Subsequent Events

Management reviewed subsequent events through April 26, 2017, the date that AEP Texas’ 2016 annual report was issued.

F-19

2. NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to AEP Texas’ business. The following final 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 clarifying 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, 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 flow arising from contracts.

The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted.

Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016, initial revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Management also continues to monitor unresolved industry implementation issues, including items related to collectability and alternative revenue programs, and will analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018.

ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11)

In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management adopted ASU 2015-11 prospectively, effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption.

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

In January 2016, the FASB issued ASU 2016-01 enhancing 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. 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 sheet 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.

F-20

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. 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 2016-01 effective January 1, 2018.

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 sheet 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 lease 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.

The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented.

Management continues to analyze the impact of the new lease standard. During 2016, initial lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Lease system options are currently being evaluated. Management plans to elect certain of 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.
Lease term	Elect to use hindsight to determine the lease term.

Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to renewables and Purchase Power and Sale Agreements, pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019.

ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09)

In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income.

The new accounting guidance is effective for annual periods beginning after December 15, 2016.  Early adoption is permitted in any interim or annual period. Certain provisions require retrospective/modified retrospective transition while others are to be applied prospectively. Management adopted ASU 2016-09 effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption.

F-21

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 effective January 1, 2020.

ASU 2016-18 “Restricted Cash” (ASU 2016-18)

In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows.

The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report.

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 in the income statement separately from the service cost component and outside a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2017-07 effective January 1, 2018.

F-22

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, 2016, 2015 and 2014. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 for additional details.

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Year Ended December 31, 2016

	Cash Flow Hedges					Pension and OPEB
						Amortization			Changes
						of Deferred			in Funded
	Commodity		Interest Rate			Costs			Status			Total
	(in millions)
Balance in AOCI as of December 31, 2015	$	—	$	(6.5	)	$	3.9		$	(14.6	)	$	(17.2	)
Change in Fair Value Recognized in AOCI	—		(0.1		)	—			0.9			0.8
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense	—		1.8			—			—			1.8
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) Credit	—		1.8			0.4			—			2.2
Income Tax (Expense) Credit	—		0.6			0.1			—			0.7
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	—		1.2			0.3			—			1.5
Net Current Period Other Comprehensive Income	—		1.1			0.3			0.9			2.3
Balance in AOCI as of December 31, 2016	$	—	$	(5.4	)	$	4.2		$	(13.7	)	$	(14.9	)

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Year Ended December 31, 2015

	Cash Flow Hedges					Pension and OPEB
						Amortization			Changes
						of Deferred			in Funded
	Commodity		Interest Rate			Costs			Status			Total
			(in millions)
Balance in AOCI as of December 31, 2014	$	—	$	(7.7	)	$	3.6		$	(14.8	)	$	(18.9	)
Change in Fair Value Recognized in AOCI	—		(0.1		)	—			0.2			0.1
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense	—		1.9			—			—			1.9
Amortization of Prior Service Cost (Credit)	—		—			(0.1		)	—			(0.1		)
Amortization of Actuarial (Gains)/Losses	—		—			0.6			—			0.6
Reclassifications from AOCI, before Income Tax (Expense) Credit	—		1.9			0.5			—			2.4
Income Tax (Expense) Credit	—		0.6			0.2			—			0.8
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	—		1.3			0.3			—			1.6
Net Current Period Other Comprehensive Income	—		1.2			0.3			0.2			1.7
Balance in AOCI as of December 31, 2015	$	—	$	(6.5	)	$	3.9		$	(14.6	)	$	(17.2	)

F-23

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Year Ended December 31, 2014

	Cash Flow Hedges						Pension and OPEB
							Amortization			Changes
							of Deferred			in Funded
	Commodity			Interest Rate			Costs			Status			Total
				(in millions)
Balance in AOCI as of December 31, 2013	$	0.1		$	(9.0	)	$	3.0		$	(16.6	)	$	(22.5	)
Change in Fair Value Recognized in AOCI	—			(0.1		)	—			1.8			1.7
Amount of (Gain) Loss Reclassified from AOCI
Regulatory Assets/(Liabilities), Net (a)	(0.1		)	—			—			—			(0.1		)
Interest Expense	—			2.1			—			—			2.1
Amortization of Prior Service Cost (Credit)	—			—			(0.1		)	—			(0.1		)
Amortization of Actuarial (Gains)/Losses	—			—			1.0			—			1.0
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.1		)	2.1			0.9			—			2.9
Income Tax (Expense) Credit	—			0.7			0.3			—			1.0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.1		)	1.4			0.6			—			1.9
Net Current Period Other Comprehensive Income (Loss)	(0.1		)	1.3			0.6			1.8			3.6
Balance in AOCI as of December 31, 2014	$	—		$	(7.7	)	$	3.6		$	(14.8	)	$	(18.9	)

(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

F-24

4.  RATE MATTERS

AEP Texas is involved in rate and regulatory proceedings at the PUCT and the FERC.  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.

TCC and TNC Merger

Effective December 31, 2016, TCC and TNC merged into AEP Utilities, Inc., as approved by the FERC and the PUCT in September 2016 and December 2016, respectively. Upon merger, AEP Utilities, Inc. changed its name to AEP Texas Inc., but maintained TCC’s and TNC’s respective customer rates. The PUCT ordered certain post-merger conditions which included a) the sharing of certain interest rate savings with customers and b) an annual credit to customers of approximately $630 thousand for savings resulting from an expected reduction in post-merger debt issuance costs, effective until the next base rate case.

AEP Texas Distribution Cost Recovery Factor (DCRF)

In July 2016, the PUCT approved settlement agreements between TCC, TNC and intervenors related to requests for DCRF riders to allow recovery of eligible net distribution investments. The settlement agreement included an annual revenue requirement of $56 million ($45 million for the TCC division and $11 million for the TNC division), effective September 2016. Amounts approved are subject to refund based upon a prudence review of the investments in AEP Texas’ next base rate case.

AEP Texas Base Rates

As of December 31, 2016, AEP’s share of AEP Texas’ cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $528 million. A base rate review could produce a refund 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.

F-25

5. EFFECTS OF REGULATION

Regulatory assets and liabilities are comprised of the following items:

			December 31,				Remaining
Regulatory Assets:			2016		2015		Recovery Period
			(in millions)
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
	Regulatory Assets Currently Earning a Return
		Storm Related Costs	$	25.1	$	24.2
	Regulatory Assets Currently Not Earning a Return
		Rate Case Expense	0.1		0.1
Total Regulatory Assets Pending Final Regulatory Approval			25.2		24.3
Regulatory assets approved for recovery:
	Regulatory Assets Currently Earning a Return
		Meter Replacement Costs	49.8		54.6		11 years
		Advanced Metering System	21.3		3.6		4 years
	Regulatory Assets Currently Not Earning a Return
		Pension and OPEB Funded Status	188.2		177.1		12 years
		Income Taxes, Net	40.3		11.8		28 years
		Unamortized Loss on Reacquired Debt	7.3		9.6		21 years
		Medicare Subsidy	5.6		6.3		8 years
		Transmission Cost Recovery Factor	5.3		9.9		1 year
		Peak Demand Reduction/Energy Efficiency	4.2		1.9		2 years
		Other Regulatory Assets Approved for Recovery	—		0.7
Total Regulatory Assets Approved for Recovery			322.0		275.5
Total Noncurrent Regulatory Assets			$	347.2	$	299.8

			December 31,				Remaining
Regulatory Liabilities:			2016		2015		Refund Period
			(in millions)
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits
Regulatory liabilities approved for payment:
	Regulatory Liabilities Currently Paying a Return
		Asset Removal Costs	$	581.7	$	544.4	(a)
		Advanced Metering Infrastructure Surcharge	17.0		21.3		4 years
		Excess Earnings	7.3		7.8		15 years
	Regulatory Liabilities Currently Not Paying a Return
		Transition Charges	40.5		46.5		11 years
		Deferred Investment Tax Credits	13.9		15.5		46 years
		Other Regulatory Liabilities Approved for Payment	0.4		—		various
Total Regulatory Liabilities Approved for Payment			660.8		635.5
Total Noncurrent Regulatory Liabilities and Deferred
	Investment Tax Credits		$	660.8	$	635.5
(a)	Relieved as removal costs are incurred

F-26

6. COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements.

COMMITMENTS

Construction and Commitments

AEP Texas has substantial construction commitments to support its operations and environmental investments. In managing the overall construction program and in the normal course of business, AEP Texas contractually commits to third-party construction vendors for certain material purchases and other construction services. AEP Texas also purchases fuel, materials, supplies, services and property, plant and equipment under contract as part of its normal course of business. Certain supply contracts contain penalty provisions for early termination.

In accordance with the accounting guidance for “Commitments”, AEP Texas had no actual contractual commitments as of December 31, 2016.

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

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $300 million. As of December 31, 2016, AEP Texas’s maximum future payment for letters of credit issued under the uncommitted credit facilities was $3 million with a maturity of January 2018.

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, 2016, there were no material liabilities recorded for any indemnifications.

F-27

Lease Obligations

AEP Texas leases certain equipment under master lease agreements. See “Master Lease Agreements” section of Note 12 for disclosure of lease residual value guarantees.

CONTINGENCIES

Insurance and Potential Losses

AEP Texas maintains insurance coverage normal and customary for an electric utility, 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 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 AEP Texas’ retentions. 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.

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

By-products from the generation of electricity include materials such as ash, slag and sludge. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous 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. Present estimates do not anticipate material cleanup costs.

F-28

7. IMPAIRMENT AND DISPOSITION

IMPAIRMENT

2016

Wind Farms

In September 2016, due to AEP’s ongoing evaluation of strategic alternatives for its merchant generation assets and declining forecasts of future energy and capacity prices, AEP performed an impairment analysis at the unit level on its merchant generation assets in accordance with accounting guidance for impairments of long-lived assets. The Wind Farms were included in this analysis. For the Wind Farms, AEP performed step one of the impairment analysis using undiscounted cash flows for the estimated useful lives of the assets based upon energy and capacity price curves, as applicable, which were developed internally with both observable Level 2 third party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. The step one analysis concluded the book value of the Wind Farms would not be recovered.

AEP performed step two of the impairment analysis on the Wind Farms using a ten-year discounted cash flow model utilizing forecasted energy price curves, which were developed internally using both observable Level 2 third party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. The results concluded the Wind Farms were impaired.

Based on the impairment analysis performed, in the third quarter of 2016, AEP Texas recorded a pretax impairment of $73 million, which was subsequently classified into Income (Loss) from Discontinued Operations, Net of Tax on AEP Texas’ statement of income for the year ended December 31, 2016. See “DISPOSITION” section of this note. See the table below for additional information.

Impaired Assets	Book Value		Fair Value		Impairment
	(in millions)
Trent and Desert Sky Wind Farms	$	118.7	$	46.0	$	72.7

F-29

DISPOSITION

2016

Wind Farms

In December 2016, TCC and TNC merged into AEP Utilities, Inc. Upon merger, AEP Utilities, Inc. changed its name to AEP Texas. Subsequent to the merger, AEP Texas exited the merchant generation business by transferring all of the common stock of the Wind Farms to a competitive AEP affiliate. No gain or loss was recognized and no cash was exchanged related to the disposition of the Wind Farms.

In the fourth quarter of 2016, the Wind Farms were determined to be discontinued operations. The assets and liabilities were classified as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on AEP Texas’ balance sheet as of December 31, 2015 and as shown in the following table:

	December 31,
	2015
Assets:	(in millions)
Advances to Affiliates	$	59.1
Property, Plant and Equipment, Net	128.2
Other Classes of Assets That Are Not Major	24.7
Total Assets from Discontinued Operations on the Balance Sheet	$	212.0
Liabilities:
Advances from Affiliates	$	64.5
Long-term Debt	10.3
Other Classes of Liabilities That Are Not Major	16.6
Total Liabilities from Discontinued Operations on the Balance Sheet	$	91.4

Results of operations of the Wind Farms have been classified as discontinued operations on AEP Texas’ statements of income for the years ended December 31, 2016, 2015 and 2014 as shown in the following table:

	Years Ended December 31,
	2016			2015			2014
	(in millions)
Revenue	$	18.2		$	22.4		$	25.5
Other Operation Expense	6.5			6.5			5.5
Maintenance Expense	3.4			4.9			4.5
Asset Impairment and Other Related Charges	72.7			—			—
Depreciation and Amortization Expense	9.8			11.5			11.1
Taxes Other Than Income Taxes	1.3			1.3			1.4
Total Expenses	93.7			24.2			22.5
Other Income (Expense)	(0.8		)	(1.3		)	(1.5		)
Pretax Income of Discontinued Operations	(76.3		)	(3.1		)	1.5
Income Tax Expense	(27.5		)	(1.7		)	0.7
Total Income on Discontinued Operations as Presented on the Statements of Income	$	(48.8	)	$	(1.4	)	$	0.8

F-30

8. 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 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 recognizes its funded status associated with defined benefit pension and OPEB plans in its 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						Other Postretirement Benefit Plans
	December 31,
Assumptions	2016			2015			2016		2015
Discount Rate	4.05	%		4.30	%		4.10	%	4.30	%
Rate of Compensation Increase	4.85	%	(a)	4.70	%	(a)	NA		NA

(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.

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 2016, the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with an average increase of 4.85%.

F-31

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									Other Postretirement Benefit Plans
	January 1,
Assumptions	2016			2015			2014			2016		2015		2014
Discount Rate	4.30	%		4.00	%		4.70	%		4.30	%	4.00	%	4.70	%
Expected Return on Plan Assets	6.00	%		6.00	%		6.00	%		7.00	%	6.75	%	6.75	%
Rate of Compensation Increase	4.85	%	(a)	4.50	%	(a)	4.65	%	(a)	NA		NA		NA

(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 and current prospects for economic growth.

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

	January 1,
Health Care Trend Rates	2016		2015
Initial	7.00	%	6.25	%
Ultimate	5.00	%	5.00	%
Year Ultimate Reached	2024		2020

Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects:

	1% Increase		1% Decrease
	(in millions)
Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost	$	0.2	$	(0.1	)
Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation	4.0		(3.5		)

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. The plans are monitored to control security diversification and ensure compliance with the investment policy. As of December 31, 2016, 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.

F-32

Benefit Plan Obligations, Plan Assets and Funded Status

The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.

Upon completion of the merger, CSW Energy, Inc. was transferred to an affiliate. The transfer occurred on December 31, 2016. CSW Energy, Inc.’s benefit obligation and portion of plan assets were transferred to the affiliate and the impact of the transfer can be seen in the table below.

	Pension Plans						Other Postretirement Benefit Plans
	2016			2015			2016			2015
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	420.3		$	455.1		$	122.0		$	122.0
Transfer of CSW Energy, Inc. Benefit Obligation	(2.8		)	—			(0.4		)	—
Service Cost	7.5			7.6			0.7			0.8
Interest Cost	17.8			17.2			5.1			4.8
Actuarial (Gain) Loss	11.1			(27.8		)	0.8			2.6
Benefit Payments	(32.2		)	(31.8		)	(11.4		)	(11.4		)
Participant Contributions	—			—			3.5			3.1
Medicare Subsidy	—			—			0.1			0.1
Benefit Obligation as of December 31,	$	421.7		$	420.3		$	120.4		$	122.0
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	415.4		$	438.9		$	138.6		$	152.8
Transfer of CSW Energy, Inc. Plan Assets	(2.5		)	—			(0.4		)	—
Actual Gain (Loss) on Plan Assets	27.4			(0.6		)	3.8			(5.9		)
Company Contributions	8.5			8.9			—			—
Participant Contributions	—			—			3.5			3.1
Benefit Payments	(32.2		)	(31.8		)	(11.4		)	(11.4		)
Fair Value of Plan Assets as of December 31,	$	416.6		$	415.4		$	134.1		$	138.6
Funded (Underfunded) Status as of December 31,	$	(5.1	)	$	(4.9	)	$	13.7		$	16.6

Amounts Recognized on the Balance Sheets

	Pension Plans						Other Postretirement Benefit Plans
	December 31,
	2016			2015			2016		2015
	(in millions)
Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs	$	—		$	—		$	13.7	$	16.6
Other Current Liabilities – Accrued Short-term Benefit Liability	(0.4		)	(0.4		)	—		—
Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability	(4.7		)	(4.5		)	—		—
Funded (Underfunded) Status	$	(5.1	)	$	(4.9	)	$	13.7	$	16.6

F-33

Amounts Included in AOCI and Regulatory Assets

	Pension Plans				Other Postretirement Benefit Plans
	December 31,
	2016		2015		2016			2015
Components	(in millions)
Net Actuarial Loss	$	193.3	$	193.3	$	50.7		$	47.1
Prior Service Cost (Credit)	—		0.4		(41.2		)	(47.2		)
Recorded as
Regulatory Assets	$	178.5	$	176.6	$	9.7		$	0.5
Deferred Income Taxes	5.2		6.0		(0.1		)	(0.2		)
Net of Tax AOCI	9.6		11.1		(0.1		)	(0.4		)

Components of the change in amounts included in AOCI and Regulatory Assets are as follows:

	Pension Plans						Other Postretirement Benefit Plans
	2016			2015			2016			2015
Components	(in millions)
Actuarial (Gain) Loss During the Year	$	7.1		$	(3.1	)	$	6.4		$	17.9
Amortization of Actuarial Loss	(7.1		)	(9.0		)	(2.8		)	(1.5		)
Amortization of Prior Service Credit (Cost)	(0.4		)	(0.3		)	6.0			5.9
Change for the Year Ended December 31,	$	(0.4	)	$	(12.4	)	$	9.6		$	22.3

Pension and Other Postretirement Benefits Plans’ Assets

The fair value tables within Pension and Other Postretirement Benefits Plans’ 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				Other Postretirement Benefit Plans
December 31,
2016		2015		2016		2015
8.6	%	8.7	%	8.7	%	8.8	%

F-34

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2016:

Asset Class	Level 1		Level 2		Level 3		Other			Total			Year End Allocation
	(in millions)
Equities:
Domestic	$	354.7	$	—	$	—	$	—		$	354.7		7.3	%
International	439.2		—		—		—			439.2			9.1	%
Options	—		20.0		—		—			20.0			0.4	%
Real Estate Investment Trusts	3.1		—		—		—			3.1			0.1	%
Common Collective Trusts (c)	—		14.0		—		400.5			414.5			8.6	%
Subtotal – Equities	797.0		34.0		—		400.5			1,231.5			25.5	%
Fixed Income:
Common Collective Trust – Debt (c)	—		—		—		32.3			32.3			0.7	%
United States Government and Agency Securities (c)	—		423.3		—		17.7			441.0			9.1	%
Corporate Debt (c)	—		1,932.2		—		10.0			1,942.2			40.2	%
Foreign Debt (c)	—		373.7		—		12.1			385.8			8.0	%
State and Local Government	—		11.5		—		—			11.5			0.2	%
Other – Asset Backed (c)	—		5.4		—		7.4			12.8			0.3	%
Subtotal – Fixed Income	—		2,746.1		—		79.5			2,825.6			58.5	%
Infrastructure	—		—		57.6		—			57.6			1.2	%
Real Estate	—		—		254.9		—			254.9			5.3	%
Alternative Investments	—		—		411.1		—			411.1			8.5	%
Securities Lending	—		161.6		—		—			161.6			3.4	%
Securities Lending Collateral (a)	—		—		—		(163.3		)	(163.3		)	(3.4	)%
Cash and Cash Equivalents (c)	—		—		—		29.7			29.7			0.6	%
Other – Pending Transactions and Accrued Income (b)	—		—		—		18.6			18.6			0.4	%
Total	$	797.0	$	2,941.7	$	723.6	$	365.0		$	4,827.3		100.0	%

(a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program.

(b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

(c) Amounts in “Other” column represent 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), which was retrospectively applied to prior periods.

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:

	Foreign Debt			Infrastructure		Real Estate			Alternative Investments			Total Level 3
	(in millions)
Balance as of January 1, 2016	$	0.1		$	42.0	$	253.7		$	378.7		$	674.5
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date	—			5.9		5.3			13.7			24.9
Relating to Assets Sold During the Period	—			0.9		23.2			21.1			45.2
Purchases and Sales	(0.1		)	8.8		(27.3		)	(2.4		)	(21.0		)
Transfers into Level 3	—			—		—			—			—
Transfers out of Level 3	—			—		—			—			—
Balance as of December 31, 2016	$	—		$	57.6	$	254.9		$	411.1		$	723.6

F-35

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2016:

Asset Class	Level 1		Level 2		Level 3		Other			Total			Year End Allocation
	(in millions)
Equities:
Domestic	$	517.1	$	—	$	—	$	—		$	517.1		33.5	%
International	435.5		—		—		—			435.5			28.2	%
Options	—		15.2		—		—			15.2			1.0	%
Common Collective Trusts (b)	—		10.9		—		20.5			31.4			2.0	%
Subtotal – Equities	952.6		26.1		—		20.5			999.2			64.7	%
Fixed Income:
Common Collective Trust – Debt (b)	—		—		—		93.7			93.7			6.0	%
United States Government and Agency Securities	—		64.7		—		—			64.7			4.2	%
Corporate Debt	—		121.6		—		—			121.6			7.9	%
Foreign Debt	—		18.6		—		—			18.6			1.2	%
State and Local Government	—		3.0		—		—			3.0			0.2	%
Other – Asset Backed	—		5.9		—		—			5.9			0.4	%
Subtotal – Fixed Income	—		213.8		—		93.7			307.5			19.9	%
Trust Owned Life Insurance:
International Equities (b)	—		—		—		110.1			110.1			7.1	%
United States Bonds (b)	—		—		—		97.4			97.4			6.3	%
Subtotal – Trust Owned Life Insurance	—		—		—		207.5			207.5			13.4	%
Cash and Cash Equivalents	24.0		10.5		—		—			34.5			2.2	%
Other – Pending Transactions and Accrued Income (a)	—		—		—		(2.8		)	(2.8		)	(0.2	)%
Total	$	976.6	$	250.4	$	—	$	318.9		$	1,545.9		100.0	%

(a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

(b) Amounts in “Other” column represent 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), which was retrospectively applied to prior periods.

F-36

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2015:

Asset Class	Level 1		Level 2		Level 3		Other			Total			Year End Allocation
	(in millions)
Equities:
Domestic	$	315.7	$	—	$	—	$	—		$	315.7		6.6	%
International	402.3		—		—		—			402.3			8.4	%
Options	—		15.6		—		—			15.6			0.3	%
Real Estate Investment Trusts	4.0		—		—		—			4.0			0.1	%
Common Collective Trusts (c)	—		16.1		—		369.7			385.8			8.1	%
Subtotal – Equities	722.0		31.7		—		369.7			1,123.4			23.5	%
Fixed Income:
Common Collective Trust – Debt (c)	—		—		—		34.2			34.2			0.7	%
United States Government and Agency Securities (c)	—		397.8		—		24.1			421.9			8.9	%
Corporate Debt (c)	—		1,964.2		—		19.0			1,983.2			41.6	%
Foreign Debt (c)	—		405.4		0.1		16.0			421.5			8.8	%
State and Local Government	—		12.8		—		—			12.8			0.3	%
Other – Asset Backed (c)	—		15.8		—		7.6			23.4			0.5	%
Subtotal – Fixed Income	—		2,796.0		0.1		100.9			2,897.0			60.8	%
Infrastructure	—		—		42.0		—			42.0			0.9	%
Real Estate	—		—		253.7		—			253.7			5.3	%
Alternative Investments	—		—		378.7		—			378.7			8.0	%
Securities Lending	—		263.0		—		—			263.0			5.5	%
Securities Lending Collateral (a)	—		—		—		(264.7		)	(264.7		)	(5.5	)%
Cash and Cash Equivalents (c)	—		1.2		—		47.4			48.6			1.0	%
Other – Pending Transactions and Accrued Income (b)	—		—		—		25.9			25.9			0.5	%
Total	$	722.0	$	3,091.9	$	674.5	$	279.2		$	4,767.6		100.0	%

(a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program.

(b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

(c) Amounts in “Other” column represent 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), which was retrospectively applied to prior periods.

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:

	Foreign Debt		Infrastructure			Real Estate			Alternative Investments			Total Level 3
	(in millions)
Balance as of January 1, 2015	$	0.1	$	12.5		$	235.8		$	378.9		$	627.3
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date	—		(3.6		)	12.5			(25.9		)	(17.0		)
Relating to Assets Sold During the Period	—		0.3			23.8			37.6			61.7
Purchases and Sales	—		32.8			(18.4		)	(11.9		)	2.5
Transfers into Level 3	—		—			—			—			—
Transfers out of Level 3	—		—			—			—			—
Balance as of December 31, 2015	$	0.1	$	42.0		$	253.7		$	378.7		$	674.5

F-37

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2015:

Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities:
Domestic	$	465.1	$	—	$	—	$	—	$	465.1	29.5	%
International	484.3		—		—		—		484.3		30.7	%
Options	—		15.6		—		—		15.6		1.0	%
Common Collective Trusts (b)	—		12.6		—		19.0		31.6		2.0	%
Subtotal – Equities	949.4		28.2		—		19.0		996.6		63.2	%
Fixed Income:
Common Collective Trust – Debt (b)	—		—		—		100.9		100.9		6.4	%
United States Government and Agency Securities	—		58.4		—		—		58.4		3.7	%
Corporate Debt	—		117.7		—		—		117.7		7.4	%
Foreign Debt	—		20.7		—		—		20.7		1.3	%
State and Local Government	—		4.2		—		—		4.2		0.3	%
Other – Asset Backed	—		8.4		—		—		8.4		0.5	%
Subtotal – Fixed Income	—		209.4		—		100.9		310.3		19.6	%
Trust Owned Life Insurance:
International Equities (b)	—		—		—		28.3		28.3		1.8	%
United States Bonds (b)	—		—		—		184.3		184.3		11.7	%
Subtotal – Trust Owned Life Insurance	—		—		—		212.6		212.6		13.5	%
Cash and Cash Equivalents	44.9		7.2		—		—		52.1		3.3	%
Other – Pending Transactions and Accrued Income (a)	—		—		—		5.8		5.8		0.4	%
Total	$	994.3	$	244.8	$	—	$	338.3	$	1,577.4	100.0	%

(a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

(b) Amounts in “Other” column represent 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), which was retrospectively applied to prior periods.

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.

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

	December 31,
	2016		2015
	(in millions)
Qualified Pension Plan	$	404.7	$	404.5
Nonqualified Pension Plan	3.8		4.0
Total Accumulated Benefit Obligation	$	408.5	$	408.5

F-38

For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets were as follows:

	Underfunded Pension Plans
	December 31,
	2016			2015
	(in millions)
Projected Benefit Obligation	$	3.8		$	4.0
Accumulated Benefit Obligation	$	3.8		$	4.0
Fair Value of Plan Assets	—			—
Underfunded Accumulated Benefit Obligation	$	(3.8	)	$	(4.0	)

Estimated Future Benefit Payments and Contributions

AEP Texas expects contributions and payments for the pension plans of $9 million during 2017. The estimated contributions to the pension trust are at least the minimum amount required by the Employee Retirement Income Security Act and additional discretionary contributions may also be made 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 pension benefits and OPEB are as follows:

	Estimated Payments
	Pension Plans		Other Postretirement Benefit Plans
	(in millions)
2017	$	32.1	$	12.1
2018	31.4		12.1
2019	31.7		12.1
2020	33.9		12.3
2021	34.8		12.4
Years 2022 to 2026, in Total	166.6		63.2

F-39

Components of Net Periodic Benefit Cost

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

	Pension Plans									Other Postretirement Benefit Plans
	Years Ended December 31,
	2016			2015			2014			2016			2015			2014
	(in millions)
Service Cost	$	7.5		$	7.6		$	6.5		$	0.7		$	0.8		$	1.0
Interest Cost	17.8			17.2			19.6			5.1			4.8			5.6
Expected Return on Plan Assets	(24.5		)	(24.1		)	(23.6		)	(9.3		)	(9.9		)	(10.0		)
Amortization of Prior Service Cost (Credit)	0.4			0.3			0.4			(6.0		)	(5.9		)	(5.9		)
Amortization of Net Actuarial Loss	7.1			9.0			11.1			2.8			1.5			1.8
Net Periodic Benefit Cost (Credit)	8.3			10.0			14.0			(6.7		)	(8.7		)	(7.5		)
Capitalized Portion	(3.6		)	(4.7		)	(6.0		)	3.4			4.1			3.2
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	4.7		$	5.3		$	8.0		$	(3.3	)	$	(4.6	)	$	(4.3	)

Estimated amounts expected to be amortized to net periodic benefit costs (credits) and the impact on the balance sheet during 2017 are shown in the following table:

	Pension Plans		Other Postretirement Benefit Plans
Components	(in millions)
Net Actuarial Loss	$	7.0	$	3.0
Prior Service Credit	—		(5.9		)
Total Estimated 2017 Amortization	$	7.0	$	(2.9	)
Expected to be Recorded as
Regulatory Asset	$	6.7	$	(3.0	)
Deferred Income Taxes	0.1		—
Net of Tax AOCI	0.2		0.1
Total	$	7.0	$	(2.9	)

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 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 totaled $5 million in 2016, $5 million in 2015 and $5 million in 2014.

F-40

9. DERIVATIVES AND HEDGING

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

Risk Management Strategies

AEP Texas’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEP Texas utilizes financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. AEP Texas does not hedge all fuel price risk. The gross notional volumes of AEP Texas’ outstanding derivative contracts for heating oil and gasoline were 2 million gallons as of December 31, 2016 and 2015.

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

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. For the December 31, 2016 and 2015 balance sheets, AEP Texas netted $185 thousand and $0, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $0 and $412 thousand, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

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

Fair Value of Derivative Instruments
December 31, 2016
			Gross			Net Amounts of
			Amounts			Assets/Liabilities
	Risk		Offset in the			Presented in the
	Management		Statement of			Statement of
	Contracts		Financial			Financial
Balance Sheet Location	Commodity (a)		Position (b)			Position (c)
	(in millions)
Current Risk Management Assets	$	0.4	$	(0.2	)	$	0.2
Long-term Risk Management Assets	—		—			—
Total Assets	0.4		(0.2		)	0.2
Current Risk Management Liabilities	—		—			—
Long-term Risk Management Liabilities	—		—			—
Total Liabilities	—		—			—
Total MTM Derivative Contract Net Assets (Liabilities)	$	0.4	$	(0.2	)	$	0.2

F-41

Fair Value of Derivative Instruments
December 31, 2015
				Gross			Net Amounts of
				Amounts			Assets/Liabilities
	Risk			Offset in the			Presented in the
	Management			Statement of			Statement of
	Contracts			Financial			Financial
Balance Sheet Location	Commodity (a)			Position (b)			Position (c)
	(in millions)
Current Risk Management Assets	$	—		$	—		$	—
Long-term Risk Management Assets	—			—			—
Total Assets	—			—			—
Current Risk Management Liabilities	0.7			(0.4		)	0.3
Long-term Risk Management Liabilities	—			—			—
Total Liabilities	0.7			(0.4		)	0.3
Total MTM Derivative Contract Net Assets (Liabilities)	$	(0.7	)	$	0.4		$	(0.3	)

(a) 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.”

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

(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.

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

Amount of Gain (Loss) Recognized on

Risk Management Contracts

	Years Ended December 31,
Location of Gain (Loss)	2016			2015			2014
	(in millions)
Electric Generation, Transmission and Distribution Revenues	$	—		$	—		$	0.1
Other Operation Expense	(0.4		)	(0.8		)	—
Maintenance Expense	(0.4		)	(0.7		)	—
Regulatory Assets (a)	0.8			0.4			(1.2		)
Regulatory Liabilities (a)	0.4			—			—
Total Gain (Loss) on Risk Management Contracts	$	0.4		$	(1.1	)	$	(1.1	)

(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

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 AEP Texas’s statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on AEP Texas’s 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.”

F-42

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 effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on its balance sheets until the period the hedged item affects Net Income. AEP Texas would record hedge ineffectiveness as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable.

AEP Texas reclassifies gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on its balance sheets into Interest Expense on its statements of income in those periods in which hedged interest payments occur. During 2016, 2015 and 2014, AEP Texas did not apply cash flow hedging to outstanding interest rate derivatives.

During 2016, 2015 and 2014, hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies discussed above.

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on AEP Texas’ balance sheets and the reasons for changes in cash flow hedges, see Note 3.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on AEP Texas’ balance sheets were:

Impact of Cash Flow Hedges on the Balance Sheet
	Interest Rate
	December 31,
	2016			2015
	(in millions)
Hedging Liabilities (a)	$	—		$	0.4
AOCI Loss Net of Tax	(5.4		)	(6.5		)	(b)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	(0.9		)	(0.9		)	(c)

(a) Hedging Assets and Liabilities are included in Risk Management Assets and Liabilities AEP Texas’s balance sheets.

(b) AOCI Loss Net of Tax includes $(0.3) million related to the Wind Farms. See Note 7 for additional information.

(c) Portion Expected to be reclassified to Net Income During the Next Twelve Months excludes $(0.2) related to the Wind Farms. See Note 7 for additional information.

The actual amounts that AEP Texas reclassifies from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. As of December 31, 2016, AEP Texas is not hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) its exposure to variability in future cash flows related to forecasted transactions.

F-43

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 AEP Texas’ Long-term Debt are summarized in the following table:

	December 31,
	2016				2015
	Book Value		Fair Value		Book Value (a)		Fair Value (a)
	(in millions)
Long-term Debt	$	3,217.7	$	3,463.2	$	3,454.0	$	3,679.8

(a) Amount includes debt related to Desert Sky Wind Farm that has been classified as Liabilities From Discontinued Operations on the balance sheet and has a fair value of $12 million. See Note 7 for additional information.

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, 2016
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Restricted Cash for Securitized Transition Funding	$	146.3	$	—	$	—	$	—		$	146.3
Risk Management Assets
Risk Management Commodity Contracts (a)	—		0.4		—		(0.2		)	0.2
Total Assets	$	146.3	$	0.4	$	—	$	(0.2	)	$	146.5

F-44

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2015
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Restricted Cash for Securitized Transition Funding	$	203.4	$	—	$	—	$	—		$	203.4
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a)	$	—	$	0.7	$	—	$	(0.4	)	$	0.3

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

As of December 31, 2016, AEP Texas had no liabilities measured at fair value on a recurring basis.

There were no transfers between Level 1 and Level 2 during the years ended December 31, 2016, 2015 and 2014.

F-45

11. INCOME TAXES

The details of AEP Texas’ income tax expense before discontinued operations as reported are as follows:

		Years Ended December 31,
		2016			2015			2014
		(in millions)
Federal:
	Current	$	40.9		$	61.4		$	67.1
	Deferred	29.9			(7.1		)	2.7
	Deferred Investment Tax Credits	(1.7		)	(1.7		)	(1.7		)
Total Federal		69.1			52.6			68.1
State and Local:
	Current	(8.8		)	5.6			10.4
	Deferred	(0.4		)	—			(0.1		)
	Deferred Investment Tax Credits	—			—			—
Total State and Local:		(9.2		)	5.6			10.3
Income Tax Expense Before Discontinued Operations		$	59.9		$	58.2		$	78.4

The following is a reconciliation of the difference between the amount of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported:

		Years Ended December 31,
		2016				2015				2014
		(in millions)
Net Income		$	146.6			$	120.3			$	127.9
Discontinued Operations (Net of Income Tax of $27.6, $1.8 and ($0.6) in 2016, 2015 and 2014, Respectively)		48.8				1.4				(0.8			)
Income Tax Expense Before Discontinued Operations		59.9				58.2				78.4
Pretax Income		$	255.3			$	179.9			$	205.5
Income Taxes on Pretax Income at Statutory Rate (35%)		$	89.4			$	63.0			$	71.9
Increase (Decrease) in Income Taxes Resulting from the Following Items:
	Depreciation	0.5				0.5				0.3
	Investment Tax Credits, Net	(1.7			)	(1.7			)	(1.7			)
	State and Local Income Taxes, Net	(6.0			)	3.6				6.7
	Parent Company Loss Benefit	(2.5			)	(3.1			)	(2.1			)
	Tax Adjustments	(4.9			)	(1.6			)	1.5
	U.K. Windfall Tax	(12.9			)	—				—
	Other	(2.0			)	(2.5			)	1.8
Income Tax Expense Before Discontinued Operations		$	59.9			$	58.2			$	78.4
Effective Income Tax Rate		23.5		%		32.4		%		38.2		%

F-46

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

	December 31,
	2016			2015
	(in millions)
Deferred Tax Assets	$	135.8		$	142.6
Deferred Tax Liabilities	(1,667.5		)	(1,620.0		)
Net Deferred Tax Liabilities	$	(1,531.7	)	$	(1,477.4	)
Property Related Temporary Differences	$	(1,056.1	)	$	(960.8	)
Amounts Due from Customers for Future Federal Income Taxes	(5.7		)	(4.1		)
Deferred State Income Taxes	(24.2		)	(0.8		)
Deferred Income Taxes on Other Comprehensive Loss	8.0			8.8
Regulatory Assets	(61.3		)	(45.8		)
Deferred Revenues	18.0			17.6
Securitized Transition Assets	(407.0		)	(488.4		)
All Other, Net	(3.4		)	(3.9		)
Net Deferred Tax Liabilities	$	(1,531.7	)	$	(1,477.4	)

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, 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, 2012 and 2013 started in April 2014. AEP and 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. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, AEP Texas accrues interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.

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 or local income tax examinations by tax authorities for years before 2009.

F-47

Tax Credit Carryforward

As of December 31, 2016 and 2015, AEP Texas had unused federal income tax credits of $249 thousand and $450 thousand, respectively, not all of which have an expiration date. Included in the credit carryforward are federal general business tax credits of $0 and $131 thousand as of December 31, 2016 and 2015, respectively. The federal general business tax credits were fully utilized in 2016.

AEP Texas anticipates future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused.

Uncertain Tax Positions

AEP Texas recognizes interest accruals related to uncertain tax positions in interest income or expense as applicable, and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.”

The following table shows the amounts reported for interest expense, interest income and reversal of prior period interest expense:

	Years Ended December 31,
	2016		2015		2014
	(in millions)
Interest Expense	$	—	$	0.2	$	0.1
Interest Income	0.2		0.2		1.2
Reversal of Prior Period Interest Expense	0.8		—		0.2

The following table shows balances for amounts accrued for the receipt of interest and the payment of interest and penalties:

	December 31,
	2016		2015
	(in millions)
Accrual for Receipt of Interest	$	2.1	$	1.7
Accrual for Payment of Interest and Penalties	0.3		1.0

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

	2016			2015		2014
	(in millions)
Balance as of January 1,	$	27.8		$	22.6	$	21.1
Increase – Tax Positions Taken During a Prior Period	6.5			5.2		3.0
Decrease – Tax Positions Taken During a Prior Period	(15.0		)	—		(0.3		)
Increase – Tax Positions Taken During the Current Year	—			—		—
Decrease – Tax Positions Taken During the Current Year	—			—		—
Decrease – Settlements with Taxing Authorities	(12.8		)	—		—
Decrease – Lapse of the Applicable Statute of Limitations	—			—		(1.2		)
Balance as of December 31,	$	6.5		$	27.8	$	22.6

The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $4 million, $26 million and $22 million for 2016, 2015 and 2014, respectively. Management believes there will be no significant net increase or decrease in unrecognized tax benefits within 12 months of the reporting date.

F-48

Federal Tax Legislation

The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact AEP Texas’ net income or financial condition but did have a favorable impact on cash flows in 2015.

The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 and with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit. The enacted provisions did not materially impact AEP Texas’ net income or financial condition but will have a favorable impact on future cash flows.

Federal Tax Regulations

In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. These final regulations did not materially impact AEP Texas’ net income, cash flows or financial condition.

State Tax Regulations

House Bill 32 was passed by the state of Texas in June 2015, permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact AEP Texas’ net income, cash flows or financial condition.

In March 2016, the Texas Comptroller of Public Accounts issued clarifying guidance regarding the treatment of transmission and distribution expenses included in the computation of taxable income for purposes of calculating the Texas income/franchise tax. The guidance clarified which specific transmission and distribution expenses are included in the computation of the cost of goods sold deduction. This guidance resulted in a net favorable adjustment to net income of $7 million in 2016 for AEP Texas.

F-49

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. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.

Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. For capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. The components of rental costs are as follows:

	Years Ended December 31,
Lease Rental Costs	2016		2015		2014
	(in millions)
Net Lease Expense on Operating Leases (a)	$	9.8	$	8.1	$	6.6
Amortization of Capital Leases	3.4		2.9		2.9
Interest on Capital Leases	0.6		0.4		0.4
Total Lease Rental Costs	$	13.8	$	11.4	$	9.9

(a) Amounts include lease expenses related to Wind Farms that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amount of $1 million for each of the years Ended December 31, 2016, 2015 and 2014, respectively. See Note 7 for additional information.

The following table shows the property, plant and equipment under capital leases and related obligations recorded on AEP Texas’ balance sheets. Capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on AEP Texas’ balance sheets.

	December 31,
	2016		2015
	(in millions)
Property, Plant and Equipment Under Capital Leases
Total Property, Plant and Equipment Under Capital Leases – Other	$	26.1	$	21.0
Accumulated Amortization	7.7		6.2
Net Property, Plant and Equipment Under Capital Leases	$	18.4	$	14.8
Obligations Under Capital Leases
Noncurrent Liability	$	14.8	$	11.7
Liability Due Within One Year	3.6		3.1
Total Obligations Under Capital Leases	$	18.4	$	14.8

Future minimum lease payments consisted of the following as of December 31, 2016:

			Noncancelable
Future Minimum Lease Payments	Capital Leases		Operating Leases
	(in millions)
2017	$	4.2	$	9.6
2018	3.7		8.8
2019	2.6		8.0
2020	2.3		7.3
2021	2.0		6.4
Later Years	6.3		17.9
Total Future Minimum Lease Payments	21.1		$	58.0
Less Estimated Interest Element	2.7
Estimated Present Value of Future Minimum Lease Payments	$	18.4

F-50

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 either the unamortized balance or 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 unamortized balance. As of December 31, 2016, the maximum potential loss for these lease agreements was $9 million assuming the fair value of the equipment is zero at the end of the lease term.

F-51

13. FINANCING ACTIVITIES

Long-term Debt

The following details long-term debt outstanding:

			Weighted
			Average
			Interest Rate
			as of	Interest Rate Ranges as of		Outstanding as of
			December 31,	December 31,		December 31,
Type of Debt		Maturity	2016	2016	2015	2016		2015
						(in millions)
Senior Unsecured Notes		2018-2044	4.75%	2.61%-6.76%	2.61%-6.76%	$	1,241.3	$	1,240.6
Pollution Control Bonds (a)		2017-2030	4.87%	4.00%-6.30%	4.00%-6.30%	530.3		530.2
Notes Payable - Nonaffiliated (b) (d)		2017			6.60%	—		10.3
Securitization Bonds		2016-2024 (c)	4.07%	0.88%-5.31%	0.88%-6.25%	1,245.8		1,497.2
Other Long-term Debt		2016-2059	2.45%	2.438%-4.5%	1.823%-4.50%	200.3		175.7
Total Long-term Debt Outstanding						$	3,217.7	$	3,454.0
(a)	Insurance policies support certain series.
(b)	Notes Payable represents an outstanding financing agreement issued with a number of banks and other financial institutions.  As of December 31, 2015 the maturity date for this Note Payable was 2017. During 2016, this Note Payable was retired.
(c)	Dates represent the scheduled final payment dates for AEP Texas’ securitization bonds. The legal maturity date is one to two years later. These bonds have been classified for maturity and repayment purposes based on the scheduled final payment date.
(d)	Amount includes debt related to Desert Sky Wind Farm that has been classified as Liabilities From Discontinued Operations on the balance sheet. See Note 7 for additional information.

Long-term debt outstanding as of December 31, 2016 is payable as follows:

												After
		2017		2018		2019		2020		2021		2021		Total
		(in millions)
Principal Amount		$	263.1	$	266.1	$	501.1	$	317.7	$	66.2	$	1,823.5	$	3,237.7
Unamortized Discount, Net and Debt Issuance Costs														(20.0		)
Total Long-term Debt
	Outstanding													$	3,217.7

In January 2017, AEP Texas retired $90 million of Securitization Bonds.

In February 2017, AEP Texas received an equity contribution of $200 million from Parent.

Dividend Restrictions

Parent depends on AEP Texas and other AEP subsidiaries to pay dividends to shareholders. 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 also has credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of AEP Texas. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements.

As of December 31, 2016, 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 billion.

F-52

As of December 31, 2016, the Federal Power Act restriction does not limit the ability of AEP Texas to pay dividends out of retained earnings. However, the credit agreement covenant restrictions can limit the ability of AEP Texas to pay dividends out of retained earnings. As of December 31, 2016, the amount of any such restrictions was $508 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, a Nonutility Money Pool, which funds a majority of AEP’s nonutility subsidiaries, and direct borrowing from AEP. 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 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEP Texas’ balance sheets. AEP Texas’ Utility Money Pool activity and corresponding authorized borrowing limits are described in the following table:

									Net Loans to
	Maximum		Maximum		Average		Average		(Borrowings from)			Authorized
	Borrowings		Loans		Borrowings		Loans		the Utility Money			Short-Term
	from the Utility		to the Utility		from the Utility		to the Utility		Pool as of			Borrowing
Year	Money Pool		Money Pool		Money Pool		Money Pool		December 31,			Limit
	(in millions)
2016	$	176.9	$	138.9	$	87.5	$	79.8	$	(174.5	)	$	400.0
2015	269.8		159.6		184.5		121.1		138.9			500.0

The activity in the above table does not include short-term lending activity of AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company LLC (TNGC), which is a participant in the Nonutility Money Pool. The amount of outstanding loans to (borrowings from) the Nonutility Money Pool are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEP Texas’ balance sheets. TNGC had the following activity in the Nonutility Money Pool:

Net Loans to

Maximum

Maximum

Average

Average

(Borrowings from)

Borrowings

Loans

Borrowings

Loans

the Nonutility

from the Nonutility

to the Nonutility

from the Nonutility

to the Nonutility

Money Pool as of

Year

Money Pool

Money Pool

Money Pool

Money Pool

December 31,

(in millions)

2016

(a)

$

12.5

$

27.0

$

12.0

$

12.3

$

8.6

2015

(b)

31.3

—

16.0

—

(10.6

)

(a)

Amounts include short-term loans and (borrowings) related to Wind Farms that have been classified as Assets and Liabilities From Discontinued Operation, which were transferred to a competitive AEP Affiliate in December 2016. See Note 7 for additional information.

(b)

Amounts include short-term loans and (borrowings) related to Wind Farms that have been classified as Assets and Liabilities From Discontinued Operations, respectively, on AEP Texas’ balance sheet. See Note 7 for additional information.

F-53

The amounts of outstanding loans to (borrowings from) AEP are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEP Texas’ balance sheets. AEP Texas’ direct borrowing activity with AEP is described in the following table:

										Net Loans to
		Maximum		Maximum		Average		Average		(Borrowings from)
		Borrowings		Loans		Borrowings		Loans		AEP as of
Year		from AEP		to AEP		from AEP		to AEP		December 31,
		(in millions)
2016	(a)	$	55.0	$	5.0	$	42.5	$	5.0	$	5.0
2015	(b)	44.5		—		36.5		—		(38.6		)
(a)	Amounts include short-term loans and (borrowings) related to Wind Farms that have been classified as Assets and Liabilities From Discontinued Operation, which were transferred to a competitive AEP Affiliate in December 2016. See Note 7 for additional information.
(b)	Amounts include short-term loans and (borrowings) related to Wind Farms that have been classified as Assets and Liabilities From Discontinued Operations, respectively, on AEP Texas’ balance sheet. See Note 7 for additional information.

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		Average
	Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate
	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds
	Borrowed		Borrowed		Loaned		Loaned		Borrowed		Loaned
Years Ended	from the Utility		from the Utility		to the Utility		to the Utility		from the Utility		to the Utility
December 31,	Money Pool		Money Pool		Money Pool		Money Pool		Money Pool		Money Pool
2016	1.02	%	0.75	%	0.83	%	0.69	%	0.88	%	0.72	%
2015	0.59	%	0.39	%	0.87	%	0.37	%	0.46	%	0.52	%
2014	0.59	%	0.24	%	—	%	—	%	0.29	%	—	%

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

	Maximum		Minimum		Maximum		Minimum		Average		Average
	Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate
	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds
	Borrowed from		Borrowed from		Loaned to		Loaned to		Borrowed from		Loaned to
Years Ended	the Nonutility		the Nonutility		the Nonutility		the Nonutility		the Nonutility		the Nonutility
December 31,	Money Pool		Money Pool		Money Pool		Money Pool		Money Pool		Money Pool
2016	1.11	%	0.97	%	1.02	%	0.75	%	1.00	%	0.86	%
2015	1.14	%	0.64	%	—	%	—	%	0.76	%	—	%
2014	0.85	%	0.53	%	0.50	%	—	%	0.61	%	0.29	%

Maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:

	Maximum		Minimum		Maximum		Minimum		Average		Average
	Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate
	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds
Years Ended	Borrowed from		Borrowed from		Loaned to		Loaned to		Borrowed from		Loaned to
December 31,	AEP		AEP		AEP		AEP		AEP		AEP
2016	0.98	%	0.69	%	1.02	%	0.99	%	0.83	%	1.00	%
2015	0.87	%	0.37	%	—	%	—	%	0.48	%	—	%
2014	0.59	%	0.24	%	—	%	—	%	0.29	%	—	%

F-54

Interest expense and interest income related to the Utility Money Pool are included in Interest Expense and Interest Income, respectively, on AEP Texas’ statements of income. For amounts borrowed from and advanced to the Utility Money Pool, AEP Texas incurred the following amounts of interest expense and earned the following amounts of interest income:

	Years Ended December 31,
	2016		2015		2014
	(in millions)
Interest Expense	$	0.6	$	0.7	$	0.4
Interest Income	0.2		0.2		—

Interest expense and interest income related to the Nonutility Money Pool are included in Interest Expense and Interest Income, respectively, on AEP Texas’ statements of income. For amounts borrowed from and advanced to the Nonutility Money Pool, AEP Texas incurred the following amounts of interest expense and earned the following amounts of interest income:

	Years Ended December 31,
	2016		2015		2014
	(in millions)
Interest Expense	$	0.6	$	0.7	$	0.5
Interest Income	0.5		0.3		0.2

Interest expense and interest income related to the direct borrowing from AEP are included in Interest Expense and Interest Income, respectively, on AEP Texas’ statements of income. For amounts borrowed from and advanced to AEP, AEP Texas incurred the following amounts of interest expense and earned the following amounts of interest income:

	Years Ended December 31,
	2016		2015		2014
	(in millions)
Interest Expense	$	0.4	$	0.2	$	0.2
Interest Income	—		—		—

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 6.

F-55

14. RELATED PARTY TRANSACTIONS

For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 11 and “Corporate Borrowing Program – AEP System” section of Note 13.

Affiliated Revenues

The following table shows the revenues derived from direct sales to affiliates and other revenues for the years ended December 31, 2016, 2015 and 2014:

	Years Ended December 31,
Related Party Revenues	2016		2015		2014
	(in millions)
Direct Sales to AEPEP Affiliate	$	73.9	$	76.9	$	91.2
Other Revenues	1.8		1.6		1.6
Total Affiliated Revenues	$	75.7	$	78.5	$	92.8

The above summarized related party revenues are reported in Sales to AEP Affiliates on AEP Texas’ statements of income.

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 $29 million, $27 million and $25 million for transmission services in 2016, 2015 and 2014, respectively. The billings are recorded in Other Operation expenses on AEP Texas’ statements of income.

Oklaunion PPA between AEP Texas and AEPEP

On January 1, 2007, AEP Texas began 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 Plant. This PPA is effective through December 2027. AEPEP is to pay 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.

AEP Texas recorded revenue of $74 million, $77 million and $91 million from AEPEP for the years ended December 31, 2016, 2015 and 2014, respectively. These amounts are included in Sales to AEP Affiliates on AEP Texas’ statements of income.

F-56

Sales and Purchases of Property

AEP Texas had affiliated sales and purchases of electric property individually amounting to $100 thousand or more and sales and purchases of meters and transformers. 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, 2016, 2015 and 2014:

	Years Ended December 31,
	2016		2015		2014
	(in millions)
Sales	$	0.3	$	0.6	$	5.6
Purchases	0.7		0.9		1.1

The amounts above are recorded in Property, Plant and Equipment on the balance sheets.

Intercompany Billings

AEP Texas performs certain utility services for other AEP subsidiaries 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.

F-57

15. VARIABLE INTEREST ENTITIES

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE.  A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities”. In determining whether AEP Texas is the primary beneficiary of a VIE, management considers whether AEP Texas has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.

Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that AEP Texas is the primary beneficiary of Transition Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Transition Funding. The securitized bonds totaled $1.2 billion and $1.5 billion as of December 31, 2016 and 2015, respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Transition Funding has securitized transition assets of $1.1 billion and $1.3 billion as of December 31, 2016 and 2015, respectively, which are presented separately on the face of the balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from AEP Texas under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Transition Funding’s securitized transition asset and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs.

The balances below represent the assets and liabilities of Transition Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.

AEP TEXAS AND SUBSIDIARIES

VARIABLE INTEREST ENTITIES

December 31, 2016 and 2015

(in millions)

	Transition Funding
ASSETS	2016		2015
Current Assets	$	184.8	$	234.1
Other Noncurrent Assets (a)	1,149.4		1,365.7
Total Assets	$	1,334.2	$	1,599.8
LIABILITIES AND EQUITY
Current Liabilities	$	251.9	$	291.7
Noncurrent Liabilities	1,064.2		1,290.0
Equity	18.1		18.1
Total Liabilities and Equity	$	1,334.2	$	1,599.8

(a) Includes an intercompany item eliminated in consolidation as of December 31, 2016 and 2015 of $61.1 million and $68.2 million, respectively.

F-58

AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. AEP Texas’ total billings from AEPSC for the years ended December 31, 2016, 2015 and 2014 were $142 million, $133 million and $122 million, respectively. The carrying amount of liabilities associated with AEPSC as of December 31, 2016 and 2015 was $23 million and $17 million, respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability.

F-59

16. PROPERTY, PLANT AND EQUIPMENT

Property, Plant and Equipment is shown functionally on the face of AEP Texas’ balance sheets. The following table includes AEP Texas’ total plant balances as of December 31, 2016 and 2015:

	December 31,
	2016		2015
	(in millions)
Regulated Property, Plant and Equipment
Transmission	$	2,623.6	$	2,352.9
Distribution	3,527.2		3,343.6
Other	432.1		403.5
CWIP	385.0		288.1
Less: Accumulated Depreciation	1,354.4		1,301.3
Total Regulated Property, Plant and Equipment - Net	5,613.5		5,086.8
Nonregulated Property, Plant and Equipment - Net	167.2		173.0		(a)
Total Property, Plant and Equipment - Net	$	5,780.7	$	5,259.8	(a)

(a) Amount excludes $128 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See Note 7 for additional information.

Depreciation

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

	2016				2015				2014
Functional Class of Property	Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges
		(in years)				(in years)				(in years)
Regulated
Transmission	1.8%	45	-	81	1.8%	45	-	81	1.8%	45	-	81
Distribution	3.3%	7	-	70	3.3%	7	-	70	3.3%	22	-	70
Other	8.3%	5	-	50	9.7%	5	-	50	8.3%	10	-	50
Nonregulated
Generation	2.8%	60			2.5%	60			2.6%	60

For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal cost is expensed as incurred.

Asset Retirement Obligations (ARO)

AEP Texas records ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of ash disposal facilities and asbestos removal. 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.

F-60

AEP Texas recorded an increase in Asset Retirement Obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule which, was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants.  The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment.

The following is a reconciliation of the 2016 and 2015 aggregate carrying amounts of ARO for AEP Texas:

										Revisions in
	ARO as of		Accretion		Liabilities		Liabilities			Cash Flow		ARO as of
Year	January 1,		Expense		Incurred		Settled			Estimates		December 31,
	(in millions)
2016	$	24.0	$	1.1	$	—	$	(0.1	)	$	0.5	$	25.5
2015	3.5		0.6		19.9		—			—		24.0

AFUDC and Interest Capitalization

AEP Texas’ amounts of allowance for equity and borrowed funds used during construction are summarized in the following table:

	Years Ended December 31,
	2016		2015		2014
	(in millions)
Allowance for Equity Funds Used During Construction	$	9.2	$	6.7	$	4.8
Allowance for Borrowed Funds Used During Construction	5.9		4.5		3.6

Jointly-owned Electric Facilities

AEP Texas has a 54.7% ownership share of Unit No. 1 at the Oklaunion Generating Station. In addition to AEP Texas, the Oklaunion Generating Station is jointly-owned by PSO and various non-affiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs in the same proportion as its ownership interest. AEP Texas’ proportionate share of the operating costs associated with this facility is included in its statements of income and the investment and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment 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, 2016
Oklaunion Generating Station, Unit 1 (a)		Coal	54.7	%	$	349.6	$	0.9	$	186.5
AEP Texas’ Share as of December 31, 2015
Oklaunion Generating Station, Unit 1 (a)		Coal	54.7	%	$	342.5	$	5.4	$	178.0
(a)	Operated by PSO.

F-61

17. BUSINESS SEGMENTS

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

F-62

AEP Texas and Subsidiaries

2017 Third Quarter Report

Consolidated Financial Statements

GLOSSARY OF TERMS

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

Term	Meaning
AEP	American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority owned consolidated subsidiaries and consolidated affiliates.
AEP System	American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP Texas	AEP Texas, an AEP electric utility subsidiary.
AEPSC	American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AOCI	Accumulated Other Comprehensive Income.
ASU	Accounting Standards Update.
FASB	Financial Accounting Standards Board.
FERC	Federal Energy Regulatory Commission.
FTR	Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP	Accounting Principles Generally Accepted in the United States of America.
IRS	Internal Revenue Service.
MTM	Mark-to-Market.
Nonutility Money Pool	Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
OPEB	Other Postretirement Benefit Plans.
OTC	Over the counter.
Parent	American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PUCT	Public Utility Commission of Texas.
Risk Management Contracts	Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
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.
Transition Funding	AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.
Utility Money Pool	Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
Wind Farms	Desert Sky and Trent Wind Farms, previously owned by a subsidiary of AEP Utilities, Inc., were transferred to an affiliated company on December 31, 2016.

F-64

AEP TEXAS AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2017 and 2016

(in millions)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
REVENUES
Electric Transmission and Distribution	$	411.5		$	379.1		$	1,111.4		$	1,040.2
Sales to AEP Affiliates	18.9			24.4			50.8			57.0
Other Revenues	0.8			0.4			2.1			2.2
TOTAL REVENUES	431.2			403.9			1,164.3			1,099.4
EXPENSES
Fuel and Other Consumables Used for Electric Generation	8.3			14.2			17.2			24.7
Other Operation	116.6			119.5			330.1			327.9
Maintenance	19.3			15.8			58.1			51.3
Depreciation and Amortization	124.0			112.0			343.0			316.0
Taxes Other Than Income Taxes	33.3			30.0			93.3			81.3
TOTAL EXPENSES	301.5			291.5			841.7			801.2
OPERATING INCOME	129.7			112.4			322.6			298.2
Other Income (Expense):
Interest Income	0.5			0.8			1.6			2.6
Allowance for Equity Used During Construction	—			2.0			2.2			7.0
Interest Expense	(35.3		)	(36.2		)	(105.6		)	(108.5		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	94.9			79.0			220.8			199.3
Income Tax Expense	30.6			23.5			74.2			59.1
INCOME FROM CONTINUING OPERATIONS	64.3			55.5			146.6			140.2
LOSS FROM DISCONTINUED OPERATIONS, NET OF TAX	—			47.4			—			49.4
NET INCOME	$	64.3		$	8.1		$	146.6		$	90.8
The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page F-71.

F-65

AEP TEXAS AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Nine Months Ended September 30, 2017 and 2016

(in millions)

(Unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016
Net Income	$	64.3	$	8.1	$	146.6	$	90.8
OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.2 and $0.1 for the Three Months Ended September 30, 2017 and 2016, Respectively, and $0.4 and $0.4 for the Nine Months Ended September 30, 2017 and 2016, Respectively	0.2		0.3		0.7		0.8
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2017 and 2016, Respectively, and $0.1 and $0.1 for the Nine Months Ended September 30, 2017 and 2016, Respectively	0.1		—		0.2		0.2
TOTAL OTHER COMPREHENSIVE INCOME	0.3		0.3		0.9		1.0
TOTAL COMPREHENSIVE INCOME	$	64.6	$	8.4	$	147.5	$	91.8
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page F-71.

F-66

AEP TEXAS AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Nine Months Ended September 30, 2017 and 2016

(in millions)

(Unaudited)

	Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2015	$	804.9	$	887.0		$	(17.2	)	$	1,674.7
Common Stock Dividends			(25.5		)				(25.5		)
Net Income			90.8						90.8
Other Comprehensive Income						1.0			1.0
TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2016	$	804.9	$	952.3		$	(16.2	)	$	1,741.0
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2016	$	857.9	$	814.1		$	(14.9	)	$	1,657.1
Capital Contribution from Parent	200.0								200.0
Net Income			146.6						146.6
Other Comprehensive Income						0.9			0.9
TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2017	$	1,057.9	$	960.7		$	(14.0	)	$	2,004.6
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page F-71.

F-67

AEP TEXAS AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2017 and December 31, 2016

(in millions)

(Unaudited)

	September 30,			December 31,
	2017			2016
CURRENT ASSETS
Cash and Cash Equivalents	$	0.1		$	0.6
Restricted Cash for Securitized Transition Funding	123.0			146.3
Advances to Affiliates	445.6			8.6
Accounts Receivable:
Customers	124.5			94.4
Affiliated Companies	12.1			11.8
Accrued Unbilled Revenues	81.9			64.8
Miscellaneous	0.2			0.1
Allowance for Uncollectible Accounts	(0.6		)	(0.6		)
Total Accounts Receivable	218.1			170.5
Fuel	4.1			9.8
Materials and Supplies	54.8			49.0
Risk Management Assets	0.1			0.2
Accrued Tax Benefits	13.1			0.7
Prepayments and Other Current Assets	6.5			3.5
TOTAL CURRENT ASSETS	865.4			389.2
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	350.6			349.6
Transmission	2,882.9			2,623.6
Distribution	3,679.3			3,527.2
Other Property, Plant and Equipment	465.1			436.4
Construction Work in Progress	554.1			385.9
Total Property, Plant and Equipment	7,932.0			7,322.7
Accumulated Depreciation and Amortization	1,592.3			1,542.0
TOTAL PROPERTY, PLANT AND EQUIPMENT –NET	6,339.7			5,780.7
OTHER NONCURRENT ASSETS
Regulatory Assets	427.1			347.2
Securitized Transition Assets
(September 30, 2017 and December 31, 2016 Amounts Include $932 and $1,088.3, Respectively, Related to Transition Funding)	956.2			1,118.7
Deferred Charges and Other Noncurrent Assets	91.5			73.3
TOTAL OTHER NONCURRENT ASSETS	1,474.8			1,539.2
TOTAL ASSETS	$	8,679.9		$	7,709.1
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page F-71.

F-68

AEP TEXAS AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

September 30, 2017 and December 31, 2016

(in millions)

(Unaudited)

	September 30,			December 31,
	2017			2016
CURRENT LIABILITIES
Advances from Affiliates	$	—		$	169.5
Accounts Payable:
General	280.5			129.5
Affiliated Companies	23.2			30.5
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2017 and December 31, 2016 Amounts Include $235.5 and $222.2, Respectively, Related to Transition Funding)	306.4			263.1
Accrued Taxes	82.3			68.2
Accrued Interest
(September 30, 2017 and December 31, 2016 Amounts Include $11.6 and $20.2, Respectively, Related to Transition Funding)	41.0			41.5
Other Current Liabilities	54.7			94.8
TOTAL CURRENT LIABILITIES	788.1			797.1
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated
(September 30, 2017 and December 31, 2016 Amounts Include $823.7 and $1,023.6, Respectively, Related to Transition Funding)	3,416.1			2,954.6
Deferred Income Taxes	1,657.9			1,531.7
Regulatory Liabilities and Deferred Investment Tax Credits	696.1			660.8
Oklaunion Purchase Power Agreement	51.9			51.5
Deferred Credits and Other Noncurrent Liabilities	65.2			56.3
TOTAL NONCURRENT LIABILITIES	5,887.2			5,254.9
TOTAL LIABILITIES	6,675.3			6,052.0
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Paid-in Capital	1,057.9			857.9
Retained Earnings	960.7			814.1
Accumulated Other Comprehensive Income (Loss)	(14.0		)	(14.9		)
TOTAL COMMON SHAREHOLDER’S EQUITY	2,004.6			1,657.1
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	8,679.9		$	7,709.1
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page F-71.

F-69

AEP TEXAS AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2017 and 2016

(in millions)

(Unaudited)

	Nine Months Ended September 30,
	2017			2016
OPERATING ACTIVITIES
Net Income	$	146.6		$	90.8
Loss from Discontinued Operations, Net of Tax	—			(49.4		)
Income from Continuing Operations	146.6			140.2
Adjustments to Reconcile Income from Continuing Operations to Net Cash Flows from Continuing Operating Activities:
Depreciation and Amortization	343.0			316.0
Deferred Income Taxes	124.1			31.8
Allowance for Equity Funds Used During Construction	(2.2		)	(7.0		)
Mark-to-Market of Risk Management Contracts	0.1			(0.4		)
Pension Contributions to Qualified Plant Trust	(8.8		)	(8.2		)
Property Taxes	(15.9		)	(13.4		)
Change in Regulatory Assets	(74.1		)	2.1
Change in Other Noncurrent Assets	(27.3		)	(18.0		)
Change in Other Noncurrent Liabilities	7.4			(4.9		)
Changes in Certain Components of Continuing Working Capital:
Accounts Receivable, Net	(47.6		)	(55.2		)
Fuel, Materials and Supplies	(0.1		)	7.9
Accounts Payable	77.3			(11.7		)
Accrued Taxes, Net	1.7			(34.6		)
Other Current Assets	(2.5		)	(2.3		)
Other Current Liabilities	(31.2		)	(24.9		)
Net Cash Flows from Continuing Operating Activities	490.5			317.4
INVESTING ACTIVITIES
Construction Expenditures	(617.5		)	(438.9		)
Change in Restricted Cash for Securitized Transition Funding	23.3			92.6
Change in Advances to Affiliates, Net	(437.0		)	152.9
Other Investing Activities	11.5			10.4
Net Cash Flows Used for Continuing Investing Activities	(1,019.7		)	(183.0		)
FINANCING ACTIVITIES
Capital Contribution from Parent	200.0			—
Issuance of Long-term Debt – Nonaffiliated	749.9			199.2
Change in Advances from Affiliates, Net	(169.5		)	88.6
Retirement of Long-term Debt – Nonaffiliated	(248.4		)	(395.2		)
Principal Payments for Capital Lease Obligations	(3.0		)	(2.4		)
Dividends Paid on Common Stock	—			(25.5		)
Other Financing Activities	(0.3		)	0.7
Net Cash Flows from (Used for) Continuing Financing Activities	528.7			(134.6		)
Net Cash Flows from Discontinued Operating Activities	—			26.2
Net Cash Flows from Discontinued Investing Activities	—			0.4
Net Cash Flows Used for Discontinued Financing Activities	—			(25.7		)
Net Increase (Decrease) in Cash and Cash Equivalents	(0.5		)	0.7
Cash and Cash Equivalents at Beginning of Period	0.6			5.0
Cash and Cash Equivalents at End of Period	$	0.1		$	5.7
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	101.1		$	109.8
Net Cash Paid (Received) for Income Taxes	(23.3		)	62.2
Noncash Acquisitions Under Capital Leases	5.3			5.8
Construction Expenditures Included in Current Liabilities as of September 30,	166.1			60.0
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page F-71.

F-70

INDEX OF CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Page Number
Significant Accounting Matters	F-72
New Accounting Pronouncements	F-73
Comprehensive Income	F-76
Rate Matters	F-78
Commitments, Guarantees and Contingencies	F-79
Disposition	F-80
Benefit Plans	F-81
Derivatives and Hedging	F-82
Fair Value Measurements	F-85
Income Taxes	F-87
Financing Activities	F-88
Business Segments	F-91

F-71

1. SIGNIFICANT ACCOUNTING MATTERS

General

The unaudited condensed consolidated financial statements and footnotes were prepared in accordance with GAAP for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods. Net income for the three and nine months ended September 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017. The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in AEP Texas’ 2016 Annual Report.

Subsequent Events

Management reviewed subsequent events through October 26, 2017, the date that the third quarter 2017 report was available to be issued.

F-72

2. NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to AEP Texas’ business. The following final 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 clarifying 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, 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 flow arising from contracts.

The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted.

Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. The evaluation of revenue streams, new contracts and the new revenue standard’s disclosure requirements continues during the fourth quarter of 2017, in particular with respect to various on going industry implementation issues. Management will continue to analyze the related impacts to revenue recognition and monitor any new industry implementation issues that arise. Further, given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. Management plans to adopt ASU 2014-09 effective January 1, 2018.

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

In January 2016, the FASB issued ASU 2016-01 enhancing 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. 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.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. 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 2016-01 effective January 1, 2018.

F-73

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 lease 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.

The new accounting guidance is effective for annual periods beginning after December 15, 2019 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented.

Management continues to analyze the impact of the new lease standard. During 2016 and 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Multiple lease system options were also evaluated. Management plans to elect certain of 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.
Lease term	Elect to use hindsight to determine the lease term.

Evaluation of new lease contracts continues and the process of implementing a compliant lease system solution began in the third quarter of 2017. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019.

ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09)

In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income.

Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption.

F-74

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, 2020 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 effective January 1, 2020.

ASU 2016-18 “Restricted Cash” (ASU 2016-18)

In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows.

The new accounting guidance is effective for annual periods beginning after December 15, 2018. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report.

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 in 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 will be eligible for capitalization as applicable following labor. For 2016, AEP Texas’ actual non-service cost components were a credit of $7 million, of which approximately 50% was capitalized.

The new accounting guidance is effective for annual periods beginning after December 15, 2018, and interim periods within annual periods beginning after December 15, 2019. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management plans to adopt 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 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 reduce the complexity of applying hedge accounting. Under the new standard, the concept of recognizing hedge ineffectiveness within the statements of income for cash flow hedges, which has historically been immaterial to AEP, will be eliminated. In addition, certain required tabular disclosures relating to fair value and cash flow hedges will be modified.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for any interim or annual period after August 2017. Management is analyzing the impact of this new standard, including the possibility of early adoption, and at this time, cannot estimate the impact of adoption on net income.

F-75

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 three and nine months ended September 30, 2017 and 2016. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details.

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended September 30, 2017

	Cash Flow Hedges
				Pension
	Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of June 30, 2017	$	(4.9	)	$	(9.4	)	$	(14.3	)
Change in Fair Value Recognized in AOCI	—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense	0.3			—			0.3
Amortization of Prior Service Cost (Credit)	—			(0.1		)	(0.1		)
Amortization of Actuarial (Gains)/Losses	—			0.2			0.2
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.3			0.1			0.4
Income Tax (Expense) Credit	0.1			—			0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.2			0.1			0.3
Net Current Period Other Comprehensive Income	0.2			0.1			0.3
Balance in AOCI as of September 30, 2017	$	(4.7	)	$	(9.3	)	$	(14.0	)

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended September 30, 2016

	Cash Flow Hedges
				Pension
	Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of June 30, 2016	$	(6.0	)	$	(10.5	)	$	(16.5	)
Change in Fair Value Recognized in AOCI	—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense	0.4			—			0.4
Amortization of Prior Service Cost (Credit)	—			(0.1		)	(0.1		)
Amortization of Actuarial (Gains)/Losses	—			0.1			0.1
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.4			—			0.4
Income Tax (Expense) Credit	0.1			—			0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.3			—			0.3
Net Current Period Other Comprehensive Income	0.3			—			0.3
Balance in AOCI as of September 30, 2016	$	(5.7	)	$	(10.5	)	$	(16.2	)

F-76

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Nine Months Ended September 30, 2017

	Cash Flow Hedges
				Pension
	Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2016	$	(5.4	)	$	(9.5	)	$	(14.9	)
Change in Fair Value Recognized in AOCI	—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense	1.0			—			1.0
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) Credit	1.0			0.3			1.3
Income Tax (Expense) Credit	0.3			0.1			0.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.7			0.2			0.9
Net Current Period Other Comprehensive Income	0.7			0.2			0.9
Balance in AOCI as of September 30, 2017	$	(4.7	)	$	(9.3	)	$	(14.0	)

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Nine Months Ended September 30, 2016

	Cash Flow Hedges
				Pension
	Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2015	$	(6.5	)	$	(10.7	)	$	(17.2	)
Change in Fair Value Recognized in AOCI	—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense	1.2			—			1.2
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) Credit	1.2			0.3			1.5
Income Tax (Expense) Credit	0.4			0.1			0.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.8			0.2			1.0
Net Current Period Other Comprehensive Income	0.8			0.2			1.0
Balance in AOCI as of September 30, 2016	$	(5.7	)	$	(10.5	)	$	(16.2	)

F-77

4. RATE MATTERS

As discussed in AEP Texas’ 2016 Annual Report, AEP Texas is involved in rate and regulatory proceedings at the FERC and the PUCT. The Effects of Regulation note within AEP Texas’ 2016 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2017 and updates AEP Texas’ 2016 Annual Report.

Regulatory Assets Pending Final Regulatory Approval

	September 30,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Storm-Related Costs	$	97.4	$	25.1
Regulatory Assets Currently Not Earning a Return
Rate Case Expenses	0.1		0.1
Total Regulatory Assets Pending Final Regulatory Approval	$	97.5	$	25.2

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

AEP Texas Interim Transmission and Distribution Rates

As of September 30, 2017, AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $697 million. A base rate review could produce a refund 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.

Hurricane Harvey

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 September 30, 2017, the total balance of AEP Texas’ deferred storm costs is approximately $97 million including approximately $73 million of incremental storm expenses as a regulatory asset related to Hurricane Harvey. Management is currently in the early stages of analyzing the impact of potential insurance claims and recoveries and, at this time, cannot estimate the impact of this amount. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. AEP Texas is currently evaluating recovery options for the regulatory asset; however, management believes the asset is probable of recovery. The other named hurricanes did not have a material impact on AEP’s operations in the third quarter of 2017. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flows and financial condition.

F-78

5. COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within AEP Texas’ 2016 Annual Report should be read in conjunction with this report.

GUARANTEES

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

Letters of Credit

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under five uncommitted facilities totaling $445 million. As of September 30, 2017, AEP Texas’ maximum future payment for letters of credit issued under the uncommitted credit facilities was $3 million with a maturity of January 2018.

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 September 30, 2017, there were no material liabilities recorded for any indemnifications.

Master Lease Agreements

AEP Texas leases certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or 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 unamortized balance. As of September 30, 2017, the maximum potential loss for these lease agreements was $10 million assuming the fair value of the equipment is zero at the end of the lease term.

F-79

6. DISPOSITION

2016

Wind Farms

In December 2016, TCC and TNC merged into AEP Utilities, Inc. Upon merger, AEP Utilities, Inc. changed its name to AEP Texas. Subsequent to the merger, AEP Texas exited the merchant generation business by transferring all of the common stock of the Wind Farms to a competitive AEP affiliate. No gain or loss was recognized and no cash was exchanged related to the disposition of the Wind Farms.

In the fourth quarter of 2016, the Wind Farms were determined to be discontinued operations. Accordingly, results of operations of the Wind Farms have been classified as discontinued operations on AEP Texas’ statements of income as shown in the following table:

	Three Months Ended			Nine Months Ended
	September 30, 2016			September 30, 2016
	(in millions)
Revenue	$	4.8		$	13.2
Other Operation Expense	74.3			77.5
Maintenance Expense	0.7			2.8
Depreciation and Amortization Expense	2.8			8.4
Taxes Other Than Income Taxes	0.3			1.0
Total Expenses	78.1			89.7
Other Income (Expense)	(0.2		)	(0.6		)
Pretax Loss of Discontinued Operations	(73.5		)	(77.1		)
Income Tax Credit	(26.1		)	(27.7		)
Total Loss on Discontinued Operations as Presented on the Statements of Income	$	(47.4	)	$	(49.4	)

F-80

7. BENEFIT 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.

Components of Net Periodic Benefit Cost

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

	Pension Plans						Other Postretirement Benefit Plans
	Three Months Ended September 30,						Three Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Service Cost	$	2.1		$	1.9		$	0.3		$	0.2
Interest Cost	4.3			4.5			1.2			1.4
Expected Return on Plan Assets	(6.2		)	(6.1		)	(2.2		)	(2.4		)
Amortization of Prior Service Cost (Credit)	—			0.1			(1.5		)	(1.5		)
Amortization of Net Actuarial Loss	1.7			1.7			0.8			0.7
Net Periodic Benefit Cost (Credit)	$	1.9		$	2.1		$	(1.4	)	$	(1.6	)

	Pension Plans						Other Postretirement Benefit Plans
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Service Cost	$	6.4		$	5.6		$	0.7		$	0.5
Interest Cost	12.9			13.3			3.7			3.9
Expected Return on Plan Assets	(18.8		)	(18.2		)	(6.6		)	(7.1		)
Amortization of Prior Service Cost (Credit)	—			0.3			(4.4		)	(4.4		)
Amortization of Net Actuarial Loss	5.2			5.2			2.4			2.1
Net Periodic Benefit Cost (Credit)	$	5.7		$	6.2		$	(4.2	)	$	(5.0	)

F-81

8. DERIVATIVES AND HEDGING

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

Risk Management Strategies

AEP Texas’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEP Texas utilizes financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. AEP Texas does not hedge all fuel price risk. The gross notional volumes of AEP Texas’ outstanding derivative contracts for heating oil and gasoline as of September 30, 2017 and December 31, 2016 were 2 million gallons and 2 million gallons, respectively.

Cash Flow Hedging Strategies

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

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

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. For the September 30, 2017 and December 31, 2016 balance sheets, AEP Texas netted $80 thousand and $185 thousand, respectively, of cash collateral received from third parties against short-term and long-term risk management assets.

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

Fair Value of Derivative Instruments
September 30, 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)
Current Risk Management Assets	$	0.2	$	(0.1	)	$	0.1
Long-term Risk Management Assets	—		—			—
Total Assets	0.2		(0.1		)	0.1
Current Risk Management Liabilities	—		—			—
Long-term Risk Management Liabilities	—		—			—
Total Liabilities	—		—			—
Total MTM Derivative Contract Net Assets (Liabilities)	$	0.2	$	(0.1	)	$	0.1

Fair Value of Derivative Instruments
December 31, 2016
	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)
Current Risk Management Assets	$	0.4	$	(0.2	)	$	0.2
Long-term Risk Management Assets	—		—			—
Total Assets	0.4		(0.2		)	0.2
Current Risk Management Liabilities	—		—			—
Long-term Risk Management Liabilities	—		—			—
Total Liabilities	—		—			—
Total MTM Derivative Contract Net Assets (Liabilities)	$	0.4	$	(0.2	)	$	0.2

(a) 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.”

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

(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.

F-82

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

Amount of Gain (Loss) Recognized on

Risk Management Contracts

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Location of Gain (Loss)	2017		2016			2017			2016
	(in millions)
Other Operation	$	0.1	$	(0.1	)	$	0.1		$	(0.3	)
Maintenance	0.1		(0.2		)	0.1			(0.3		)
Regulatory Assets (a)	0.1		0.1			—			0.7
Regulatory Liabilities (a)	0.1		—			(0.2		)	—
Total Gain (Loss) on Risk Management Contracts	$	0.4	$	(0.2	)	$	—		$	0.1

(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

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 AEP Texas’ statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on AEP Texas’ 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 effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on its balance sheets until the period the hedged item affects Net Income. AEP Texas would record hedge ineffectiveness as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable.

AEP Texas reclassifies gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on its balance sheets into Interest Expense on its statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2017 and 2016, AEP Texas did not apply cash flow hedging to outstanding interest rate derivatives.

During the three and nine months ended September 30, 2017 and 2016, hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies discussed above.

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on AEP Texas’ balance sheets and the reasons for changes in cash flow hedges, see Note 3.

F-83

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on AEP Texas’ balance sheets were:

	Interest Rate
	September 30,			December 31,
	2017			2016
	(in millions)
AOCI Loss Net of Tax	$	(4.7	)	$	(5.4	)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	(0.9		)	(0.9		)

The actual amounts that AEP Texas reclassifies from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. As of September 30, 2017, AEP Texas is not hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) its exposure to variability in future cash flows related to forecasted transactions.

F-84

9. FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

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

For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded 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.

For Restricted Cash for Securitized Transition Funding, items classified as Level 1 are investments in money market funds. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.

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 AEP Texas’ Long-term Debt are summarized in the following table:

	September 30, 2017				December 31, 2016
	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
Long-term Debt	$	3,722.5	$	4,022.0	$	3,217.7	$	3,463.2

F-85

Fair Value Measurements of Financial Assets and Liabilities

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2017
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Restricted Cash for Securitized Transition Funding	$	123.0	$	—	$	—	$	—		$	123.0
Risk Management Assets
Risk Management Commodity Contracts (a)	—		0.2		—		(0.1		)	0.1
Total Assets	$	123.0	$	0.2	$	—	$	(0.1	)	$	123.1

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2016
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Restricted Cash for Securitized Transition Funding	$	146.3	$	—	$	—	$	—		$	146.3
Risk Management Assets
Risk Management Commodity Contracts (a)	—		0.4		—		(0.2		)	0.2
Total Assets	$	146.3	$	0.4	$	—	$	(0.2	)	$	146.5

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

As of September 30, 2017 and December 31, 2016, AEP Texas had no liabilities measured at fair value on a recurring basis.

There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2017 and 2016.

F-86

10. INCOME TAXES

Effective Tax Rates (ETR)

The interim ETR for AEP Texas reflects the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis.

The ETR for AEP Texas are included in the following table. Significant variances in the ETR are described below.

Three Months Ended September 30,				Nine Months Ended September 30,
2017		2016		2017		2016
32.2	%	29.7	%	33.6	%	29.7	%

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

The increase in the ETR is primarily due to the recording of favorable state income tax adjustments in 2016 and an increase in pretax book income.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016

The increase in the ETR is primarily due to the recording of favorable state income tax adjustments in 2016.

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, 2012 and 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. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, AEP Texas accrues interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.

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 or local income tax examinations by tax authorities for years before 2009.

F-87

11. FINANCING ACTIVITIES

Long-term Debt

Long-term debt issued, retired and principal payments made during the first nine months of 2017 are shown in the tables below:

	Principal		Interest	Due
Type of Debt	Amount (a)		Rate	Date
Issuances:	(in millions)		(%)
Senior Unsecured Notes	$	400.0	2.40	2022
Pollution Control Bonds	60.0		1.75	2020
Senior Unsecured Notes	300.0		3.80	2047

	Principal		Interest	Due
Type of Debt	Amount Paid		Rate	Date
Retirements and Principal Payments:	(in millions)		(%)
Securitization Bonds	$	27.2	0.88	2017
Securitization Bonds	161.2		5.17	2018
Pollution Control Bonds	60.0		5.20	2030

In October 2017, AEP Texas retired $41 million of 5.625% Pollution Control Bonds due in 2017.

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.

Federal Power Act

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.

Leverage Restrictions

AEP Texas has credit agreements that contain a covenant that limit its debt to capitalization ratio to 67.5%. As of September 30, 2017, AEP Texas did not exceed its debt to capitalization limit. The payment of cash dividends indirectly results in an increase in the percentage of AEP Texas’ debt to total capitalization. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements.

As of September 30, 2017, the Federal Power Act restriction does not limit the ability of AEP Texas to pay dividends out of retained earnings.

F-88

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, and a Nonutility Money Pool, which funds a majority of AEP’s nonutility 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 September 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates on AEP Texas’ balance sheets. AEP Texas’ Utility Money Pool activity and corresponding authorized borrowing limit for the nine months ended September 30, 2017 are described in the following table:

Maximum		Maximum		Average		Average		Loans to		Authorized
Borrowings		Loans		Borrowings		Loans		the Utility		Short-Term
from the Utility		to the Utility		from the Utility		to the Utility		Money Pool as of		Borrowing
Money Pool		Money Pool		Money Pool		Money Pool		September 30, 2017		Limit
(in millions)
$	296.0	$	451.7	$	194.8	$	430.0	$	437.3	$	400.0

The activity in the above table does not include short-term lending activity of AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company LLC (TNGC), which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates on AEP Texas’ balance sheets. For the nine months ended September 30, 2017, TNGC had the following activity in the Nonutility Money Pool:

Maximum		Maximum		Average		Average		Loans
Borrowings		Loans		Borrowings		Loans		to the Nonutility
from the Nonutility		to the Nonutility		from the Nonutility		to the Nonutility		Money Pool as of
Money Pool		Money Pool		Money Pool		Money Pool		September 30, 2017
(in millions)
$	—	$	8.6	$	—	$	8.3	$	8.3

In January 2017, management removed AEP Texas from the direct financing relationship with AEP to better reflect current business operations. The amounts of outstanding loans to AEP as of December 31, 2016 are included in Advances to Affiliates on AEP Texas’ balance sheets.

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		Average
	Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate
	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds
Nine Months	Borrowed		Borrowed		Loaned		Loaned		Borrowed		Loaned
Ended	from the Utility		from the Utility		to the Utility		to the Utility		from the Utility		to the Utility
September 30,	Money Pool		Money Pool		Money Pool		Money Pool		Money Pool		Money Pool
2017	1.49	%	0.92	%	1.43	%	1.12	%	1.29	%	1.35	%
2016	0.91	%	0.75	%	0.83	%	0.69	%	0.84	%	0.72	%

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

	Maximum		Minimum		Maximum		Minimum		Average		Average
	Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate
	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds
Nine Months	Borrowed from		Borrowed from		Loaned to		Loaned to		Borrowed from		Loaned to
Ended	the Nonutility		the Nonutility		the Nonutility		the Nonutility		the Nonutility		the Nonutility
September 30,	Money Pool		Money Pool		Money Pool		Money Pool		Money Pool		Money Pool
2017	—	%	—	%	1.49	%	—	%	—	%	1.27	%
2016	1.11	%	0.97	%	0.91	%	0.75	%	1.00	%	0.82	%

F-89

Maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:

	Maximum		Minimum		Maximum		Minimum		Average		Average
	Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate
Nine Months	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds
Ended	Borrowed from		Borrowed from		Loaned to		Loaned to		Borrowed from		Loaned to
September 30,	AEP		AEP		AEP		AEP		AEP		AEP
2017	—	%	—	%	—	%	—	%	—	%	—	%
2016	0.91	%	0.69	%	—	%	—	%	0.80	%	—	%

F-90

12. BUSINESS SEGMENTS

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

F-91

AEP Texas Inc.

Offers to Exchange

$400,000,000 aggregate principal amount of its 2.40% Senior Notes, Series C due 2022 and

$300,000,000 aggregate principal amount of its 3.80% Senior Notes, Series D due 2047,

each of which have been registered under the Securities Act of 1933, as amended,

for any and all of its outstanding

2.40% Senior Notes, Series A due 2022 and

3.80% Senior Notes, Series B due 2047, respectively

_______________________________

PROSPECTUS

________________________

, 2017

II-1

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20.Indemnification of Directors and Officers.

The Certificate of Incorporation of the Company provides that the Company shall indemnify and hold harmless, to the full extent permitted by law, each person whowas or is made a party or is threatened to be made a party to or is involved (including, without limitation, as a witness) in any threatened, pending or completed action, suit, arbitration, alternative dispute resolution mechanism, investigation, administrative hearing or any other proceeding by reason of the fact that such person is or was a director or officer of the Company or is or was serving at the request of the Company as a director or officer of another corporation or any other person or entity against all expense, liability, losses and claims.

The Bylaws of the Company provide that the Company shall indemnify each person who is, was or has agreed to become a director or officer of the Company, or who has agreed to serve as a director, officer, employee or agent of the Company (or any other person or entity) at the request of the Board of Directors against all loss, liability and expenses to the fullest extent permitted by the General Corporation Law of Delaware.  Notwithstanding the foregoing, no person shall be indemnified for amounts paid in settlement unless the terms and conditions of such settlement have been consented to by the Company, and no indemnification for employees or agents shall be made without the express authorization of the Board of Directors.

Section 145 of the Delaware General Corporation Law provides that a Delaware corporation may indemnify any persons, including officers and directors, who are, or are threatened to be made, parties to any threatened, pending or completed legal action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of such corporation), by reason of the fact that such person is or was an officer, director, employee or agent of such corporation, or is or was serving at the request of such corporation as a director, officer, employee or agent of another corporation.  The indemnity may include expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with such action, suit or proceeding, provided such person acted in good faith and in a manner he reasonably believed to be in or not opposed to the corporation’s best interests and, for criminal actions or proceedings, had no reasonable cause to believe that his conduct was unlawful.  A Delaware corporation may indemnify officers and directors in an action by or in the right of the corporation under the same conditions, except that no indemnification is permitted without judicial approval if the officer or director is adjudged to be liable to the corporation.  Where an officer or director is successful on the merits or otherwise in the defense of any action referred to above, the corporation must indemnify him against the expenses (including attorneys’ fees) which such officer or director actually and reasonably incurred.

The above is a general summary of certain provisions of the Company’s Certificate of Incorporation and Bylaws and the Delaware General Corporation Law and is subject in all respects to the specific and detailed provisions of the Company’s Certificate of Incorporation and Bylaws and the Delaware General Corporation Law.

Insurance

The Company maintains insurance policies insuring its directors and officers against certain obligations that may be incurred by them.

II-2

Item 21. Exhibits and Financial Statement Schedules.

The following Exhibits indicated by an asterisk preceding the Exhibit number have heretofore been filed with the Commission and pursuant to Rule 12(b)-32 are incorporated herein by reference. The balance of the Exhibits are filed herewith. Exhibits indicated by a [ ] are management contracts or compensatory arrangements that are filed or listed pursuant to Item 601(b)(10)(iii) of Regulation S-K.

3(a)	Composite of the Restated Certificate of Incorporation, as amended.
3(b)	Bylaws.
4(a)-1	Indenture, dated as of September 1, 2017, between AEP Texas Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee.
4(a)-2	First Supplemental Indenture dated as of September 22, 2017, to said Indenture, establishing the terms of the 2.40% Senior Notes, Series A, due 2022 and the 3.80% Senior Notes, Series B, due 2047.
4(a)-3	Form of Company Order and Officers’ Certificate for the Exchange Notes.
4(a)-4	Form of 2022 Exchange Note.
4(a)-5	Form of 2047 Exchange Note.
4(b)	Registration Rights Agreement, dated September 22, 2017, between AEP Texas Inc. and the Initial Purchasers.
5	Opinion of Thomas G. Berkemeyer.
*[10(f)]	AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2008, incorporated by reference to Ex 10(1)(1)(A) to the 2008 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on February 27, 2009.
*[10(f)(1)]	Guaranty by AEP of AEPSC Excess Benefits Plan, incorporated by reference to Ex 10(h)(1)(B) of the 1990 Annual Report on Form 10-K of American Electric Power Company, Inc.
*[10(g)]	AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2011 (Non-Qualified), incorporated by reference to Ex 10(1)(2) of the 2010 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on February 25, 2011.
*[10(g)(1)]	Amendment to AEP System Supplemental Retirement Savings Plan, as Amended and Restated as of January 1, 2011 (Non-Qualified), incorporated by reference to Ex 10(1)(1)(A) of the 2014 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on February 20, 2015.
*[10(h)]	AEPSC Umbrella Trust for Executives, incorporated by reference to Ex 10(g)(3) of the 1993 Annual Report on Form 10-K of American Electric Power Company, Inc.
*[10(h)(1)]	First Amendment to AEPSC Umbrella Trust for Executives, incorporated by reference to Ex 10(h)(3) of the 2008 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on February 27, 2009.
*[10(i)]	Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers, incorporated by reference to Ex 10(m)(4) of the 2002 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on March 20, 2003.

II-3

*[10(i)(1)]	Amendment to Employment Agreement dated December 9, 2008 between AEPSC and Robert P. Powers, incorporated by reference to Ex 10(m)(4)(A) to the 2008 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on February 27, 2009.
*[10(i)(2)]	Separation and Release Agreement for Robert P. Powers, incorporated by reference to Ex 10(c) to the Quarterly Report on Form 10-Q of American Electric Power Company, Inc. for the quarterly period ended March 31, 2017 filed on April 28, 2017.
*[10(j)]	AEP System Senior Officer Annual Incentive Compensation Plan amended and restated as of February 28, 2012, incorporated by reference to Ex 10 to the Quarterly Report on Form 10-Q of American Electric Power Company, Inc. for the quarterly period ended June 30, 2012, filed on July 27, 2012.
*[10(k)]	AEP System Survivor Benefit Plan, effective January 27, 1998, incorporated by reference to Ex 10 to the Quarterly Report on Form 10-Q of American Electric Power Company, Inc. for the quarterly period ended September 30, 1998 filed on November 16, 1998.
*[10(l)(1)]	First Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 31, 2000, incorporated by reference to Ex 10(o)(2) to the 2002 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on March 20, 2003.
*[10(l)(2)]	Second Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 1, 2008, incorporated by reference to Ex 10(o)(1)(B) to the 2008 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on February 27, 2009.
*[10(m)]	AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008, incorporated by reference to Ex 10(p) to the 2008 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on February 27, 2009.
*[10(m)(1)]	First Amendment to AEP System Incentive Compensation Deferral Plan as Amended and Restated as of January 1, 2008, incorporated by reference to Ex 10(p)(1)(A) to the 2011 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on February 28, 2012.
*[10(m)(2)]	Second Amendment to AEP System Incentive Compensation Deferral Plan as Amended and Restated as of January 1, 2008, incorporated by reference to Ex 10(q)(2)(A) to the 2014 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on February 20, 2015.
*[10(n)]	AEP Change In Control Agreement, as Revised Effective January 1, 2017, incorporated by reference to Ex 10(c) to the Quarterly Report on Form 10-Q of American Electric Power Company, Inc. for the quarterly period ended September 30, 2016, filed on November 2, 2016.
*[10(o)]	Amended and Restated AEP System Long-Term Incentive Plan as of September 21, 2016, incorporated by reference to Ex 10(a) to the Quarterly Report on Form 10-Q of American Electric Power Company, Inc. for the quarterly period ended September 30, 2016, filed on November 2, 2016.
*[10(o)(1)]	Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended, incorporated by reference to Ex 10(t)(1)(A) to the 2011 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on February 28, 2012.

II-4

*[10(o)(2)]	Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan Amended and Restated effective January 1, 2013, incorporated by reference to Ex 10(t)(2)(A) to the 2012 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on February 26, 2013.
*[10(p)]	AEP System Stock Ownership Requirement Plan Amended and Restated effective January 1, 2014, incorporated by reference to Ex 10 to the Quarterly Report on Form 10-Q of American Electric Power Company, Inc. for the quarterly period ended June 30, 2014, filed on July 25, 2014.
*[10(p)(1)]	First Amendment to AEP System Stock Ownership Requirement Plan as Amended and Restated effective January 1, 2014, incorporated by reference to Ex 10(t)(1)(A) to the 2014 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on February 20, 2015.
*[10(q)]	Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2009, incorporated by reference to Ex 10(v) to the 2008 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on February 27, 2009.
*[10(r)]	AEP Executive Severance Plan Amended and Restated effective October 24, 2016, incorporated by reference to Ex 10(d) to the Quarterly Report on Form 10-Q of American Electric Power Company, Inc. for the quarterly period ended September 30, 2016, filed on November 2, 2016.
*[10(s)]	Letter Agreement dated November 20, 2012 between AEPSC and Lana Hillebrand, incorporated by reference to Ex 10(x) to the 2013 Annual Report on Form 10-K of American Electric Power Company, Inc. filed on February 25, 2014.
12	AEP Texas Inc. Computation of Ratio of Earnings to Fixed Charges.
*16	American Electric Power Company, Inc. Current Report on Form 8-K, filed July 29, 2016 (the “Current Report”), including the letter from Deloitte & Touche LLP regarding change in certifying accountant.
16(a)	Letter from Deloitte & Touche LLP regarding change in certifying accountant.
21	Schedule of Subsidiaries of AEP Texas Inc.
23(a)	Consent of Deloitte & Touche LLP.
23(b)	Consent of Thomas G. Berkemeyer, Esq. (included in Exhibit 5).
24	Power of Attorney.
25	Statement of Eligibility of Trustee on Form T-I with respect to the indenture dated as of September 1, 2017 between AEP Texas Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee.
99(a)	Form of Letter of Transmittal.
99(b)	Form of Letter to Brokers, Dealers, Commercial Banks, Trust Companies and Other Nominees.
99(c)	Form of Letter to Clients.
99(d)	Form of Notice of Guaranteed Delivery.

II-5

Item 22. Undertakings

(a) The undersigned registrant hereby undertakes:

(1) to file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

i. to include any prospectus required by Section 10(a)(3) of the Securities Act;

ii. to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the SEC pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

iii. to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

(2) that, for the purpose of determining any liability under the Securities Act, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof;

(3) to remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering;

(4) that, for the purpose of determining liability under the Securities Act to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness; provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use; and

(5) that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

i. any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

ii. any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

II-6

iii. the portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

iv. any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

(b) Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of any registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of any registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

(c) The undersigned registrant hereby undertakes to respond to requests for information that is incorporated by reference into the prospectus pursuant to Item 4, 10(b), 11 or 13 of this form, within one business day of receipt of such request, and to send the incorporated documents by first-class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

(d) The undersigned registrant hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

II-7

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, AEP Texas Inc. has duly caused this Registration Statement on Form S-4 to be signed on its behalf by the undersigned, hereunto duly authorized, in the City of Columbus and State of Ohio, on the 17th day of November, 2017.

AEP TEXAS INC.

Nicholas K. Akins *

Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities and on the dates indicated.

SignatureTitleDate

(i)    Principal Executive

Officer                Chairman of the Board and             November 17, 2017

Nicholas K. Akins*        Chief Executive Officer    

(ii)    Principal Financial

Officer:

/s/ Brian X. Tierney        Vice President and                 November 17, 2017

Brian X. Tierney            Chief Financial Officer     

(iii)    Principal Accounting

Officer:

/s/ Joseph M. Buonaiuto        Controller and Chief                 November 17, 2017

Joseph M. Buonaiuto        Accounting Officer

(iv)    A Majority of the

Directors:

Nicholas K. Akins*            Lana L. Hillebrand*        

Lisa M. Barton*                Mark C. McCullough*

Paul Chodak, III*                Charles R. Patton*                

David M. Feinberg*            Brian X. Tierney*

*By /s/ Brian X. Tierney                                      November 17, 2017

(Brian X. Tierney, Attorney-in-Fact)

_____________________________

II-8