Document


PROSPECTUS
AEP Transmission Company, LLC
Offers to Exchange
$300,000,000 aggregate principal amount of its 3.10% Senior Notes, Series F due 2026 and
$400,000,000 aggregate principal amount of its 4.00% Senior Notes, Series G due 2046,
each of which have been registered under the Securities Act of 1933, as amended,
for any and all of its outstanding

3.10% Senior Notes, Series D due 2026 and
4.00% Senior Notes, Series E due 2046, 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We will exchange all Outstanding Notes that are validly tendered and not validly withdrawn for an equal principal amount of Exchange Notes that are registered under the Securities Act.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 May 17, 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 11 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 April 17, 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 and Incorporation by Reference.” 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 May 17, 2017, the present expiration date of the exchange offers.
References to “AEPTCo,” “Company,” “we,” “us” and “our” in this prospectus are references to AEP Transmission Company, LLC specifically or, if the context requires, to AEP Transmission Company, LLC and its subsidiaries, collectively.





TABLE OF CONTENTS
 
 
 
 
 
Summary
 
1
Risk Factors
 
Forward-Looking Statements
 
17
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
 
35
Quantitative and Qualitative Disclosures about Market Risk
 
36
Business
 
37
Management
 
47
Compensation Discussion and Analysis
 
49
Transactions with Related Persons
 
83
The Exchange Offers
 
84
Description of the Exchange Notes
 
96
Material United States Federal Income Tax Consequences Of The Exchange Offers
 
104
Plan of Distribution
 
104
Legal Matters
 
104
Experts
 
105
Available Information
 
105
Index to 2016 Annual Report
 
106





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 Transmission Company, LLC
Overview
AEP Transmission Company, LLC (“AEPTCo” or the “Company”), a Delaware limited liability company organized in 2006, is the holding company of seven regulated transmission-only electric utilities. AEPTCo is an indirect wholly-owned subsidiary of American Electric Power Company, Inc. (“AEP”).
Our business consists of developing and building new transmission facilities at the request of the regional transmission organizations in which we operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. Our principal executive offices are located at 1 Riverside Plaza, Columbus, Ohio 43215 (Telephone number (614) 716-1000).

Organizational Structure

http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=11531278&doc=6


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State Transcos

AEPTCo’s seven wholly-owned public utility companies are (collectively referred to herein as the “State Transcos”):
AEP Appalachian Transmission Company, Inc. (“APTCo”),
AEP Indiana Michigan Transmission Company, Inc. (“IMTCo”),
AEP Kentucky Transmission Company, Inc. (“KTCo”),
AEP Ohio Transmission Company, Inc. (“OHTCo”),
AEP West Virginia Transmission Company, Inc. (“WVTCo”),
AEP Oklahoma Transmission Company, Inc. (“OKTCo”) and
AEP Southwestern Transmission Company, Inc. (“SWTCo”).
The State Transcos are independent of but overlay AEP’s existing electric utility operating companies: Appalachian Power Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport Power Company, Ohio Power Company, Public Service Company of Oklahoma, Southwestern Electric Power Company and Wheeling Power Company (collectively, the “AEP Operating Companies”). The State Transcos develop, own, operate, and maintain their respective transmission assets. Assets of the State Transcos interconnect to transmission facilities owned by the AEP Operating Companies and unaffiliated transmission owners within the footprints of PJM and SPP. PJM and SPP are regional transmission organizations (“RTOs”) mandated by the Federal Energy Regulatory Commission (“FERC”) to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale prices of electricity.  PJM is a regional transmission organization serving approximately 61 million people throughout 13 states and the District of Columbia. APTCo, IMTCo, KTCo, OHTCo and WVTCo are located within PJM. SPP is a regional transmission organization serving over 18 million people in fourteen states.  OKTCo and SWTCo are located within SPP.

IMTCo, KTCo, OHTCo, OKTCo and WVTCo have received all necessary approvals for formation and currently own and operate transmission assets in their respective jurisdictions.  In December 2016, the Virginia State Corporation Commission and West Virginia Public Service Commission granted consent for Appalachian Power Company and APTCo to enter into a joint license agreement that will support APTCo investment in the state of Tennessee. An application for regulatory approval for SWTCo is under consideration in Louisiana.

Regulation
The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. The State Transcos establish transmission rates each year through formula rate filings with FERC. The rate filings calculate the revenue requirement needed to cover the costs of operation and debt service and to earn an allowed return on equity. These rates are then included in the Open Access Transmission Tariffs (“OATT”) for SPP and PJM. SPP and PJM collect the revenue requirement from transmission customers under their respective OATTs. The transmission customers under the OATTs include the AEP Operating Companies, other investor-owned utilities, electric cooperatives, municipal entities and power marketers.

The public service commissions in the states where our State Transcos’ assets are located do not have jurisdiction over the State Transcos’ rates or terms and conditions of service. However, certain transmission facilities are subject to certification and/or siting and financing requirements specific to each state. While these proceedings require a statement and justification of need, they also determine line routes and substation locations with the least impact to the environment and general public. The state public service commission or a designated entity will review the State Transco’s application to certify the project.


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Operations
As transmission-only companies, our State Transcos function as conduits, allowing for power from generators to be transmitted to local distribution systems. The transmission of electricity by our State Transcos is a central function to the provision of electricity to residential, commercial and industrial end-use consumers. American Electric Power Service Corporation (“AEPSC”) has executed a services agreement pursuant to which AEPSC has agreed to provide services to each of the State Transcos. AEPSC is an AEP service subsidiary that provides management and professional services to AEP and its subsidiaries. AEPSC provides four categories of service to the State Transcos: project evaluation and permitting services, project development services, operation and management services and business services, including billing, insurance, human resources and IT services. All of these services are provided at cost. Additionally, each State Transco has executed a services agreement with the respective incumbent AEP Operating Company in its state or footprint.

Existing and Forecasted Projects
The State Transcos are geographically diverse and have assets in service or under construction across two RTOs and in six states, with additional states planned or pending approval. As of December 31, 2016, the State Transcos had $4.1 billion of transmission assets in-service with plans to construct approximately $4.4 billion of additional transmission assets through 2019. We anticipate the need for extensive additional investment in transmission infrastructure within PJM and SPP to maintain the required level of grid reliability, resiliency, security and efficiency and to address an aging transmission infrastructure. We also foresee the need to construct additional transmission facilities based on changes in generating resources, such as wind or solar projects, generation additions or retirements, and additional new customer interconnections. We will continue our investment to enhance physical and cyber security of our assets, and are also investing in improving the telecommunication network that supports the operation and control of the grid. Finally, our fundamental obligation to meet state, federal, regulatory and industry standards will continue to drive investment in this category of projects.

A key part of our business is replacing and upgrading transmission facilities, assets and components of the existing AEP System as needed to maintain reliability. Roughly 7,000 miles of AEP's transmission lines were built more than seventy years ago and have surpassed their useful life expectancy. Significant quantities of major transmission equipment, such as transformers and circuit breakers, on AEP’s grid have also surpassed their life expectancy. The State Transcos provide the capability to upgrade existing facilities due to their condition as a result of their age.
Business Strategy
AEPTCo’s business strategy is to own, operate, maintain and invest in transmission infrastructure in order to maintain and enhance system integrity and grid reliability, grid security, safety, reduce transmission constraints and facilitate interconnections of new generating resources and new wholesale customers, as well as enhance competitive wholesale electricity markets. We intend to implement this strategy through the following types of projects:
Regional Projects: Projects assigned to the AEP System as a result of the regional planning initiatives conducted by PJM or SPP. The RTOs identify the need for transmission in support of regional reliability, transmission service, congestion mitigation, public policy, to support the integration of new generation resources and to support the retirement of generation resources. Regional Projects must be awarded by PJM or SPP in a process approved by FERC under Order 1000, and generally contemplates more than one bidder for any particular Regional Project.

Local Projects: Improvements to local area reliability by upgrading, rebuilding or replacing existing, aging infrastructure at the AEP Operating Companies. AEP evaluates several criteria to determine the need for Local Projects. These criteria include age, recorded performance issues, condition assessment, anticipated maintenance requirements and criticality to the grid. Projects are assigned to the State Transcos based upon a defined set of criteria. Local projects also include new interconnections discussed below.


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New Interconnections: Construction of new facilities to support customer points of delivery.    

Transmission investment across AEP is primarily driven by the need to revitalize aging infrastructure, our desire to enhance reliability at a local level to improve the customer experience, compliance with regulatory, industry, and governmental standards, requirements to improve telecommunication capability to keep up with changing technologies, and the obligation to address grid limitations identified by the RTOs. The State Transcos are not limited to investing in projects addressing particular transmission drivers. AEP has developed project selection guidelines that help determine which transmission assets can be built, owned and operated by the State Transcos. In essence, the need on the transmission grid determines the transmission project, and the project selection guidelines help determine which components of the transmission project will be placed in the State Transcos.

Generally, greenfield transmission, partial or complete refurbishment of extra high voltage transmission, and complete refurbishment of lower voltage transmission assets qualify for transmission investment in the State Transcos. AEPTCo expects the majority of its transmission investment to go towards improving aging infrastructure, local reliability and upgrades to telecommunication and operational stacks.


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The Exchange Offers
In November 2016, 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 “2026 Exchange Notes” refers to the 3.10% Senior Notes, Series F due 2026 and the term “2046 Exchange Notes” refers to the 4.00% Senior Notes, Series G due 2046, 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
$300,000,000 aggregate principal amount of 3.10% Senior Notes, Series F due 2026 that have been registered under the Securities Act for any and all of our existing 3.10% Senior Notes, Series D due 2026 and

 
Ÿ
$400,000,000 aggregate principal amount of 4.00% Senior Notes, Series G due 2046 that have been registered under the Securities Act for any and all of our existing 4.00% Senior Notes, Series E due 2046.

 
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


5



 
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

 
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 May 17, 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
If you wish to participate in any of the Exchange Offers, you must either:

6



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

 
Ÿ
you are not an “affiliate,” as defined in Rule 405 of the Securities Act, of the Company or, if you are an affiliate, you will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable; and

 
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.

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.”

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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.”


8



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 Transmission Company, LLC.

The Exchange Notes
 
$300,000,000 principal amount of 3.10% Senior Notes, Series F due 2026 and $400,000,000 principal amount of 4.00% Senior Notes, Series G due 2046.
Maturity
 
December 1, 2026 for 2026 Exchange Notes and December 1, 2046 for 2046 Exchange Notes.
Interest Rate
 
3.10% per annum for 2026 Exchange Notes and 4.00% per annum for 2046 Exchange Notes.
Interest Payment Dates
 
June 1 and December 1 of each year, beginning on December 1, 2017.
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 April 4, 2017.
Optional Redemption
 
At any time prior to September 1, 2026, we may redeem the 2026 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 2026 Exchange Notes being redeemed that would be due if such 2026 Exchange Notes matured on September 1, 2026, 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 15 basis points, plus in each case accrued and unpaid interest to the redemption date.
At any time prior to June 1, 2046, we may redeem the 2046 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 2046 Exchange Notes being redeemed that would be due if such 2046 Exchange Notes matured on June 1, 2046, 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, 2026, we may redeem the 2026 Exchange Notes in whole or in part at 100% of the principal amount of the 2026 Exchange Notes being redeemed, plus accrued and unpaid interest thereon to but excluding the date of redemption. At any time on or after June 1, 2046, we may redeem the 2046 Exchange Notes in whole or in part at 100% of the principal amount of the 2046 Exchange Notes being redeemed, plus accrued and unpaid interest thereon to but excluding the date of redemption.

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Certain Covenants
 
The Indenture (as defined herein) limits our ability to incur Liens (as defined herein), does not permit Consolidated Priority Debt (as defined herein) to exceed 10% of Consolidated Tangible Net Assets (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-Certain Covenants.”
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.


10



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

Certain elements of our State Transcos’ formula rates can be and have been challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on our business, financial condition, results of operations and cash flows.

Our State Transcos provide transmission service under rates regulated by the FERC. The FERC has approved the cost-based formula rate templates used by our State Transcos to calculate their respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the formula rates. All aspects of our State Transcos’ rates accepted or approved by the FERC, including the formula rate templates, the rates of return on the actual equity portion of their respective capital structures and the approved targeted capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative. In addition, interested parties may challenge the annual implementation and calculation by our State Transcos of their projected rates and formula rate true up pursuant to their approved formula rate templates under the State Transcos’ formula rate implementation protocols. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC will make appropriate prospective adjustments to them and/or disallow any of our State Transcos’ inclusion of those aspects in the rate setting formula.

In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates, including the State Transcos that operate in PJM, in calculating formula transmission rates under the PJM Open Access Transmission Tariff (OATT) is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to our State Transcos, particularly if rates for delivered electricity increase substantially.

Our actual capital investment may be lower than planned, which would cause a lower than anticipated rate base and would therefore result in lower revenues and earnings compared to our current expectations.

Each of our State Transcos’ rate base, revenues and earnings are determined in part by additions to property, plant and equipment and when those additions are placed in service. We anticipate making significant capital investments over the next several years; however, the amounts could change significantly due to factors beyond our control. If our State Transcos’ capital investment and the resulting in-service property, plant and equipment are lower than anticipated for any reason, our State Transcos will have a lower than anticipated rate base, thus causing their revenue requirements and future earnings to be lower than anticipated.


11



Changes in energy laws, regulations or policies could impact our business, financial condition, results of operations and cash flows.

Each of our State Transcos is regulated by the FERC as a “public utility” under federal law and is a transmission owner in PJM or SPP. We cannot predict whether the approved rate methodologies for any of our State Transcos will be changed. In addition, the U.S. Congress periodically considers enacting energy legislation that could assign new responsibilities to the FERC, modify existing law or provide the FERC or another entity with increased authority to regulate transmission matters. We cannot predict whether, and to what extent, our State Transcos may be affected by any such changes in federal energy laws, regulations or policies in the future. While our State Transcos are subject to FERC’s exclusive jurisdiction for purposes of rate regulation, changes in state laws affecting other matters, such as transmission siting and construction, could limit investment opportunities available to us.

We depend on the AEP Operating Companies for a substantial portion of our revenues.

Our principal transmission service customers in PJM are AEP Operating Companies. In SPP, our principal transmission service customers are also affiliated AEP Operating Companies. We expect that AEP Operating Companies will continue to be our principal transmission service customers for the foreseeable future. For the year ended December 31, 2016, the AEP Operating Companies were responsible for approximately 77% of our consolidated transmission revenues.

Most of the real property rights on which our assets are situated result from affiliate license agreements and are dependent on the terms of the underlying easements and other rights of our affiliates.

We do not hold title to the majority of real property on which our electric transmission assets are located. Instead, under the provisions of certain affiliate contracts, we are permitted to occupy and maintain our facilities upon real property held by the respective AEP Operating Companies that overlay our operations. Our ability to continue to occupy such real property is dependent upon the terms of such affiliate contracts and upon the underlying real property rights of the AEP Operating Companies, which may be encumbered by easements, mineral rights and other similar encumbrances that may affect the use of such real property. We can give no assurance that (i) we will continue to be affiliates of the AEP Operating Companies, (ii) suitable replacement arrangements can be obtained in the event that the AEP Operating Companies are not our affiliates, and (iii) the underlying easements and other rights are sufficient to permit us to operate our assets in a manner free from interruption.

We contract with third parties and affiliates to provide services for certain aspects of our business. If any of these agreements are terminated, we may face a shortage of labor or replacement contractors to provide the services formerly provided by these third parties.

We enter into various agreements and arrangements with third parties and affiliates to provide services for construction, maintenance and operations of certain aspects of our business, which, if terminated, could result in a shortage of a readily available workforce to provide these services. If any of these agreements or arrangements is terminated for any reason, we may face difficulty finding a qualified replacement work force to provide such services, which could have an adverse effect on our ability to carry on our business and on our results of operations.

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. AEPTCo 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.

12



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, limitations on the discharge of pollutants into the environment, 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.

Our subsidiaries 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 foregoing 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.

Acts of war, terrorist attacks, cyberattacks, 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, cyberattacks, 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 and cyberattacks, as well as natural disasters, severe weather and other catastrophic events. In addition to any physical damage caused by such events, cyberattacks targeting our information systems could impair our records, networks, systems and programs, or transmit viruses to other systems. 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.


13



Risks Relating to Our Corporate and Financial Structure

We are a holding company with no operations, and unless we receive dividends or other payments from our subsidiaries, we may be unable to fulfill our other cash obligations.

As a holding company with no business operations, our material assets consist primarily of the stock interests in the State Transcos. Our only sources of cash to pay interest on our indebtedness are dividends and other payments received by us from time to time from the State Transcos, capital contributions from AEP, proceeds raised from the sale of our debt and borrowings. Each of the State Transcos, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us (apart from payment obligations in connection with loans that we have made to the State Transcos). The ability of each of our State Transcos to pay dividends and make other payments to us is subject to, among other things, the availability of funds, after taking into account capital expenditure requirements, the terms of its indebtedness, applicable state laws and regulations of the FERC.

AEPTCo is the sole obligor of the Exchange Notes and the State Transcos will not guarantee AEPTCo’s obligations under the Exchange Notes. Although certain debt covenants limit external debt at the subsidiary level, the Exchange Notes will be structurally subordinated to the debt and other liabilities of the State Transcos and the assets of the State Transcos may not be available to make payments on the Exchange Notes.

None of the State Transcos will guarantee AEPTCo’s obligations under the Exchange Notes. Although certain debt covenants limit external debt at the subsidiary level, the Exchange Notes are structurally subordinated to all of the debt and other liabilities of the State Transcos (other than debt owed to AEPTCo, “Parent Debt”). For a description of such covenants, see “Description of Exchange Notes-Certain Covenants” and Note 10, respectively, to our audited consolidated financial statements, included elsewhere in this prospectus. In the event that any of the State Transcos becomes insolvent, liquidates, reorganizes, dissolves or otherwise winds up, holders of that State Transco’s debt and its trade creditors generally will be entitled to payment on their claims from the assets of that State Transco before any of those assets are made available to AEPTCo. Consequently, the claims of holders of the Exchange Notes will be effectively subordinated to all of the debt and other liabilities of the State Transcos, including trade payables.

As of December 31, 2016, the State Transcos had an aggregate of $4 million in debt outstanding, other than Parent Debt.

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

The Exchange Notes will be general senior unsecured obligations and therefor will be effectively subordinated to AEPTCo’s future secured indebtedness. As of April 4, 2017, AEPTCo had no secured indebtedness outstanding. Although the Indenture will place some limitations on our ability to create liens securing indebtedness, there are significant exceptions to these limitations that would allow us to secure indebtedness without equally and ratably securing the Exchange Notes. If AEPTCo were to incur secured indebtedness and if AEPTCo defaulted on the Exchange 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 Exchange Notes, unless the Exchange Notes were similarly secured as described in “Description of Exchange Notes-Certain Covenants-Limitation on Liens” herein. If the value of such collateral is not sufficient to pay any secured indebtedness in full, AEPTCo’s secured creditors would share the value of AEPTCo’s other assets, if any, with you and the holders of other claims against AEPTCo which rank equally with the Exchange Notes.

AEPTCo 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 Exchange Notes.

The terms of the Exchange Notes will not prevent AEPTCo from entering into a variety of acquisition, refinancing, recapitalization or other highly-leveraged transactions. As a result, AEPTCo 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 Exchange Notes. As of December 31, 2016, AEPTCo had approximately $1.9 billion of indebtedness outstanding.


14



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:

incur Consolidated Priority Debt;
create liens;
dispose of certain assets;
enter into certain lines of business;
engage in transactions with affiliates;
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 and the acceleration of debt under other instruments evidencing indebtedness that may contain cross-acceleration provisions.

Certain covenants with respect to the Exchange Notes and our outstanding indebtedness are described under “Description of Exchange Notes-Certain Covenants” and in Note 10, respectively, to our audited consolidated financial statements, included elsewhere in this prospectus.

Adverse changes in our credit ratings may negatively affect us.

Our ability to access capital markets is important to our ability to operate our business. Increased scrutiny of the energy industry and the impact of regulation, as well as changes in our financial performance and unfavorable conditions in the capital markets could result in credit agencies reexamining our credit ratings. A downgrade in our credit ratings could restrict or discontinue our ability to access capital markets at attractive rates and increase our borrowing costs.

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.

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.

15




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.

Risks Related to the Exchange Notes

The following risks apply 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.


16



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 the Company’s service territory.
Inflationary or deflationary interest rate trends.
Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
The availability and cost of funds to finance working capital and capital needs.
Weather conditions, including storms and drought conditions.
The ability to build transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms.
New legislation, litigation and government regulation;
A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers;
Regulatory decisions, including rate or other recovery of new investments in transmission service.
The ability to constrain operation and maintenance costs.
Changes in utility regulation and the allocation of costs within regional transmission organizations, including Pennsylvania-New Jersey-Maryland regional transmission organization (“PJM”) and Southwest Power Pool regional transmission organization (“SPP”).
Actions of rating agencies, including changes in our ratings.
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.
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 capitalization as of December 31, 2016.

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 consolidated financial statements as of December 31, 2016 and 2015 and for the years ended December 31, 2016, 2015 and 2014, 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.
 
As of December 31, 2016
 
(in millions)
Long-Term Debt and Advances from Affiliates
 
 
Long-Term Debt
$
1,932
Advances from Affiliates (a)
 
4
Total Long-Term Debt and Advances from Affiliates
$
1,936
Total Equity
 
1,958
Total Capitalization
$
3,894

(a)Represents Advances from AEP’s Utility Money Pool.



18



SELECTED FINANCIAL DATA
The selected financial data presented below for the years ended December 31, 2013 and 2012 and as of December 31, 2014, 2013 and 2012 have been derived from AEPTCo’s audited consolidated financial statements and are not included elsewhere in this prospectus. 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 AEPTCo’s audited consolidated financial statements which are included elsewhere in this prospectus. Historical results are not necessarily indicative of future results.

You should read the data set forth below in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS” and AEPTCo’s audited consolidated financial statements and related notes included elsewhere in this prospectus.

 
 
Years Ended December 31,
 
 
2016
 
2015
 
2014
 
2013
 
2012
 
 
(in thousands)
STATEMENTS OF INCOME DATA
 
 
 
 
 
 
 
 
 
 
Total Revenues
 
$
478,043

 
$
310,175

 
$
182,249

 
$
77,666

 
$
24,112

 
 
 
 
 
 
 
 
 
 
 
Operating Income
 
$
280,166

 
$
174,349

 
$
113,770

 
$
41,141

 
$
10,036

 
 
 
 
 
 
 
 
 
 
 
Income Before Income Tax Expense
 
$
286,768

 
$
192,987

 
$
137,317

 
$
60,825

 
$
22,004

 
 
 
 
 
 
 
 
 
 
 
Net Income
 
$
192,689

 
$
132,944

 
$
101,225

 
$
48,735

 
$
18,807

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
As of December 31,
 
 
2016
 
2015
 
2014
 
2013
 
2012
 
 
(in thousands)
BALANCE SHEETS DATA
 
 
 
 
 
 
 
 
 
 
Total Transmission Property
 
$
5,054,185

 
$
3,749,790

 
$
2,620,442

 
$
1,636,081

 
$
748,172

Accumulated Depreciation and Amortization
 
99,566

 
51,677

 
24,500

 
9,551

 
2,676

Total Transmission Property – Net
 
$
4,954,619

 
$
3,698,113

 
$
2,595,942

 
$
1,626,530

 
$
745,496

 
 
 
 
 
 
 
 
 
 
 
Total Assets (a)
 
$
5,349,795

 
$
4,156,444

 
$
2,929,805

 
$
1,748,780

 
$
825,157

 
 
 
 
 
 
 
 
 
 
 
Total Member’s Equity
 
$
1,957,582

 
$
1,552,884

 
$
1,140,940

 
$
692,215

 
$
320,480

 
 
 
 
 
 
 
 
 
 
 
Long-term Debt (a)
 
$
1,931,984

 
$
1,544,401

 
$
1,094,907

 
$
616,914

 
$
323,289


(a) Amounts reflect the adoption of ASU 2015-3 “Simplifying the Presentation of Debt Issuance Costs.”


19



MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

The following discussion and analysis by management focuses on those factors that had a material effect on AEPTCo’s results of operations and financial condition during the periods presented and should be read in connection with AEPTCo’s audited consolidated 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 Transmission Company, LLC (“AEPTCo” or the “Company”) is a holding company for seven FERC regulated transmission-only electric utilities. AEPTCo is an indirect wholly-owned subsidiary of American Electric Power Company, Inc. (“AEP”).

AEPTCo’s seven wholly-owned public utility companies are (collectively referred to herein as the “State Transcos”):
AEP Appalachian Transmission Company, Inc. (“APTCo”)
AEP Indiana Michigan Transmission Company, Inc. (“IMTCo”)
AEP Kentucky Transmission Company, Inc. (“KTCo”)
AEP Ohio Transmission Company, Inc. (“OHTCo”)
AEP West Virginia Transmission Company, Inc. (“WVTCo”)
AEP Oklahoma Transmission Company, Inc. (“OKTCo”)
AEP Southwestern Transmission Company, Inc. (“SWTCo”)

AEPTCo’s business activities are the development, construction and operation of transmission facilities through investments in seven wholly-owned FERC-regulated transmission only electric subsidiaries.

FERC Transmission Complaint

In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates, including the State Transcos that operate in PJM, in calculating formula transmission rates under the PJM Open Access Transmission Tariff (OATT) is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.



20



RESULTS OF OPERATIONS

The table below summarizes the significant components of AEPTCo’s net income for the years ended December 31, 2016, 2015 and 2014.
 
 
Years Ended December 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands)
Transmission Revenues
 
$
478,043

 
$
310,175

 
$
182,249

Other Operation and Maintenance
 
43,656

 
27,474

 
12,971

Depreciation and Amortization
 
65,875

 
42,350

 
23,698

Taxes Other Than Income Taxes
 
88,346

 
66,002

 
31,810

Operating Income
 
280,166

 
174,349

 
113,770

Interest Income - Affiliated
 
375

 
154

 
59

Allowance for Equity Funds Used During Construction
 
52,261

 
53,080

 
44,873

Interest Expense
 
(46,034
)
 
(34,596
)
 
(21,385
)
Income Before Income Tax Expense
 
286,768

 
192,987

 
137,317

Income Tax Expense
 
94,079

 
60,043

 
36,092

Net Income
 
$
192,689

 
$
132,944

 
$
101,225




Summary of Net Plant In Service and CWIP for AEPTCo
 
 
December 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands)
Net Plant In Service
 
$
3,973,287

 
$
2,763,906

 
$
1,794,988

CWIP
 
981,332

 
934,207

 
800,954



21



2016 Compared to 2015

Reconciliation of Year Ended December 31, 2015 to Year Ended December 31, 2016
Net Income
(in thousands)
Year Ended December 31, 2015
 
$
132,944

 
 
 
Changes in Transmission Revenues:
 
 
Transmission Revenues
 
167,868

Total Change in Transmission Revenues
 
167,868

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(16,182
)
Depreciation and Amortization
 
(23,525
)
Taxes Other Than Income Taxes
 
(22,344
)
Interest Income - Affiliated
 
221

Allowance for Equity Funds Used During Construction
 
(819
)
Interest Expense
 
(11,438
)
Total Change in Expenses and Other
 
(74,087
)
 
 
 
Income Tax Expense
 
(34,036
)
 
 
 
Year Ended December 31, 2016
 
$
192,689


The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and non-affiliates were as follows:

Transmission Revenues increased $168 million primarily due to the following:
A $140 million increase due to formula rate increases driven by continued investment in transmission assets and the related increases in recoverable operating expenses.
A $28 million increase due to annual formula rate true-up adjustments.

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

Other Operation and Maintenance expenses increased $16 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $24 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $22 million primarily due to increased property taxes as a result of additional transmission investment.
Interest Expense increased $11 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $34 million primarily due to an increase in pretax book income.


22



2015 Compared to 2014
 
Reconciliation of Year Ended December 31, 2014 to Year Ended December 31, 2015
Net Income
(in thousands)
Year Ended December 31, 2014
 
$
101,225

 
 
 
Changes in Transmission Revenues:
 
 
Transmission Revenues
 
127,926

Total Change in Transmission Revenues
 
127,926

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(14,503
)
Depreciation and Amortization
 
(18,652
)
Taxes Other Than Income Taxes
 
(34,192
)
Interest Income - Affiliated
 
95

Allowance for Equity Funds Used During Construction
 
8,207

Interest Expense
 
(13,211
)
Total Change in Expenses and Other
 
(72,256
)
 
 
 
Income Tax Expense
 
(23,951
)
 
 
 
Year Ended December 31, 2015
 
$
132,944


The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and non-affiliates were as follows:

Transmission Revenues increased $128 million primarily due to the following:
A $116 million increase due to formula rate increases driven by continued investment in transmission assets and the related increases in recoverable operating expenses.
A $12 million increase due to annual formula rate true-up adjustments.

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

Other Operation and Maintenance expenses increased $15 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $19 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $34 million primarily due to increased property taxes as a result of additional transmission investment.
Allowance for Equity Funds Used During Construction increased $8 million primarily due to increased transmission investment.
Interest Expense increased $13 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $24 million primarily due to an increase in pretax book income.











23



FINANCIAL CONDITION

AEPTCo 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
 
 
December 31,
 
 
2016
 
2015
 
 
(dollars in thousands)
Long-term Debt
 
$
1,931,984

 
49.6
%
 
$
1,544,401

 
49.6
%
Advances from Affiliates
 
4,077

 
0.1
%
 
16,857

 
0.5
%
Total Debt
 
1,936,061

 
49.7
%
 
1,561,258

 
50.1
%
Member’s Equity
 
1,957,582

 
50.3
%
 
1,552,884

 
49.9
%
Total Debt and Equity Capitalization
 
$
3,893,643

 
100.0
%
 
$
3,114,142

 
100.0
%

AEPTCo’s ratio of debt-to-total capital changed primarily due to an increase in debt related to increased construction expenditures and an increase in member’s equity related to capital contributions from member.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEPTCo’s financial stability.  AEPTCo 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 AEPTCo Parent and the State Transcos. These short-term borrowings are generally used by AEPTCo to fund working capital needs, property acquisitions and construction until long-term funding is arranged. 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. APTCo, IMTCo, KTCo, OHTCo, OKTCo and WVTCo have been approved to participate in the Utility Money Pool. In addition, for AEP subsidiaries including AEPTCo Parent and SWTCo, that are not participants in either money pool due to regulatory or operational reasons, the corporate borrowing program funds the short-term debt requirements of those subsidiaries as direct borrowers. The corporate borrowing program is backed by AEP’s commercial paper program and corporate credit facilities. Management believes AEPTCo has adequate liquidity under the AEP’s corporate borrowing program.  


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Commercial Paper Credit Facilities

AEP manages liquidity by maintaining adequate external financing commitments. As of December 31, 2016, AEP had $3.5 billion in aggregate credit facility commitments to support its operations. AEP’s $3 billion credit facility allows management to issue letters of credit in an amount up to $1.2 billion in support of subsidiary needs, including AEPTCo.  AEPTCo does not maintain separate credit facilities. During 2016, the maximum amount of commercial paper AEP had outstanding was $1.5 billion.  The weighted-average interest rate for AEP’s commercial paper during 2016 was 0.80%. As of December 31, 2016, AEP’s available liquidity was approximately $2.7 billion as illustrated in the table below:
 
 
Amount
 
Maturity
 
 
(in millions)
 
 
Commercial Paper Backup:
 
 
 
 
Revolving Credit Facility
 
$
3,000.0

 
June 2021
Revolving Credit Facility
 
500.0

 
June 2018
Total
 
3,500.0

 
 
Cash and Cash Equivalents
 
210.5

 
 
Total Liquidity Sources
 
3,710.5

 
 
Less: AEP Commercial Paper Outstanding
 
1,040.0

 
 
 
 
 
 
 
Net Available Liquidity
 
$
2,670.5

 
 

Additional liquidity is available to AEPTCo from cash from operations, the issuance of long-term debt as well as equity contributions from AEP.  Management is committed to maintaining adequate liquidity.  

Other Credit Facilities

AEP has an uncommitted facility that gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit under four uncommitted facilities totaling $300 million.  As of December 31, 2016, the maximum future payments for letters of credit issued under the uncommitted facilities was $150 million with maturities ranging from January 2017 to February 2018. As of December 31, 2016 AEPTCo had no letters of credit outstanding under these facilities.

Financing Plan

AEPTCo plans to refinance long-term debt as it becomes due and issue incremental debt, as needed, to support future capital expenditure plans.

Debt Covenants and Borrowing Limitations

AEPTCo’s long-term debt agreements and AEP’s credit agreements contain certain covenants and require AEPTCo and AEP 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 AEPTCo’s long-term debt agreements and AEP’s credit agreements.  Debt as defined in AEP’s credit agreements excludes securitization bonds and debt of AEP Credit.  As of December 31, 2016, this contractually-defined percentage for AEP and AEPTCo was 53.6% and 49.8%, respectively.   AEPTCo also has a priority debt limitation on external debt under its long-term debt agreements that limits such debt incurred by AEPTCo’s State Transco subsidiaries to 10% of AEPTCo’s tangible net assets. The method for calculating the priority debt limitation is contractually defined in AEPTCo’s long-term debt obligations. Nonperformance under these covenants could result in an event of default under these credit agreements.  In addition, subject to certain exceptions, AEPTCo Parent has covenanted that it will not incur debt secured by a lien unless its other indebtedness is similarly secured. As of December 31, 2016, AEP and AEPTCo were in compliance with all of the covenants contained in their long-term debt and credit agreements.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, including AEPTCo, 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 credit agreements. 

25



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 may not exceed amounts authorized by regulatory orders and AEP manages its borrowings to stay within those authorized limits.

For a further discussion of AEPTCo’s debt covenants, see Note 10 to AEPTCo’s audited consolidated financial statements and related notes appearing elsewhere in this prospectus.

Credit Ratings

AEPTCo does not have any long-term debt or credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade. 

CASH FLOW

AEPTCo relies primarily on cash flows from operations and debt issuances to fund its liquidity and investing activities. AEPTCo’s investing and capital requirements are primarily capital expenditures and repaying advances received from affiliates.
 
 
Years Ended December 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands)
Cash and Cash Equivalents at Beginning of Period
 
$

 
$

 
$

Net Cash Flows from Operating Activities
 
548,884

 
199,366

 
263,857

Net Cash Flows Used for Investing Activities
 
(1,135,017
)
 
(940,064
)
 
(1,007,462
)
Net Cash Flows from Financing Activities
 
586,133

 
740,698

 
743,605

Net Change in Cash and Cash Equivalents
 

 

 

Cash and Cash Equivalents at End of Period
 
$

 
$

 
$


AEPTCo 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.

Operating Activities
 
 
Years Ended December 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands)
Net Income
 
$
192,689

 
$
132,944

 
$
101,225

Deferred Income Taxes
 
223,096

 
183,180

 
207,141

Allowance for Equity Funds Used During Construction
 
(52,261
)
 
(53,080
)
 
(44,873
)
Accrued Taxes, Net
 
143,837

 
(53,634
)
 
20,318

Other
 
41,523

 
(10,044
)
 
(19,954
)
Net Cash Flows from Operating Activities
 
$
548,884

 
$
199,366

 
$
263,857


Net Cash Flows from Operating Activities were $549 million in 2016 consisting primarily of Net Income of $193 million and $223 million of noncash Deferred Income Taxes.  The change in Accrued Taxes is primarily due to bonus tax depreciation partially offset by an increase in property taxes due to additional transmission investments. 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.


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Net Cash Flows from Operating Activities were $199 million in 2015 consisting primarily of Net Income of $133 million and $183 million of noncash Deferred Income Taxes.  The change in Accrued Taxes is primarily due to bonus tax depreciation partially offset by an increase in property taxes due to additional transmission investments. 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 Operating Activities were $264 million in 2014 consisting primarily of Net Income of $101 million and $207 million of noncash Deferred Income Taxes.  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 thousands)
Construction Expenditures
 
$
(1,159,495
)
 
$
(1,007,791
)
 
$
(858,259
)
Change in Advances to Affiliates, Net
 
29,010

 
65,354

 
(151,835
)
Acquisitions of Assets
 
(6,518
)
 
(1,075
)
 
(11,472
)
Other
 
1,986

 
3,448

 
14,104

Net Cash Flows Used for Investing Activities
 
$
(1,135,017
)
 
$
(940,064
)
 
$
(1,007,462
)

Net Cash Flows Used for Investing Activities were $1.1 billion in 2016 primarily due to Construction Expenditures for transmission investments.

Net Cash Flows Used for Investing Activities were $940 million in 2015 primarily due to Construction Expenditures for transmission investments.

Net Cash Flows Used for Investing Activities were $1 billion in 2014 primarily due to Construction Expenditures for transmission investments.

Financing Activities
 
 
Years Ended December 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands)
Capital Contributions from Member
 
$
212,009

 
$
279,000

 
$
347,500

Issuance/Retirement of Debt, Net
 
386,904

 
449,008

 
477,733

Change in Advances from Affiliates, Net
 
(12,780
)
 
12,690

 
(81,628
)
Net Cash Flows from Financing Activities
 
$
586,133

 
$
740,698

 
$
743,605


Net Cash Flows from Financing Activities in 2016 were $586 million.  AEPTCo had debt issuances of $687 million, debt retirements of $300 million and received capital contributions of $212 million. See Note 10 to AEPTCo’s audited consolidated financial statements included elsewhere in this prospectus.

Net Cash Flows from Financing Activities in 2015 were $741 million.  AEPTCo had debt issuances of $449 million and received capital contributions of $279 million. See Note 10 to AEPTCo’s audited consolidated financial statements included elsewhere in this prospectus.

Net Cash Flows from Financing Activities in 2014 were $744 million.  AEPTCo had debt issuances of $478 million and received capital contributions of $348 million. AEPTCo also repaid $82 million of advances from affiliates.  See Note 10 to AEPTCo’s audited consolidated financial statements included elsewhere in this prospectus.


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BUDGETED CONSTRUCTION EXPENDITURES

Management forecasts approximately $1.5 billion of construction expenditures in 2017. For 2018 and 2019 combined, management forecasts construction expenditures of approximately $3 billion. 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, legal reviews and the ability to access capital.  Management expects to fund these construction expenditures through cash flows from operations and financing activities.  AEPTCo Parent and SWTCo can borrow directly from AEP to meet short-term borrowing needs. APTCo, IMTCo, KTCo, OHTCo, OKTCo and WVTCo have been approved to participate in the Utility Money Pool to finance their short-term borrowing needs until long-term funding is arranged.

OFF-BALANCE SHEET ARRANGEMENTS

AEPTCo’s current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that AEPTCo enters in the normal course of business.  As of December 31, 2016 and 2015, AEPTCo had no off-balance sheet arrangements.

CONTRACTUAL OBLIGATION INFORMATION

AEPTCo’s contractual cash obligations include amounts reported on the balance sheets and other obligations disclosed in the footnotes to AEPTCo’s audited consolidated financial statements, included elsewhere in this prospectus.  The following table summarizes AEPTCo’s 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 thousands)
Advances from Affiliates (a)
 
$
4,077

 
$

 
$

 
$

 
$
4,077

Interest on Fixed Rate Portion of Long-term Debt (b)
 
77,312

 
151,853

 
145,932

 
1,066,879

 
1,441,976

Fixed Rate Portion of Long-term Debt (c)
 

 
135,000

 
50,000

 
1,765,000

 
1,950,000

Noncancelable Operating Leases (d)
 
938

 
1,258

 
663

 

 
2,859

Construction Contracts for Capital Assets (e)
 
101,547

 

 

 

 
101,547

Total
 
$
183,874

 
$
288,111

 
$
196,595

 
$
2,831,879

 
$
3,500,459


(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 10 to AEPTCo’s audited consolidated financial statements, included elsewhere in this prospectus.  Represents principal only, excluding interest and debt issuance costs.
(d)
See Note 9 to AEPTCo’s audited consolidated financial statements, included elsewhere in this prospectus.
(e)
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.


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SIGNIFICANT TAX LEGISLATION

The Tax Increase Prevention Act of 2014 provided for a one-year extension of the 50% bonus depreciation and 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.

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. While there is no proposed statutory tax language on which to base definitive conclusions, management reviewed the tax proposals currently available, particularly the House Republican Blueprint. Management has assessed the accumulated deferred federal income taxes on the balance sheet as of December 31, 2016 and identified approximately $300 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 this amount of excess accumulated deferred income tax related to depreciation would flow back to customers through lower rates over the life of the applicable property. Management continues to work with industry groups and legislators to advocate for the benefit of AEPTCo’s customers and shareholder.

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

29



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 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 AEPTCo’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

AEPTCo’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.

AEPTCo recognizes regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) 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.


30



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-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 AEPTCo’s audited consolidated financial statements, included elsewhere in this prospectus for further detail related to regulatory assets and regulatory liabilities.

Revenue Recognition

Transmission Revenue Accounting

Pursuant to an order approved by the FERC, the AEP East Transmission Companies and the AEP West Transmission Companies are included in the OATT administered by PJM and SPP, respectively. The FERC order implemented an annual transmission revenue requirement for each of the AEP East Transmission Companies and the AEP West Transmission Companies. Under this requirement, AEPSC, on behalf of the AEP East Transmission Companies and the AEP West Transmission Companies, makes annual filings in order to recover prudently incurred costs and an allowed return on plant in service. An annual formula rate filing is made for each calendar year using estimated costs, which is used to determine the billings to PJM and SPP ratepayers. The annual rate filing is compared to actual costs with any over- or under-recovery being trued-up with interest and recovered in a future year’s rates.

In accordance with the accounting guidance for “Regulated Operations-Revenue Recognition”, AEPTCo recognizes revenue related to OATT rate true-ups immediately following the annual FERC filings. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable-Affiliated Companies or Accounts Payable-Affiliated Companies on the balance sheets. Any portion of the true-ups applicable to third parties is recorded as Regulatory Assets or Regulatory Liabilities on the balance sheets.

Long-Lived Assets

Nature of Estimates Required

In accordance with the requirements of “Property, Plant and Equipment” accounting guidance, AEPTCo 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.  AEPTCo 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, AEPTCo 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 affected assets and developing the undiscounted and discounted future cash flows (used to estimate fair value in the absence of market-

31



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.

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, AEPTCo 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 on the use of the asset.  AEPTCo 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.

ACCOUNTING PRONOUNCEMENTS

New Accounting Pronouncements Adopted During 2016

The FASB issued ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” eliminating the concept of extraordinary items for presentation on the face of the statements of income. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. Management adopted ASU 2015-01 effective January 1, 2016.

The FASB issued ASU 2015-05 “Customer’s Accounting for Fees paid in a Cloud Computing Arrangement” providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-05 prospectively, effective January 1, 2016, with no impact on results of operations, financial position or cash flows.


32



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, 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.

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 2016-01 “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, initial lease contract assessments were completed. The AEP

33



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 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.

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.  The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.


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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 Transmission Company, LLC and subsidiaries (the “Company” or “AEPTCo”). 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 AEPTCo was effective on April 4, 2017.
Deloitte’s reports on the financial statements of the Company as of December 31, 2016 and 2015 and for the years then 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 April 4, 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 April 4, 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 AEPTCo 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.
    



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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk

Fixed Rate Debt

Based on the borrowing rates currently available for bank loans with similar terms and average maturities, the fair value of AEPTCo’s long-term debt, excluding revolving credit agreements and commercial paper, was $2.0 billion as of December 31, 2016. The book value of AEPTCo’s long-term debt, net of discounts and deferred financing fees and excluding revolving credit agreements and commercial paper, was $1.9 billion as of December 31, 2016. Management performed an analysis calculating the impact of changes in interest rates on the fair value of long-term debt, excluding revolving credit agreements and commercial paper, as of December 31, 2016. An increase of 10% in interest rates used to calculate fair value (from 5.0% to 5.5%, for example) as of December 31, 2016 would decrease the fair value of debt by $85 million and a decrease in interest rates of 10% as of December 31, 2016 would increase the fair value of debt by $92 million at that date.
Corporate Borrowing Program

As of December 31, 2016, AEPTCo had $4 million of utility money pool borrowings outstanding under the AEP Corporate Borrowing Program, which is funded by commercial paper. Due to the short-term nature of these financial instruments, the carrying value of any outstanding short term debt would approximate fair value. Using a hypothetical continuous level of $100 million in utility money pool borrowings outstanding, the impact of a hypothetical 10% increase or decrease in interest rates for commercial paper would increase or decrease AEPTCo’s annual interest expense by less than $1 million.

Credit Risk

The State Transcos are regulated for rate-making purposes exclusively by FERC and employ a formula rate tariff design that incorporates forward looking -plant in service. As electric transmission utilities with rates regulated by FERC, the State Transcos earn revenues through tariff rates charged for the use of their electric transmission systems. The State Transcos establish transmission rates each year through formula rate filings with FERC. The rate filings calculate the revenue requirement needed to cover the costs of operation and debt service and to earn an allowed return on equity. These rates are then included in the OATT for SPP and PJM. SPP and PJM collect the revenue requirement from transmission customers under their respective OATTs. The transmission customers under the OATTs include the AEP Operating Companies, other investor-owned utilities, electric cooperatives, municipal entities and power marketers.

AEPTCo’s primary credit risk is with the AEP Operating Companies. For the years ended December 31, 2016, 2015 and 2014, the AEP Operating Companies were responsible for approximately 77%, 73% and 64%, respectively, of AEPTCo’s consolidated transmission revenues. Any financial difficulties experienced by the AEP Operating Companies could negatively impact AEPTCo’s business. However, PJM and SPP, as the billing agents of the State Transcos, have strict credit policies for its members’ customers, which include customers using our transmission systems. Specifically, PJM and SPP require a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a member’s transmission system.

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BUSINESS
Overview

AEPTCo, a Delaware limited liability company organized in 2006, is the holding company of seven regulated transmission-only electric utilities. AEPTCo is an indirect wholly-owned subsidiary of AEP. AEPTCo’s business consists of developing and building new transmission facilities at the request of the regional transmission organizations in which we operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers.

AEPTCo’s seven wholly-owned public utility companies are:

    AEP Appalachian Transmission Company, Inc.,
    AEP Indiana Michigan Transmission Company, Inc.,
    AEP Kentucky Transmission Company, Inc.,
    AEP Ohio Transmission Company, Inc.,
    AEP West Virginia Transmission Company, Inc.,
    AEP Oklahoma Transmission Company, Inc., and
    AEP Southwestern Transmission Company, Inc..

The State Transcos are independent of but overlay AEP’s existing electric utility operating companies: Appalachian Power Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport Power Company, Ohio Power Company, Public Service Company of Oklahoma, Southwestern Electric Power Company and Wheeling Power Company (collectively, the “AEP Operating Companies”). The State Transcos develop, own, operate, and maintain their respective transmission assets. Assets of the State Transcos interconnect to transmission facilities owned by the AEP Operating Companies and unaffiliated transmission owners within the footprints of the PJM and the SPP. PJM and SPP are RTOs mandated by the FERC to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale prices of electricity. PJM is a regional transmission organization serving approximately 61 million people throughout 13 states and the District of Columbia. APTCo, IMTCo, KTCo, OHTCo and WVTCo are located within PJM. SPP is a regional transmission organization serving over 18 million people in fourteen states. OKTCo and SWTCo are located within SPP.

The State Transcos are regulated for rate-making purposes exclusively by FERC and employ a formula rate tariff design that incorporates forward looking -plant in service. Activity between the State Transcos and the AEP Operating Companies is governed by service agreements. IMTCo, KTCo, OHTCo, OKTCo and WVTCo have received all necessary approvals for formation and currently own and operate transmission assets in their respective jurisdictions. In December 2016, the Virginia State Corporation Commission and the Public Service Commission of West Virginia issued separate orders that approve APTCo to construct, own, operate, and maintain transmission facilities and equipment in Tennessee using land and right of way (ROW) of APCo or APTCo in Tennessee. An application for regulatory approval for SWTCo is under consideration in Louisiana.

As electric transmission utilities with rates regulated by FERC, the State Transcos earn revenues through tariff rates charged for the use of their electric transmission systems. The State Transcos establish transmission rates each year through formula rate filings with FERC. The rate filings calculate the revenue requirement needed to cover the costs of operation and debt service and to earn an allowed return on equity. These rates are then included in the OATT for SPP and PJM. SPP and PJM collect the revenue requirement from transmission customers under their respective OATTs. The transmission customers under the OATTs include the AEP Operating Companies, other investor-owned utilities, electric cooperatives, municipal entities and power marketers.


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Development of Business

Each State Transco is geographically aligned with an existing AEP Operating Company. Each State Transco develops and owns new transmission assets that are physically connected to the electric system owned and operated by the AEP Operating Companies (the “AEP System”). Our business strategy is to own, operate, maintain and invest in transmission infrastructure in order to maintain and enhance system integrity and grid reliability, grid security, safety, reduce transmission constraints and facilitate interconnections of new generating resources and new wholesale customers, as well as enhance competitive wholesale electricity markets.

Development of transmission projects through the State Transcos is primarily driven by:

1.
Projects assigned to the AEP System as a result of the regional planning initiatives conducted by the RTOs. The RTOs identify the need for transmission in support of regional reliability, transmission service, congestion mitigation, public policy, to support the integration of new generation resources and to support the retirement of generation resources. These projects are referred to as “Regional Projects.”

2.
Improvements to local area reliability by upgrading, rebuilding or replacing existing, aging infrastructure at the AEP Operating Companies. Together with New Interconnections described below, these projects are referred to as “Local Projects.”

3.
Construction of new facilities to support customer points of delivery (“New Interconnections”).

Transmission investment across AEP is primarily driven by the need to revitalize aging infrastructure, our desire to enhance reliability at a local level to improve the customer experience, compliance with regulatory, industry, and governmental standards, requirements to improve telecommunication capability to keep up with changing technologies, and the obligation to address grid limitations identified by the RTOs. The State Transcos are not limited to investing in projects addressing particular transmission drivers. AEP has developed project selection guidelines that help determine which transmission assets can be built, owned and operated by the State Transcos. In essence, the need on the transmission grid determines the transmission project and the project selection guidelines help determine which components of the transmission project will be placed in the State Transcos.

Generally, greenfield transmission, partial or complete refurbishment of extra high voltage transmission, and complete refurbishment of lower voltage transmission assets qualify for transmission investment in the State Transcos. AEPTCo expects the majority of its transmission investment to go towards improving aging infrastructure, local reliability and upgrades to telecommunication and operational stacks.

Each State Transco is responsible for developing, constructing, owning, operating, and maintaining its respective transmission facilities.

Development of Regional Projects

Both PJM and SPP have sophisticated, long-term transmission planning processes to identify needed system upgrades. In their respective planning processes, each RTO identifies needed upgrades and then publishes those results in an annual plan. The following is an overview of the PJM and SPP regional transmission expansion plans.

The PJM Regional Transmission Expansion Plan (“RTEP”) identifies transmission system enhancements to meet the reliability requirements and ensure an efficient real-time operations of PJM electric transmission grid. PJM’s RTEP process encompasses a comprehensive assessment of system performance, adherence to PJM reliability criteria and compliance with the NERC Standards. The RTEP process also examines market efficiency to identify transmission enhancements that lower costs to consumers by relieving congested lines. Transmission enhancements are examined for their feasibility, impact and costs. This process culminates in a recommended RTEP for the entire PJM footprint that is submitted to PJM’s independent Board of Managers for consideration and approval each year. Under the PJM governing documents, transmission owning utilities in PJM are required to construct Board-approved RTEP projects.

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The SPP Transmission Expansion Plan (“STEP”) identifies distinct areas of transmission planning for the future development of the SPP transmission grid. SPP’s engineering staff works closely with members, regulators, and systems interconnecting with SPP to plan future transmission system expansion needs and provide transmission and generation interconnection service necessary to facilitate reliable and efficient delivery of generation resources to end-use customers. The SPP Board of Directors reviews the STEP annually for approval and endorsement of proposed projects. Under the SPP governing documents, transmission owning utilities in SPP are required to construct projects approved by the SPP Board of Directors.

Development of Local Projects

The State Transcos develop additional transmission projects to meet their fundamental obligation to serve customers and to ensure operability of the grid as designed. Local Projects include replacement of aging or obsolete infrastructure and enhancements to improve local reliability needs and support customer connections. These projects focus on upgrading, rebuilding or replacing specific assets that have reached the end of their useful life. AEP evaluates several criteria to determine the need for Local Projects. These criteria include age, recorded performance issues, condition assessment, anticipated maintenance requirements and criticality to the grid. Projects are assigned to the State Transcos based upon a defined set of criteria that are outlined in AEP’s Project Selection Guidelines. The need on the transmission grid determines the transmission project and project selection guidelines help determine which components of the transmission project will be placed in the State Transcos.
 
Project Approval

Regional Projects are subject to approval by the respective RTO Board. This is preceded by an open stakeholder review and comment period as part of the RTO planning process. Once approved, these Regional Projects are mandatory and must be constructed by the designated transmission owner pursuant to FERC rules that govern the RTOs.

Local Projects do not require RTO Board approval; however, the State Transcos have a plan that entails review of the Local Projects with relevant stakeholders including RTOs. This public vetting provides the stakeholders whose constituents will pay for these projects the opportunity to review and, if desired, to question and comment on those Local Project plans.

State Siting Approval

No prior regulatory approval is typically required to replace existing assets with new equipment of the same electrical rating. Approval is generally required for the replacement of lower voltage facilities with higher voltage lines. These requirements vary by state.

Competition

Local Projects and new interconnections are not subject to competition from other non-affiliated providers, owners or developers of transmission assets or services.

In PJM, Regional Projects situated within a single transmission zone, such as the zone in which the AEP System operates in PJM (the “AEP Transmission Zone”), are not subject to competition. These include: (i) Regional Projects that are fully cost allocated to the AEP Transmission Zone, (ii) time-sensitive Regional Projects that address planning criteria violations that occur within three years, and (iii) Regional Projects that are upgrades to existing transmission facilities. Regional Projects not meeting these criteria must be awarded by PJM or SPP in a process approved by FERC under Order 1000, and generally contemplates more than one bidder for any particular Regional Project.


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In PJM, projects with cost allocation in more than one zone are competitive. In the last three years only three projects met this criterion. In SPP greenfield transmission at or above 100 kilovolts (“kV”) is competitive. Most of the transmission solutions in SPP are comprised of upgrades to existing facilities and therefore are not subject to competition. Upkeep of existing assets is a fundamental obligation of a transmission owner and revitalization of existing assets is not open to competition in PJM and SPP.

Existing and Forecasted Projects

The State Transcos are geographically diverse and have assets in service or under construction across two RTOs and in six states, with additional states pending approval. We anticipate the need for extensive additional investment in transmission infrastructure within PJM and SPP to maintain the required level of grid reliability, resiliency, security and efficiency and to address an aging infrastructure. We also foresee the need to construct additional transmission facilities based on changes in generating resources such as wind or solar projects, generation additions or retirements, and additional new customer interconnections. We will continue our investment to enhance physical and cyber security of our assets, and are also investing in improving the telecommunication network that supports the operation and control of the grid. Finally, our fundamental obligation to meet state, federal, regulatory and industry standards will continue to drive investment in this category of projects.

A key part of our business is replacing and upgrading transmission facilities, assets and components of the existing AEP System as needed to maintain reliability. Roughly 7,000 miles of AEP's transmission lines were built more than seventy years ago and have surpassed their life expectancy. A significant quantity of major transmission equipment, such as transformers and circuit breakers, on AEP's grid have also surpassed their life expectancy. The State Transcos provide the capability to upgrade existing facilities due to their condition as a result of their age.

Operations

As transmission-only companies, our State Transcos function as conduits, allowing for power from generators to be transmitted to local distribution systems. The transmission of electricity by our State Transcos is a central function to the provision of electricity to residential, commercial and industrial end-use consumers. The operations performed fall into the following categories:

planning;
engineering, procurement and project services;
maintenance; and
real time operations.

Planning
AEPSC transmission employees (“AEP Transmission”) use detailed system models and load forecasts to develop our system capital plans. Expansion capital plans are used to identify projects that would address potential future reliability issues and service to new customers, connect new generation resources and/or produce economic savings for customers by eliminating constraints.
AEP Transmission works closely with PJM and SPP in the development of our system capital plans by performing technical evaluations and detailed studies. As the regional planning authorities, PJM and SPP approve regional system improvement plans which include projects to be constructed by their members, including our State Transcos.

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Engineering , Procurement and Project Services
AEP Transmission maintains in-house engineering expertise in all facets of the transmission AEP system. AEP Transmission also performs services for the estimating, project management and construction management services for the capital work plan. AEP Transmission performs much of this work and utilizes outside services as needed to supplement capacity to match the work load. AEP Transmission directly procures the majority of equipment used in the construction of its transmission projects. The majority of the construction work is performed by outside contractors.
Maintenance
AEP Transmission performs maintenance, field operations and emergency restoration of our State Transco transmission line and station facilities. AEP Transmission develops and tracks preventive maintenance plans to promote safe and reliable operation of our systems. By performing preventive maintenance on our assets, AEP Transmission minimizes the need for reactive maintenance, resulting in improved reliability and compliance with all applicable NERC and RTO requirements.
Real Time Operations
From our System Control Center located in New Albany, Ohio, transmission system operators continuously monitor the performance of the transmission system of the AEP System. AEP Transmission uses software and communication systems to perform analysis to maintain security and reliability and for contingency planning triggered by any unplanned events. From our geographically dispersed Transmission Dispatch Centers (situated in Roanoke, Virginia; New Albany, Ohio; Tulsa, Oklahoma; and Shreveport, Louisiana) our transmission dispatchers are responsible for the activities related to taking equipment in and out of service to ensure capital construction projects and maintenance programs are completed safely and reliably.
Operating Contracts
AEPSC has executed a services agreement pursuant to which AEPSC has agreed to provide services to each of the State Transcos. AEPSC is an AEP service subsidiary that provides management and professional services to AEP and its subsidiaries. AEPSC provides four categories of service to the State Transcos: project evaluation and permitting services, project development services, operation and management services and business services, including billing, insurance, human resources and IT services. All of these services are provided at cost. Additionally, each State Transco has executed a services agreement with the respective incumbent AEP Operating Company in its state or footprint.
Regulatory Environment
Federal regulators and public policy currently support further investment in transmission. The growth and changing mix of electricity generation and wholesale power sales, combined with historically inadequate transmission investment have resulted in significant transmission constraints across the United States and increased stress on aging transmission equipment. Transmission system investments increase system reliability and reduce the frequency of power outages. Such investments can also reduce transmission constraints and improve access to lower cost generation resources, resulting in a lower overall cost of delivered electricity for end-use consumers. FERC has encouraged new investment in the transmission sector by implementing various financial and other incentives.
FERC has issued orders to promote non-discriminatory transmission access for all transmission customers and has mandated that all transmission systems over which it has jurisdiction must be operated in a comparable, non-discriminatory manner such that any seller of electricity affiliated with a transmission owner or operator is not provided with preferential treatment. FERC requires compliance with certain reliability standards by transmission owners and may take enforcement actions for violations, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards.

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Federal Regulation and Formula Rate Setting at FERC
The State Transcos are regulated by FERC as electric transmission companies. FERC is an independent regulatory commission that regulates the transmission and wholesale sales of electricity in interstate commerce. FERC also administers accounting and financial reporting regulations and standards of conduct for the companies it regulates.
FERC has approved a formula rate mechanism to recover the State Transcos’ costs of investments in transmission facilities. The approved formula rate mechanism established a revenue requirement for transmission services over the facilities of the State Transcos under the respective PJM and SPP OATTs, as applicable, and implemented a transmission cost of service formula rate. The PJM and SPP OATTs provide standard terms and conditions to ensure consistent service availability and treatment of all transmission customers.

An OATT is the FERC rate schedule that provides the terms and conditions for transmission and related services on a transmission provider’s transmission system. FERC requires transmission providers to offer transmission service to all eligible customers (load-serving entities, generators, and customers in states with supplier choice) on a non- discriminatory basis. Through an OATT, FERC establishes transmission service rates for transmission owners, as derived from their annual transmission revenue requirement (“ATRR”). The ATRR consists of the cost of capital (debt and equity costs), plus income statement items such as operations and maintenance costs, depreciation, interest and taxes. The applicable RTO collects the transmission owner’s ATRR requirements from the transmission customers and provides payment to the transmission owner.

The State Transcos’ ATRR is under the PJM OATT or SPP OATT, as applicable. Under the terms and conditions provided in the applicable OATT, each State Transco files its ATRR annually in May, establishing rates for the one-year forward period of July of the current year through June of the following year (“Rate Year”). Concurrently, the ATRR includes a true-up calculation for the previous Rate Year’s billings, eliminating any potential for over- or under-recovery of expenses or the allowed return on and of the plant in-service. The applicable RTO collects the State Transcos’ ATRR requirements from the RTO transmission customers and provides payment to the State Transcos.


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The ATRR calculation allows the State Transcos to collect revenues during the Rate Year for the previous year’s financial activity plus projected plant in-service through the end of the filing year. This provides the State Transcos with a mechanism for revenue recovery of and on actual and projected capital investments. The table below illustrates the formula rate calculation for each of the State Transcos:

http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=11531278&doc=2

The most recent ATRR information was filed in May 2016. Inclusive in each State Transco ATRR is a true-up calculation to provide for any over or under recovery of revenues. The annual true-up calculation provides for the recovery of changes in the cost of capital. Any over or under- recovery of revenue is calculated with interest.

State Regulation
The public service commissions in the states where our State Transcos’ assets are located do not have jurisdiction over the State Transco’s rates or terms and conditions of service. However, certain transmission facilities are subject to certification and/or siting and financing requirements specific to each state. While these proceedings require a statement and justification of need, they also determine line routes and substation locations with the least impact to the environment and general public. The state public service commission or a designated entity will review the State Transco’s application to certify the project.
For a further discussion of rate and regulatory proceedings at FERC and state public service commissions, see Note 3 to our audited consolidated financial statements and related notes appearing elsewhere in this prospectus.

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Sources of Revenue
The State Transcos submit their annual revenue requirement to their respective RTO (PJM or SPP). PJM and SPP then charge their respective transmission customers under their respective OATT to collect the revenue requirement of all transmission owners under their respective OATT. The revenues collected from transmission customers are distributed by PJM and SPP to the applicable State Transcos, as transmission owners, based on their individual OATT revenue requirement. The illustration below depicts the revenue collection process.
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=11531278&doc=5
Principal Customers
Our principal transmission service customers in PJM are affiliated AEP Operating Companies. In SPP, our principal transmission service customers are also affiliated AEP Operating Companies. For the year ended December 31, 2016, the AEP Operating Companies were responsible for approximately 77% of our consolidated transmission revenues. Load serving entities are responsible for their portion of our PJM and SPP formula rate revenue requirement. Our remaining revenues are primarily generated from providing service to other entities such as alternative electricity suppliers and wholesale customers that provide electricity to end-use consumers.
Billing
PJM and SPP are responsible for billing and collecting our transmission service revenues as well as independently administering the transmission tariff in their respective service territory. As the billing agents for our State Transcos, PJM and SPP independently bill our customers on a monthly basis and collect fees for the use of our transmission systems. Should one of these entities default on its payment to the SPP or PJM, that portion of the revenue requirement is shared among the other transmission service customers in the RTO.
Employees
As of December 31, 2016, AEPTCo had no employees. Each State Transco and AEPSC has executed a services agreement pursuant to which AEPSC has agreed to provide services to each of the State Transcos. All such services are provided at cost. Additionally, each State Transco has executed a services agreement with the respective incumbent AEP Operating Company in its state. These form the core operative agreements by which each State Transco obtains services.

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Seasonality
The State Transcos’ cost-based formula rates with a true-up mechanism mitigate the seasonality of cash flows as amounts are collected evenly throughout the year. Our State Transcos accrue or defer revenues annually in June of each year to the extent that the actual revenue requirement for the prior PJM and SPP planning year was higher or lower, respectively, than the amounts billed. To the extent that a State Transco’s amounts billed are less than its revenue requirement for the annual period, a revenue accrual is recorded in June for this annual difference.
Environmental Matters
The State Transcos are 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 State Transcos currently incur 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 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.

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Properties
Our transmission facilities are located in Indiana, Kentucky, Michigan, Ohio, Oklahoma, and West Virginia and include the following assets:
639 circuit miles of overhead transmission lines rated at voltages of 34.5 kV to 765 kV;
43 stations;
other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment);
associated real property held in fee, by lease, or by easement grant; and
an approximately 190,000 square-foot AEP Transmission headquarters facility in New Albany, Ohio, including furniture, fixtures and office equipment.

Our State Transcos do not hold title to the majority of real property on which their electric transmission assets are located. Instead, under the provisions of certain affiliate contracts, each of our State Transcos are permitted to occupy and maintain their facilities upon real property held by the respective AEP Operating Company that overlays its operations. The ability of the State Transcos to continue to occupy such real property is dependent upon the terms of such affiliate contracts and upon the underlying real property rights of the AEP Operating Company, which may be encumbered by easements, mineral rights and other similar encumbrances that may affect the use of such real property.

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 3 and Note 5 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.


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MANAGEMENT
Set forth below is information regarding AEPTCo’s executive officers and members of our board of managers. 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 managers during the past ten years. Some officers serve in the same capacities at AEP and the Company. All of the managers of the Company are employees of AEPSC.

Listed below are the executive officers and managers at March 1, 2017.

Nicholas K. Akins
Chairman of the Board, Chief Executive Officer and Manager of the Company
Chairman of the Board, President and Chief Executive Officer of AEP
Age 56
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.

Lisa M. Barton
President, Chief Operating Officer and Manager of the Company
Executive Vice President - Transmission of AEP
Age 51
Executive Vice President - Transmission of AEPSC since August 2011. She was Senior Vice President - Transmission Strategy and Business Development of AEPSC from November 2010 to July 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
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. 

David M. Feinberg
Vice President, Secretary and Manager 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.

Lana L. Hillebrand
Executive Vice President and Chief Administrative Officer of AEP
Age 56
Executive Vice President since January 2017. She was Senior Vice President from December 2012 to December 2016 and Chief Administrative Officer since December 2012. She previously served as South Region leader - Senior Partner at Aon Hewitt from 2010 to 2012.

Charles Patton
Executive Vice President-External Affairs of AEP
Age 57
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.


47



Robert P. Powers
Vice Chairman of AEP
Age 63
Vice Chairman since January 2017. He was Executive Vice President and Chief Operating Officer of AEP from November 2011 to December 2016 and President - Utility Group of AEP from April 2009 to November 2011.

A. Wade Smith
Manager of the Company
Age 52
Mr. Smith is Senior Vice President-Grid Development for AEPSC since August 2015. He was President and Chief Operating Officer of AEP Texas Central Company and AEP Texas North Company from 2010 to August 2015.
Brian X. Tierney
Vice President, Chief Financial Officer and Manager of the Company
Executive Vice President and Chief Financial Officer of AEP since October 2009.
Age 49


48



COMPENSATION DISCUSSION AND ANALYSIS
The following information relates to AEP. AEP Transmission Company, LLC 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:
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
Vice Chairman of AEP
Mr. Feinberg
Executive Vice President and General Counsel of AEP
Ms. Barton
Executive Vice President Transmission 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.
 

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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;


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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.
 
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.
 

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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 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. As illustrated in the charts below, in 2016, 69 percent of the target total direct compensation for the CEO and 61 percent on average for the other named executive officers 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 and an additional 14 percent on average for the other named executive officers was provided in the form of time-vesting RSUs (grant date value) which are tied to AEP’s stock price.

http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=11531278&doc=4


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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 50th percentile, and closer to the 75th 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.
 
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.
 

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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
 
 
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:
 
 
 
 
 
 
 
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.


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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).
 
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 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.
 
    

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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.
 
    

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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




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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

*
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

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.
 

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In February 2017, Mr. Powers announced his retirement from AEP in August 2017. Mr. Powers will remain Vice Chairman of AEP until his retirement. Mr. Powers did not receive a 2017 long-term incentive (LTIP) award because of his announced retirement, but AEP intends to provide a cash payment to Mr. Powers instead. In connection with Mr. Powers’ retirement, AEP and Mr. Powers anticipate entering into a separation and release of all claims agreement, containing among other things, certain non-solicitation, confidentiality and cooperation agreements. It is anticipated that this agreement will provide a cash payment that would provide 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.
 

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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.
 
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.

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 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.
 
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.
 

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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 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.

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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, 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.
 

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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.

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
-  
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
-  
6,719,981
3,150,000
199,027
103,658
11,452,566
2014
1,240,754
-  
6,720,019
2,950,000
359,787
102,960
11,373,520
 
 
 
 
 
 
 
 
 
Brian X. Tierney-
2016
730,800
-  
1,895,038
990,000
131,575
95,026
3,842,439
Executive Vice President and
Chief Financial Officer
2015
709,246
-  
1,907,216
1,100,000
0
84,125
3,800,587
2014
695,339
-  
1,881,251
1,050,000
269,994
82,448
3,979,032
 
 
 
 
 
 
 
 
 
Robert P. Powers-
2016
723,773
-  
1,895,038
980,000
335,960
93,931
4,028,702
Vice Chairman
2015
709,246
-  
1,888,008
1,075,000
0
90,234
3,762,488
2014
695,339
-  
1,881,251
1,012,000
746,589
82,706
4,417,885
 
 
 
 
 
 
 
 
 
David M. Feinberg-
2016
615,358
-  
1,126,919
730,000
85,179
75,435
2,632,891
Executive Vice President and General Counsel
2015
591,426
-  
998,394
800,000
59,069
68,163
2,517,052
2014
568,679
-  
962,482
675,000
69,384
63,293
2,338,838
 
 
 
 
 
 
 
 
 
Lisa M. Barton-
2016
532,039
-  
1,003,030
650,000
95,020
68,007
2,348,096
Executive Vice President- Transmission
2015
516,750
-  
998,394
686,000
49,931
59,042
2,310,117
2014
452,735
-  
804,984
540,000
71,814
47,919
1,917,452

(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 and $1,504,608 for Ms. Barton; 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 and $1,397,704 for Ms. Barton. 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:


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Type 
Nicholas K.
         Akins 
Brian X.
 Tierney 
Robert P.
   Powers
David M.
 Feinberg
Lisa M.
 Barton
Retirement Savings Plan Match
$11,629
$11,925
$11,925
$11,925
$11,925
Supplemental Retirement Savings Plan Match
$78,075
$70,302
$68,873
$51,623
$42,771
Perquisites
$13,983
$12,799
$13,133
$11,887
$13,311
Total
$103,687
$95,026
$93,931
$75,435
$68,007

    
Perquisites provided in 2016 included: financial counseling and tax preparation services, and, for Mr. Akins, director’s accidental death insurance premium. Executive officers may also have the occasional personal use of event tickets when such tickets are not being used for business purposes, however, there is no associated incremental cost. From time to time executive officers may receive customary gifts from third parties that sponsor sporting events (subject to our policies on conflicts of interest).

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
 
-  
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
 
-  
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
 
-  
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
 
-  
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
 
-  
370,631
926,578