Proxy Statement (definitive) (def 14a)

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SCHEDULE 14A

(Rule 14a-101)

INFORMATION REQUIRED IN PROXY STATEMENT

SCHEDULE 14A INFORMATION

Proxy Statement Pursuant to Section 14(a) of the Securities

Exchange Act of 1934

(Amendment No. )

 

Filed by the Registrant    x

 

Filed by a Party other than the Registrant    ¨

 

Check the appropriate box:

 

 

¨    Preliminary Proxy Statement

¨

Confidential, for Use of the Commission Only        (as permitted by Rule 14a-6(e)(2))

x    Definitive Proxy Statement

 

¨     Definitive Additional Materials

 

¨    Soliciting Material Pursuant to Rule 14a-12.

 

American Electric Power Company, Inc.

(Name of Registrant as Specified in its Charter)

 

(Name of Person(s) Filing Proxy Statement, if other than the Registrant)

 

Payment of Filing Fee (Check the appropriate box):

 

x No fee required.

 

¨ Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11.

 

  (1) Title of each class of securities to which transaction applies:

 

  (2) Aggregate number of securities to which transaction applies:

 

  (3) Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (Set forth the amount on which the filing fee is calculated and state how it was determined):

 

  (4) Proposed maximum aggregate value of transaction:

 

  (5) Total fee paid:

 

¨ Fee paid previously with preliminary materials.

 

¨ Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing.

 

  (1) Amount Previously Paid:

 

  (2) Form, Schedule or Registration Statement No.:

 

  (3) Filing Party:

 

  (4) Date Filed:


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Notice of 2015 Annual Meeting • Proxy Statement

 

LOGO

       American Electric Power

1 Riverside Plaza

Columbus, OH 43215

         Nicholas K. Akins

Chairman of the Board and
Chief Executive Officer

 

March 12, 2015

 

Dear Shareholders:

 

This year’s annual meeting of shareholders will be held at The Ohio State University’s Fawcett Center, 2400 Olentangy River Road, Columbus, Ohio on Tuesday, April 21, 2015, at 9:00 a.m. Eastern Time.

 

Your Board of Directors and I cordially invite you to attend. Registration will begin at 8:00 a.m. Only shareholders who owned shares on the record date, February 23, 2015, are entitled to vote and attend the meeting. To attend the meeting, you will need to present an admission ticket or the notice you received. If your shares are registered in your name, and you received your proxy materials by mail, your admission ticket is attached to your proxy card. A map and directions are printed on the admission ticket. If your shares are registered in your name and you received your proxy materials electronically via the Internet, you will need to print an admission ticket after you vote by clicking on the “Options” button. If you hold shares through an account with a bank or broker, you will need to contact them and request a legal proxy, or bring a copy of your statement to the meeting that shows that you owned the shares on the record date. Each ticket will admit a shareholder and one guest.

 

We are mailing to many of our shareholders a notice instead of a paper copy of this proxy statement and our 2014 Annual Report. The notice contains instructions on how to access those documents over the Internet. The notice also contains instructions on how shareholders can receive a paper copy of our proxy materials, including this proxy statement, our 2014 Annual Report and a form of proxy card or voting instruction card.

 

During the course of the meeting there will be the usual time for discussion of the items on the agenda and for questions regarding AEP’s affairs. Directors and officers will be available to talk individually with shareholders before and after the meeting.

 

Your vote is very important. Shareholders of record can vote in any one of the following three ways:

 

   

By Internet, at www.envisionreports.com/AEP

 

   

By toll-free telephone at 800-652-8683

 

   

By completing and mailing your proxy card if you receive paper copies of the proxy materials

 

If your shares are held in the name of a bank, broker or other holder of record, you will receive instructions from the holder of record that you must follow in order for you to vote your shares.

 

If you have any questions about the meeting, please contact Investor Relations, American Electric Power Company, 1 Riverside Plaza, Columbus, Ohio 43215. The telephone number is 800-237-2667.

 

Sincerely,

 

LOGO


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NOTICE OF 2015 ANNUAL MEETING

 


 

American Electric Power Company, Inc.

1 Riverside Plaza

Columbus, Ohio 43215

 


 

TIME

   9:00 a.m. Eastern Time on Tuesday, April 21, 2015

PLACE

  

The Ohio State University Fawcett Center

2400 Olentangy River Road

Columbus, Ohio

ITEMS OF BUSINESS

  

(1)    To elect the 12 directors named herein to hold office until the next annual meeting and until their successors are duly elected.

    

(2)    To ratify the appointment of Deloitte & Touche LLP as the independent registered public accounting firm for the year 2015.

    

(3)    To hold an advisory vote on executive compensation.

    

(4)    To consider and act on a proposal to approve the American Electric Power System 2015 Long-Term Incentive Plan.

    

(5)    To vote on a proposal to amend the Company’s Restated Certificate of Incorporation to Eliminate Article 7.

    

(6)    To vote on a proposal to amend the Company’s Bylaws to eliminate the supermajority provisions.

    

(7)    To vote on a shareholder proposal for proxy access set forth at pages 35 to 40, if properly presented at the meeting.

    

(8)    To consider and act on such other matters as may properly come before the meeting.

RECORD DATE

   Only shareholders of record at the close of business on February 23, 2015 are entitled to notice of and to vote at the meeting or any adjournment thereof.

ANNUAL REPORT

   Appendix A to this proxy statement has AEP’s audited financial statements, management’s discussion and analysis of results of operations and financial condition and the report of the independent registered public accounting firm.

PROXY VOTING

   It is important that your shares be represented and voted at the meeting. Please vote in one of these ways:
    

(1)    MARK, SIGN, DATE AND PROMPTLY RETURN your proxy card if you receive paper copies of the proxy materials.

    

(2)    CALL TOLL-FREE by telephone at 800-652-8683.

    

(3)    VISIT THE WEB SITE shown on the notice of Internet availability of proxy materials to vote via the Internet.

    

If your shares are held in the name of a bank, broker or other holder of record, please follow the instructions from the holder of record in order to vote your shares.

 

Any proxy may be revoked at any time before your shares are voted at the meeting.

 

March 12, 2015    David M. Feinberg

Secretary

 

 


Table of Contents

TABLE OF CONTENTS

 

Proxy and Voting Information

     1   

Item 1: Election of Directors

     3   

AEP’s Board of Directors and Committees

     7   

Director Compensation

     18   

Item 2: Proposal to Ratify Appointment of Independent Registered Public Accounting Firm

     21   

Item 3: Advisory Vote on Executive Compensation

     24   

Item 4: Proposal to approve the American Electric Power System 2015 Long-Term Incentive Plan

     25   

Item  5: Proposal to amend the Company’s Restated Certificate of Incorporation to Eliminate Article 7.

     33   

Item 6: Proposal to amend the Company’s Bylaws to Eliminate the Supermajority Provisions.

     34   

Item 7: Shareholder Proposal on Proxy Access

     35   

Compensation Discussion and Analysis

     40   

Executive Summary

     40   

Results of 2014 Advisory Vote to Approve Executive Compensation

     42   

Compensation Program Design

     43   

Compensation Peer Group

     44   

Executive Compensation Program Detail

     47   

Other Compensation Information

     55   

Human Resources Committee Report

     58   

Executive Compensation

     61   

Summary Compensation Table

     61   

Grants of Plan-Based Awards for 2014

     63   

Outstanding Equity Awards at Fiscal Year-End for 2014

     66   

Option Exercises and Stock Vested for 2014

     68   

Pension Benefits for 2014

     69   

Nonqualified Deferred Compensation for 2014

     72   

Potential Payments Upon Termination of Employment or Change in Control

     74   

Share Ownership of Directors and Executive Officers

     85   

Section 16(a) Beneficial Ownership Reporting Compliance

     86   

Share Ownership of Certain Beneficial Owners

     86   

Shareholder Proposals and Nominations

     86   

Solicitation Expenses

     87   

Exhibit A: Reconciliation of GAAP and Non-GAAP Financial Measures

     A-1   

Exhibit B: American Electric Power System 2015 Long-Term Incentive Plan

     B-1   

Exhibit C: Restated Certificate of Incorporation Article 7

     C-1   

Exhibit D: Proposed Amendment to Section 16 of the Bylaws

     D-1   


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Proxy Statement

 

March 12, 2015

 

Proxy and Voting Information

 

A notice of Internet availability of proxy materials or paper copy of the proxy statement and form of proxy is to be mailed to shareholders on or about March 12, 2015, in connection with the solicitation of proxies by the Board of Directors of American Electric Power Company, Inc., 1 Riverside Plaza, Columbus, Ohio 43215, for the annual meeting of shareholders to be held on April 21, 2015 in Columbus, Ohio.

 

We use the terms “AEP,” the “Company,” “we,” “our” and “us” in this proxy statement to refer to American Electric Power Company, Inc. and, where applicable, its subsidiaries. All references to “years,” unless otherwise noted, refer to our fiscal year, which ends on December 31.

 

Who Can Vote.    Only the holders of shares of AEP common stock at the close of business on the record date, February 23, 2015 are entitled to vote at the meeting. Each such holder has one vote for each share held on all matters to come before the meeting. On that date, there were 489,620,548 shares of AEP common stock, $6.50 par value, outstanding.

 

How You Can Vote.    Shareholders of record can give proxies by (i) mailing their signed proxy cards; (ii) calling a toll-free telephone number; or (iii) using the Internet. The telephone and Internet voting procedures are designed to authenticate shareholders’ identities, to allow shareholders to give their voting instructions and to confirm that shareholders’ instructions have been properly recorded. Instructions for shareholders of record who wish to use the telephone or Internet voting procedures are set forth on the proxy card or the website shown on the notice of internet availability of proxy materials.

 

If your shares are held in the name of a bank, broker or other holder of record, you will receive instructions from the holder of record that you must follow in order for you to vote your shares.

 

When proxies are signed and returned, the shares represented thereby will be voted by the persons named on the proxy card or by their substitutes in accordance with shareholders’ directions. If a proxy card is signed and returned without choices marked, it will be voted for the nominees for directors listed on the card and as recommended by the Board of Directors with respect to other matters. The proxies of shareholders who are participants in the Dividend Reinvestment and Stock Purchase Plan include both the shares registered in their names and the whole shares held in their plan accounts on February 23, 2015.

 

Revocation of Proxies.    A shareholder giving a proxy may revoke it at any time before it is voted at the meeting by voting again after the date of the proxy being revoked or by attending the meeting and voting in person.

 

How Votes are Counted.    The presence of the holders of a majority of the outstanding shares of common stock entitled to vote at the Annual Meeting, present in person or represented by proxy, is necessary to constitute a quorum. Abstentions and “broker non-votes” are counted as present and entitled to vote for purposes of determining a quorum. A “broker non-vote” occurs when a broker holding shares for a beneficial owner does not vote on a particular proposal because the broker does not have discretionary voting power for that particular item and has not received instructions from the beneficial owner.

 

Under current New York Stock Exchange (NYSE) rules, the proposal to ratify the appointment of Deloitte & Touche LLP as our independent registered public accounting firm is considered a “discretionary” item. This means that brokerage firms may vote in their discretion on this matter

 

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on behalf of their clients who have not furnished voting instructions. The proposals to elect directors, the advisory vote on executive compensation, adoption of the long-term incentive plan, the amendment to the Restated Certificate of Incorporation, the amendment to the Bylaws and the shareholder proposal are “non-discretionary” matters. That means that brokerage firms may not use their discretion to vote on such matters without express voting instructions from their clients.

 

The Company has implemented a majority voting standard for the election of directors in uncontested elections of directors. The election of directors at the Annual Meeting is an uncontested election, so for a nominee to be elected to the Board, the number of votes cast “for” the nominee’s election must exceed the number of votes cast “against” his or her election. Abstentions and broker non-votes will not be considered votes cast “for” or “against” a nominee and will therefore have no effect on the outcome. If a nominee does not receive a greater number of votes “for” his or her election than “against” such election, he or she will be required to tender his or her resignation for the Board’s consideration of whether to accept such resignation in accordance with our Bylaws. No shareholder has the right to cumulate his or her voting power in the election of directors at the Annual Meeting.

 

Shareholder approval of Item 2: Proposal to Ratify Appointment of Independent Registered Public Accounting Firm, Item 3: Advisory Vote on Executive Compensation, Item 4: Proposal to Approve the American Electric Power System 2015 Long-Term Incentive Plan and Item 7: Shareholder Proposal on Proxy Access require an affirmative vote of a majority of votes cast at a meeting of shareholders. This means that the votes cast “for” the proposal must exceed the votes cast “against” the proposal in order for the proposal to pass. Abstentions and broker non-votes are not counted as votes “for” or “against” Item 3: Advisory Vote on Executive Compensation, Item 4: Proposal to Approve the American Electric Power System 2015 Long-Term Incentive Plan and Item 7: Shareholder Proposal on Proxy Access and therefore will have no effect on the outcome of the votes with respect to such proposal.

 

Shareholder approval of Item 5: Proposal to Amend the Company’s Restated Certificate of Incorporation to Eliminate Article 7 requires the affirmative vote of at least a majority of the outstanding shares. Shareholder approval of Item 6: Proposal to Amend the Company’s Bylaws to Eliminate the Supermajority Provisions requires the affirmative vote of the holders of two-thirds of the shares outstanding.

 

Abstentions are not counted as votes “for” or “against” Item 2 (Proposal to Ratify the Appointment of Independent Registered Public Accounting Firm) and therefore will have no effect on the outcome of the vote with respect to such proposal.

 

Your Vote is Confidential.    It is AEP’s policy that shareholders be provided privacy in voting. All proxies, voting instructions and ballots, which identify shareholders, are held on a confidential basis, except as may be necessary to meet any applicable legal requirements. We direct proxies to an independent third-party tabulator who receives, inspects, and tabulates them. Voted proxies and ballots are not seen by nor reported to AEP except (i) in aggregate number or to determine if (rather than how) a shareholder has voted, (ii) in cases where shareholders write comments on their proxy cards or (iii) in a contested proxy solicitation.

 

Multiple Copies of Annual Report, Proxy Statement or Notice of Internet Availability of Proxy Materials to Shareholders.    Securities and Exchange Commission (SEC) rules provide that more than one annual report, proxy statement or notice of Internet availability of proxy materials need not be sent to the same address. This practice is commonly called “householding” and is intended to eliminate duplicate mailings of shareholder documents. Mailing of your annual report, proxy statement or notice of Internet availability of proxy materials is being householded indefinitely unless you instruct us otherwise. We will deliver promptly upon written or oral request a

 

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separate copy of the annual report, proxy statement or notice of Internet availability of proxy materials to a shareholder at a shared address. To receive a separate copy of the annual report, proxy statement or notice of Internet availability of proxy materials, write to AEP, attention: Investor Relations, at 1 Riverside Plaza, Columbus, OH 43215 or call 1-800-237-2667. If more than one annual report, proxy statement or notice of Internet availability of proxy materials is being sent to your address, at your request, mailing of the duplicate copy can be discontinued by contacting our transfer agent, Computershare Trust Company, N.A. (Computershare), at 800-328-6955 or writing to them at P.O Box 43078, Providence, RI 02940-3078. If you wish to resume receiving separate annual reports, proxy statements or notice of Internet availability of proxy materials at the same address in the future, you may call Computershare at 800-328-6955 or write to them at P.O Box 43078, Providence, RI 02940-3078. The change will be effective 30 days after receipt.

 

Additional Information.    Our website address is www.aep.com. We make available free of charge on the Investor Relations section of our website (www.aep.com/investors) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (Exchange Act). We also make available through our website other reports filed with or furnished to the SEC under the Exchange Act, including our proxy statements and reports filed by officers and directors under Section 16(a) of the Exchange Act. You may request any of these materials and information in print by contacting Investor Relations at: AEP, attention: Investor Relations, 1 Riverside Plaza, Columbus, OH 43215. We do not intend for information contained on our website to be part of this proxy statement. In addition, this proxy statement and the Annual Report on Form 10-K for the fiscal year ended December 31, 2014 are available at www.edocumentview.com/aep.

 

Item 1. Election of Directors

 

Twelve directors are to be elected to hold office until the next annual meeting and until their successors have been elected. AEP’s Bylaws provide that the number of directors of AEP shall be such number, not less than 9 nor more than 17, as shall be determined from time to time by resolution of the Board.

 

The 12 nominees named on pages 4 to 7 were nominated by the Board on the recommendation of the Committee on Directors and Corporate Governance of the Board, following an individual evaluation of each incumbent nominee’s qualifications and 2014 performance. The proxies named on the proxy card or their substitutes will vote for the Board’s nominees, unless instructed otherwise. All of the Board’s nominees were elected by the shareholders at the 2014 annual meeting. We do not expect any of the nominees will be unable to stand for election or be unable to serve if elected. If a vacancy in the slate of nominees occurs before the meeting, the proxies may be voted for another person nominated by the Board or the number of directors may be reduced accordingly.

 

Biographical Information.    The following brief biographies of the nominees include their principal occupations, ages on the date of this proxy statement, accounts of their business experience and names of certain companies of which they are directors. Data with respect to the number of shares of AEP’s Common Stock and stock-based units beneficially owned by each of them appears on page 85.

 

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Nominees For Director

 

LOGO   

Nicholas K. Akins

 

Dublin, Ohio

 

Age 54

 

Director since 2011

  

Elected chief executive officer of AEP in November 2011; elected chairman of the board in January 2014 and chairman and chief executive officer of all of its major subsidiaries in November 2011. President of AEP from January 2011 to October 2011 and executive vice president of AEP from 2006 to 2011. A director of Fifth Third Bancorp.

 

Mr. Akins’ qualifications to serve on the Board include his extensive senior executive experience in the utility industry and his deep knowledge of the Company as our chief executive officer.

LOGO   

David J. Anderson

 

Greenwich, Connecticut

 

Age 65

 

Director since 2011

  

Retired senior vice president and chief financial officer of Honeywell International, a diversified technology and manufacturing company, from 2003 until his retirement in April 2014. A director of Cardinal Health, Inc., BE Aerospace Inc., and Fifth Street Asset Management, Inc.

 

Mr. Anderson’s qualifications to serve on the Board include his corporate finance expertise as the chief financial officer of a Fortune 100 company and his experience as a public company director.

LOGO   

J. Barnie Beasley, Jr.

 

Sylvania, Georgia

 

Age 63

 

Director since 2014

  

Mr. Beasley served as an independent nuclear safety and operations expert to the board of directors of the Tennessee Valley Authority, a large electric utility in the southeastern United States, from 2011 to 2014. Retired chairman, president and chief executive officer of Southern Nuclear Operating Company, the nuclear operating company subsidiary of an electric utility (2005-2008). Mr. Beasley was formerly a director of EnergySolutions, Inc. (2008-2013), and he has served as an advisor to that company since 2014.

 

Mr. Beasley’s qualifications to serve on the Board include his nuclear expertise as the chief executive officer of the nuclear operating company subsidiary of Southern Company and his experience in the utility industry and as a public company director.

 

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Nominees for Director — continued

 

LOGO   

Ralph D. Crosby, Jr.

 

McLean, Virginia

 

Age 67

 

Director since 2006

  

Retired chairman of EADS North America, Inc., an aerospace company (2002-2011). Retired chief executive officer of EADS North America, Inc. (2002-2009). A director of Serco Group PLC and Airbus Group N.V. Mr. Crosby was formerly a director of Ducommun Incorporated (2000-2013).

 

Mr. Crosby’s qualifications to serve on the Board include his extensive senior executive experience in the aerospace industry and his experience as a public company director.

LOGO   

Linda A. Goodspeed

 

Crestview, Florida

 

Age 53

 

Director since 2005

  

Managing partner of Wealthstrategies Financial Advisors, LLC since 2008. Retired senior vice president and chief information officer of The ServiceMaster Company, a residential and commercial service company (2011-2013). From 2008 to 2011, vice president of information systems of Nissan North America, Inc., an automobile manufacturer. A director of Columbus McKinnon Corp and AutoZone, Inc.

 

Ms. Goodspeed’s qualifications to serve on the Board include her information technology expertise as the chief information officer of a service company and her experience as a public company director.

LOGO   

Thomas E. Hoaglin

 

Columbus, Ohio

 

Age 65

 

Director since 2008

  

Retired chairman and chief executive officer of Huntington Bancshares Incorporated, a bank holding company (2001-2009). A director of The Gorman-Rupp Company.

 

Mr. Hoaglin’s qualifications to serve on the Board include his extensive senior executive experience in the banking industry and his experience as a public company director.

LOGO   

Sandra Beach Lin

 

Flower Mound, Texas

 

Age 57

 

Director since 2012

  

Retired chief executive officer of Calisolar, Inc., a solar silicon company, a position she held from August 2010 until December 2011. Corporate executive vice president (February 2009 to July 2010) and executive vice president (July 2007 to February 2009) of Celanese Corporation, a global hybrid chemical company. A director of WESCO International and PolyOne Corporation.

 

Ms. Lin’s qualifications to serve on the Board include her extensive senior executive experience managing global businesses in multiple industries and her experience as a public company director.

 

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Nominees for Director — continued

 

LOGO   

Richard C. Notebaert

 

Chicago, Illinois

 

Age 68

 

Director since 2011

  

Retired chief executive officer of Qwest Communications International Inc., a telecommunications systems company (2002-2007). A director of Aon Corporation and Cardinal Health, Inc.

 

Mr. Notebaert’s qualifications to serve on the Board include his extensive senior executive experience in the regulated telecommunications industry and his experience as a public company director.

LOGO   

Lionel L. Nowell III

 

Marco Island, Florida

 

Age 60

 

Director since 2004

  

Retired senior vice president and treasurer of PepsiCo, Inc., a food and beverage company (2001-2009). A director of Reynolds American Inc., Darden Restaurants Inc. and Bank of America Corporation.

 

Mr. Nowell’s qualifications to serve on the Board include his capital markets, accounting, financial reporting, and risk management skills and experience at a Fortune 100 company, and his experience as a public company director.

LOGO   

Stephen S. Rasmussen

 

Columbus, Ohio

 

Age 62

 

Director since 2012

  

Chief executive officer of Nationwide Mutual Insurance Company (Nationwide) since 2009. President and chief operating officer of Nationwide (2003 – 2009).

 

Mr. Rasmussen’s qualifications to serve on the Board include his extensive senior executive experience in the regulated insurance industry.

LOGO   

Oliver G. Richard, III

 

Lake Charles, Louisiana

 

Age 62

 

Director since 2013

   Chairman of privately held CleanfuelUSA, an alternative vehicular fuel company since 2006. Owner and president of Empire of the Seed LLC, a private consulting firm in the energy and management industries, as well as the private investments industry since 2005. Mr. Richard served as chairman, president and chief executive officer of Columbia Energy Group (“Columbia Energy”) from April 1995 until Columbia Energy was acquired by NiSource Inc. in November 2000. Mr. Richard served as a commissioner of the Federal Energy Regulatory Commission from 1982 to 1985. A director of Buckeye Partners, L.P. and Cheniere Energy Partners, GP, LLC.

 

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Nominees for Director — continued

 

          Mr. Richard’s qualifications to serve on the Board include his extensive knowledge of the utility industry as a former commissioner of the Federal Energy Regulatory Commission, his senior executive experience at a utility company and his experience as a public company director.
LOGO   

Sara Martinez Tucker

 

Dallas, Texas

 

Age 59

 

Director since 2009

  

Chief executive officer of the National Math and Science Initiative since March 1, 2013. From 2009 to February 2013, independent consultant. Former Under Secretary of Education in the U.S. Department of Education (2006-2008). Chief executive officer and president of the Hispanic Scholarship Fund from 1997 to 2006. Retired executive of AT&T. A director of Xerox Corporation and Sprint Corporation.

 

Ms. Tucker’s qualifications to serve on the Board include her experience in governmental affairs as the Under Secretary of Education, her experience in human resources and customer service operations in the regulated telecommunications industry and her experience as a public company director.

 

AEP’s Board of Directors and Committees

 

Under New York law, AEP is managed under the direction of the Board of Directors. The Board establishes broad corporate policies and authorizes various types of transactions, but it is not involved in day-to-day operational details. During 2014, the Board held six regular meetings and two telephonic meetings. AEP encourages but does not require members of the Board to attend the annual shareholders’ meeting. Last year, all directors attended the annual meeting.

 

Two members of our Committee on Directors and Corporate Governance, Ms. Lin and Mr. Hoaglin, are members of The National Association of Corporate Directors’ Nominating and Governance Chair Advisory Council, a group that seeks to identify ways that board nominating and governance committees can help build investor confidence in publicly traded companies.

 

Board Meetings and Committees.    The Board expects that its members will rigorously prepare for, attend and participate in all Board and applicable committee meetings. Directors are also expected to become familiar with AEP’s management team and operations as a basis for discharging their oversight responsibilities.

 

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The Board has seven standing committees. The table below shows the number of meetings conducted in 2014 by each committee and the directors who currently serve on these committees. Each director attended 90 percent or more of the meetings of the Board and Board committees on which he or she served during 2014, and the average director attendance in 2014 was 98 percent.

 

DIRECTOR   BOARD COMMITTEES
  Audit  

Directors

and

Corporate

Governance

  Policy   Executive   Finance  

Human

Resources

 

Nuclear

Oversight

Mr. Akins

          X   X (Chair)            

Mr. Anderson

  X       X       X (Chair)        

Mr. Beasley

  X       X               X

Mr. Crosby

          X   X       X (Chair)   X

Ms. Goodspeed

  X       X (Chair)               X

Mr. Hoaglin

      X (Chair)   X   X       X    

Ms. Lin

  X   X   X                

Mr. Notebaert

      X   X       X   X    

Mr. Nowell

  X (Chair)   X   X   X   X        

Mr. Rasmussen

      X   X       X   X    

Mr. Richard

          X           X   X (Chair)

Ms. Tucker

  X   X   X                

2014 Meetings

  7   5   3   0   5   7   4

 

The functions of the committees are described below.

 

The Committee on Directors and Corporate Governance has the responsibilities set forth in its charter, including:

 

1.   Recommending the size of the Board within the limits imposed by the Bylaws.

 

2.   Recommending selection criteria for nominees for election or appointment to the Board.

 

3.   Conducting independent searches for qualified nominees and screening the qualifications of candidates recommended by others.

 

4.   Recommending to the Board nominees for appointment to fill vacancies on the Board as they occur and the slate of nominees for election at the annual meeting.

 

5.   Reviewing and making recommendations to the Board with respect to compensation of directors and corporate governance.

 

6.   Recommending members to serve on committees and chairs of the committees of the Board.

 

7.   Reviewing the independence and possible conflicts of interest of directors and executive officers.

 

8.   Overseeing the AEP Corporate Compliance Program.

 

9.   Overseeing the annual evaluation of the Board of Directors.

 

10.   Overseeing the annual evaluation of individual directors.

 

11.   Overseeing the implementation of AEP’s Related Person Transaction Approval Policy.

 

12.   Overseeing AEP’s Sustainability Report, including the material concerning political contributions.

 

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13.   Overseeing elements of the Company’s risks that are within the scope of the Committee’s responsibility as assigned to it by the Board of Directors.

 

A copy of the charter can be found on our website at www.aep.com/investors/corporateleadersandgovernance. Consistent with the rules of the NYSE and our Director Independence Standards, all members of the Committee on Directors and Corporate Governance are independent.

 

The Human Resources Committee (the HR Committee) annually reviews and approves AEP’s executive compensation in the context of the performance of management and the Company. None of the members of the HR Committee is or has been an officer or employee of the Company or any of its subsidiaries. In addition, each of the current members of the HR Committee has been determined to be independent by the Board in accordance with NYSE rules and our Director Independence Standards. In addition, each member is a “non-employee director” as defined in SEC Rule 16b-3 under the Exchange Act and is an “outside director” as defined in Section 162(m) of the Internal Revenue Code.

 

The HR Committee also reviews the Compensation, Discussion and Analysis section of this proxy statement and recommends that it be included in the Company’s Annual Report on Form 10-K.

 

The HR Committee has the responsibilities set forth in its charter, a copy of which can be found on our website at www.aep.com/investors/corporateleadersandgovernance.

 

For a more complete description of the HR Committee’s responsibilities, see the Human Resources Committee Report on page 58.

 

The Audit Committee is responsible for, among other things, the appointment of the independent registered public accounting firm (independent auditor) for the Company; reviewing with the independent auditor the plan and scope of the audit and approving audit fees; monitoring the adequacy of financial reporting and internal control over financial reporting and meeting periodically with the internal auditor and the independent auditor. A more detailed discussion of the purposes, duties and responsibilities of the Audit Committee is found in the Audit Committee charter, a copy of which can be found on our website at www.aep.com/investors/corporateleadersandgovernance. Consistent with the rules of the NYSE and our Director Independence Standards, all members of the Audit Committee are independent. Each Audit Committee member has sufficient knowledge in financial and auditing matters to serve on the Audit Committee. In addition, the Board has determined that all members of the Audit Committee, Messrs. Anderson, Beasley and Nowell and Ms. Goodspeed, Ms. Lin and Ms. Tucker, are “audit committee financial experts” as defined by SEC rules.

 

The Finance Committee monitors and reports to the Board with respect to the capital requirements and financing plans and programs of AEP and its subsidiaries, including reviewing and making recommendations concerning their short and long-term financing plans and programs. The Finance Committee also provides recommendations to the Board on dividend policy, including the declaration and payment of dividends. The Finance Committee also reviews and approves the treasury policies of the Company.

 

The Nuclear Oversight Committee is responsible for overseeing and reporting to the Board with respect to the management and operation of AEP’s nuclear generation.

 

The Policy Committee is responsible for examining AEP’s policies on major public issues affecting the AEP System, including environmental, technology, fuel supply, industry change and other matters.

 

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The Executive Committee is empowered to exercise all the authority of the Board, subject to certain limitations prescribed in the Bylaws, during the intervals between meetings of the Board.

 

The Board’s role in AEP’s risk oversight process

 

The Board has the overall responsibility for overseeing the Company’s management of risks. Management is responsible for identifying and managing the Company’s risks. The Board reviews the Company’s processes for identifying and managing risks and communicating with the Board about those risks to help ensure that the processes are effective.

 

Like other companies, we have very diverse risks. These include financial and accounting risks, capital deployment risks, operational risks, compensation risks, liquidity risks, litigation risks, strategic risks, regulatory risks, reputation risks, natural-disaster risks and technology risks. Some critical risks having enterprise-wide significance, such as corporate strategy and capital budget, require the full Board’s active oversight, but our Board committees also play a key role because they can devote more time to reviewing specific risks. For example, our Nuclear Oversight Committee focuses on the specific risks of operating a nuclear plant. Other committees oversee both specific and broad types of risks. Some of the committees have oversight responsibility for specific risks that are inherent in carrying out their responsibilities set forth in their charters. For example, the Audit Committee is responsible for overseeing financial reporting risks.

 

The Board is responsible for ensuring that these types of risks are properly delegated to the appropriate committee, and that the risk oversight activities are properly coordinated and communicated among the Board and the various committees that oversee the risks. Management prepares and categorizes a list of the Company’s major types of risks. The Audit Committee and the Committee on Directors and Corporate Governance review that list and propose an assignment of risks either to the full Board or to specific committees. The Board reviewed the recommendations and adopted the proposed allocation of responsibilities.

 

Under the NYSE’s listing standards, our Audit Committee must discuss AEP’s policies for risk assessment and risk management. The Audit Committee oversees the process of identifying major enterprise risks and communicates those risks to the Board for assignment of oversight among the Board and the various committees. Our Chief Financial Officer, Chief Risk Officer, Chief Accounting Officer and General Counsel attend the Audit Committee meetings. The Audit Committee oversees the Company’s maintenance of financial and disclosure controls and procedures and also specifically reviews our litigation and regulatory risks as part of their review of the Company’s disclosures.

 

Our Finance Committee broadly oversees our financial risks, which include energy trading risks, liquidity risks and interest rate risks. The Finance Committee reviews and approves the Company’s risk policies relating to our power marketing and hedging activities and also oversees the performance of the assets in our pension plans. Our Chief Financial Officer and General Counsel attend the Finance Committee meetings.

 

Our HR Committee reviews the Company’s incentive compensation practices to ensure they do not encourage excessive risk-taking and are consistent with the Company’s risk tolerance. The HR Committee also oversees our succession planning and executive leadership development. Our Chief Administrative Officer attends the HR Committee meetings.

 

The Committee on Directors and Corporate Governance focuses on corporate governance risks and oversees the Company’s Corporate Compliance Program, which includes the Company’s whistleblower program. Our General Counsel attends the meetings of the Committee on Directors and Corporate Governance.

 

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Compensation Risk

 

As specified in its charter, the HR Committee (with the assistance of its independent compensation consultant and Company management) reviewed the Company’s compensation policies and practices for all employees, including executive officers, and determined that the compensation programs are appropriate and are not reasonably likely to have a material adverse effect on the Company.

 

The Company has designed its executive compensation process, with oversight from the HR Committee, to identify and manage risk and to ensure that its executive compensation programs do not encourage excessive risk taking. The Company provided annual and long-term incentive compensation in amounts that represented approximately 16 percent and 71 percent of our CEO’s total compensation opportunity for 2014, respectively. The HR Committee believes this appropriately allocated the CEO’s compensation among base salary, annual incentive compensation and long-term incentive compensation opportunities in such a way as to not encourage excessive risk-taking. The Company’s incentive compensation also has the following characteristics:

 

   

It is part of a market competitive compensation package that enables the Company to attract, retain and motivate executives with the skills and experience needed to successfully manage the Company, which reduces risk by better ensuring both strong management competence and continuity;

 

   

Incentive award opportunities for all employees are capped, generally at 200 percent of their target. Capping the potential payout limits the extent that employees could potentially profit by taking on excessive risk;

 

   

The HR Committee provides the large majority of incentive compensation to executive officers as long-term stock-based incentive compensation to ensure that short-term performance is not encouraged or rewarded at the expense of long-term performance. This is important primarily because of the large amount of long-term capital investments required in our business;

 

   

Annual incentive compensation funding for nearly all employees, including all executive officers, is based substantially on AEP’s operating earnings per share, which helps ensure that incentive awards are commensurate with the Company’s earnings;

 

   

Annual incentive compensation funding includes safety measures which helps ensure that no employees are encouraged to achieve earnings objectives at the expense of workplace safety;

 

   

The primary metrics used in the Company’s long-term incentive compensation are cumulative operating earnings per share and total shareholder return, which are both robust measures of shareholder value that reduce the risk that employees might be encouraged to pursue other objectives that increase risk or reduce financial performance;

 

   

Annual and long-term incentive compensation programs are reviewed by AEP’s internal audit staff;

 

   

Incentive compensation performance scores are subject to an internal audit, and incentive award payouts to 24 senior officers are subject to the review and approval of the HR Committee; or in the case of the CEO, the independent members of the Board; and these groups may discretionarily reduce or eliminate any payouts;

 

   

Annual and long-term incentive payments and deferrals are subject to the Company’s recoupment of incentive compensation policy (“clawback policy”) as described in the Compensation Discussion and Analysis section on page 55;

 

   

In 2014, AEP granted seventy percent of its long-term incentive awards in the form of performance units with a three-year performance and vesting period, and granted the remain-

 

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ing thirty percent of its long-term incentive awards in the form of restricted stock units that vest over a forty month period which aligns the interests of employees with the long-term interests of shareholders and serves as a retention tool; and

 

   

AEP maintains stock ownership requirements for 47 officers (as of January 31, 2015) as described in Compensation Discussion and Analysis on page 53.

 

Corporate Governance

 

AEP maintains a corporate governance page on its website that includes key information about corporate governance initiatives, including AEP’s Principles of Corporate Governance, AEP’s Principles of Business Conduct, Code of Business Conduct and Ethics for Members of the Board of Directors, Director Independence Standards, and charters for the Audit Committee, the Committee on Directors and Corporate Governance and the HR Committee. The corporate governance page can be found at www.aep.com/investors/corporateleadersandgovernance. Printed copies of all of these materials also are available without charge upon written request to Investor Relations at: AEP, attention: Investor Relations, 1 Riverside Plaza, Columbus, Ohio 43215.

 

AEP’s policies and practices reflect corporate governance initiatives that are designed to comply with SEC rules, the listing requirements of the NYSE and the corporate governance requirements of the Sarbanes-Oxley Act of 2002, including:

 

   

The Board of Directors has adopted corporate governance policies;

 

   

All members but the CEO are independent under the NYSE rules and our Director Independence Standards;

 

   

All members of the Audit Committee, HR Committee and the Committee on Directors and Corporate Governance are independent under applicable rules and regulations;

 

   

The independent members of the Board meet regularly without the presence of management;

 

   

AEP has a code of business conduct that applies to its principal executive officer, principal financial officer and principal accounting officer and will promptly disclose waivers of the code for these officers;

 

   

The charters of the Board committees clearly establish their respective roles and responsibilities; and

 

   

The Board, the Committee on Directors and Corporate Governance, the Audit Committee and the HR Committee conduct annual self-assessments. The Committee on Directors and Corporate Governance also oversees the annual evaluation of the individual directors.

 

Director Qualifications

 

The Company’s Principles of Corporate Governance (Principles) are available on its website at www.aep.com/investors/corporateleadersandgovernance. With respect to director qualifications and attributes, the Principles provide that, in nominating a slate of Directors, it is the Board’s objective, with the assistance of the Committee on Directors and Corporate Governance, to select individuals with skills and experience to effectively oversee management’s operation of the Company’s business.

 

In addition, the Principles provide that directors should possess the highest personal and professional ethics, integrity and values, and be committed to representing the long-term interests of the shareholders, and that directors must also have an inquisitive and objective perspective, practical wisdom and mature judgment.

 

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These requirements are expanded in the Criteria for Evaluating Directors (Criteria), which was initially adopted by the Committee on Directors and Corporate Governance in 2005 and has been subsequently reviewed and refined several times. The Criteria are available on the Company’s website at www.aep.com/investors/corporateleadersandgovernance.

 

As indicated in the Principles and the Criteria, directors should have personal attributes such as high integrity, intelligence, wisdom and judgment. In addition, they should have skills and experience that mesh effectively with the skills and experience of other Board members, so that the talents of all members blend together to be as effective as possible in overseeing a large electric utility business.

 

Board Diversity

 

Our Criteria for Evaluating Directors also includes the Company’s statement regarding how the Board considers diversity in identifying nominees for our Board. The Criteria provide:

 

Two central objectives in selecting board members and continued board service are that the skills, experiences and perspectives of the Board as a whole should be broad and diverse, and that the talents of all members of the Board should blend together to be as effective as possible. In particular, the Board should be balanced by having complementary knowledge, expertise and skill in areas such as business, finance, accounting, marketing, public policy, manufacturing and operations, government, technology, environmental and other areas that the Board has decided are desirable and helpful to fulfilling its role. Diversity in gender, race, age, tenure of board service, geography and background of directors, consistent with the Board’s requirements for knowledge and experience, are desirable in the mix of the Board.

 

Our Committee on Directors and Corporate Governance considers these criteria each year as it determines the slate of director nominees to recommend to the Board for election at our annual meeting. It also considers these criteria each time a new director is recommended for election or appointment to the Board. The Board believes that its implementation of this policy is effective in considering the diversity of the members of the Board.

 

Annual Board Evaluation

 

Each year, an independent, third-party experienced in corporate governance matters interviews each Director to obtain his or her assessment of the effectiveness of the Board and committees, as well as Director performance and Board dynamics, and then, after discussion with the Chair of the Committee on Directors and Corporate Governance, organizes and summarizes issues for discussion with the Board. The Board evaluation includes an assessment of both Board process and substance, including:

 

   

the Board committees and organization of the Board;

 

   

the Board culture and composition;

 

   

the Board’s performance in key areas such as strategy, succession planning and risk oversight; and

 

   

specific issues which should be discussed in the future

 

As part of the interview process, each Director is also asked to provide feedback with respect to the performance of each of the other Directors. This process allows the Committee on Directors and Corporate Governance to fulfill its duties to oversee the evaluation of the qualifications and performance of each incumbent Director. The Board wants to ensure that it remains composed of high-functioning members able to keep their commitments to Board service. Each Director is provided with feedback on his or her individual contribution to the Board and its committees. This annual self-assessment and review supported the Board’s decision to recommend the nomination of each incumbent Director for an additional term.

 

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Selection of Director Candidates

 

The Committee on Directors and Corporate Governance is responsible for recruiting new directors and identifies, evaluates and recommends director candidates to the Board. The Committee regularly assesses the appropriate size and composition of the Board, the needs of the Board and the respective committees of the Board and the qualifications of candidates in light of these needs. Candidates may come to the attention of the Committee through shareholders, management, current members of the Board or search firms. Shareholders who wish to recommend director candidates to the Committee on Directors and Corporate Governance may do so by following the procedures described in Shareholder Proposals and Nominations on page 86.

 

In recruiting and selecting Board candidates, the Committee on Directors and Corporate Governance takes into account the size of the Board and considers a “skills matrix” indicating whether a particular candidate possesses the attributes and one or more of the skill sets described under “Director Qualifications” and “Board Diversity” above, as well as whether those skills and/or other attributes qualify him or her for service on a particular committee. The Committee also considers a wide range of additional factors, including each candidate’s projected retirement date to assist in Board succession planning; other positions the candidate holds, including other boards of directors on which he or she serves; and the independence of each candidate. Typically, the Committee identifies candidates through the use of an outside search firm. The Committee provides the outside search firm the characteristics, skills and experiences that may complement those of the existing members. The outside search firm then provides recommendations for candidates with such attributes and skills. The Committee meets in executive session to discuss potential candidates and determines which candidates to interview.

 

The Committee believes it is important to have a mix of experienced directors with a deep understanding of the Company and others who bring a fresh perspective. In this regard, the Committee has recruited four new directors to the Board over the last three years (25 percent of the current Board) through the rigorous process described above. In our view, the best method to ensure healthy board evolution is through thoughtful consideration of the nomination of directors prior to each election or appointment based on a variety of factors, including director performance, skills and expertise, the Company’s needs and board diversity.

 

Director Independence

 

In accordance with the NYSE standards, a majority of the members of the Board of Directors must qualify as independent directors. Under the NYSE standards, no member of the Board is independent unless the Board affirmatively determines that such member does not have a direct or indirect material relationship with the Company. The Board has adopted categorical standards to assist it in making this determination of director independence (Director Independence Standards). These standards can be found on our web site at www.aep.com/investors/corporateleadersandgovernance.

 

Each year, our directors complete a questionnaire that elicits information to assist the Committee on Directors and Corporate Governance in assessing whether the director meets the NYSE’s independence standards and the Company’s Director Independence Standards. Each director lists all the companies and charitable organizations that he or she, or an immediate family member, has a relationship with as a partner, trustee, director or officer, and indicates whether that entity made or received payments from AEP. The Company reviews its financial records to determine the amounts paid to or received from those entities. A list of the entities and the amounts AEP paid to or received from those entities is provided to the Committee on Directors and Corporate Governance. Utilizing this information, the Committee on Directors and Corporate Governance evaluates, with regard to each director, whether the director has any material relationship with AEP or any of its subsidiaries and also confirms that none of these relationships is advisory in nature. The Com-

 

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mittee on Directors and Corporate Governance determines whether the amount of any payments between those entities and AEP could interfere with a director’s ability to exercise independent judgment. The Committee on Directors and Corporate Governance also reviews any other relevant facts and circumstances regarding the nature of these relationships, to determine whether other factors, regardless of the categorical standards the Board has adopted or under the NYSE’s independence standards, might impede a director’s independence.

 

We are a large electric utility company that operates in parts of eleven different states. Any organization that does business in our service territory is served by one of our subsidiaries. Many of our directors live in our service territory or are executives, directors or trustees of organizations that do business in our service area. Most of those organizations purchase electric service from us. However, there are no unique negotiated rates with any of those organizations. Therefore, the Committee on Directors and Corporate Governance determined that none of those relationships impedes a director’s independence.

 

We make numerous charitable contributions to nonprofit and community organizations and universities in the states where we do business. Again, because many of our directors live in our service territory and are highly accomplished individuals in their communities, our directors are frequently affiliated with many of the same educational institutions, museums, charities and other community organizations. The Committee on Directors and Corporate Governance reviews all charitable contributions made by AEP to organizations with which our directors or their immediate family members are affiliated. The Committee on Directors and Corporate Governance also reviewed contributions made from The American Electric Power Foundation, which was created to support and play an active, positive role in the communities in which we operate by contributing funds to organizations in those communities. The Committee on Directors and Corporate Governance determined that the Company’s contributions were not materially influenced by the director’s relationship with the organization, and therefore none of these relationships conflicts with the interests of the Company or would impair the director’s independence or judgment.

 

The Board’s independence determinations specifically included reviewing the following transactions with Mr. Rasmussen, who is an executive officer of Nationwide Insurance. Nationwide purchases electricity from our subsidiaries (substantially less than one percent of the Company’s gross revenues). In addition, the Company paid an insignificant amount to Nationwide for standard insurance premiums, rent for office space and interest payments on ordinary course debt issued by the Company and its subsidiaries, which was sold through underwriters or brokers (which totaled substantially less than one percent of Nationwide’s gross revenues). The transactions between Nationwide and the Company were in the ordinary course and entered into on an arm’s length basis, and payments were for services that were transactional in nature and did not involve any consulting or advisory work. Therefore, the Board determined that these transactions did not impair the independence of Mr. Rasmussen.

 

As a result of this review, the Board has determined that, other than Mr. Akins, each of the directors and director nominees standing for election, including Messrs. Anderson, Beasley, Crosby, Hoaglin, Notebaert, Nowell, Rasmussen and Richard and Ms. Goodspeed, Ms. Lin and Ms. Tucker, has no material relationship with the Company (either directly or as a partner, stockholder or officer of an organization that has a relationship with the Company) and is independent under the NYSE rules and the Company’s Director Independence Standards.

 

Involvement by Mr. Hoaglin in Certain Legal Proceedings

 

On June 2, 2005, Huntington Bancshares Incorporated (Huntington) announced that the SEC approved a settlement of its previously announced formal investigation into certain financial accounting matters relating to fiscal years 2002 and earlier and certain related disclosure matters. As part of the settlement, the SEC instituted a cease and desist administrative proceeding and entered

 

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a cease and desist order and also filed a civil action in federal district court pursuant to which, without admitting or denying the allegations in the complaint, Huntington and Mr. Hoaglin consented to pay civil money penalties. Without admitting or denying the charges in the administrative proceeding, Mr. Hoaglin agreed to cease and desist from committing and/or causing the violations charged as well as any future violations of these provisions. Additionally, Mr. Hoaglin agreed to pay disgorgement, pre-judgment interest and penalties in the amount of $667,609.

 

Shareholder Nominees for Directors

 

The Committee on Directors and Corporate Governance will consider shareholder recommendations of candidates to be nominated as directors of the Company. All such recommendations must be in writing and submitted in accordance with the procedures described under Shareholder Proposals and Nominations on page 86 and must include information required in AEP’s Policy on Consideration of Candidates for Director Recommended by Shareholders. A copy of this policy is on our website at www.aep.com/investors/corporateleadersandgovernance. Shareholders’ nominees who comply with these procedures will receive the same consideration that all other nominees receive.

 

Board Leadership

 

We believe the Company and its shareholders are best served by a Board that has the flexibility to establish a leadership structure that fits the needs of the Company at a particular point in time. Under the Company’s Principles of Corporate Governance, the Board has the authority to combine or separate the positions of Chairman and CEO, as well as to determine whether, if the positions are separated, the Chairman should be an employee, non-employee or an independent director.

 

The Board believes that the functioning of the Board is currently best served by maintaining a structure of having one individual serve as both Chairman and CEO. The Board believes that having a single person acting in those capacities promotes unified leadership and direction for both the Board and management and also provides a single, clear focus to execute the Company’s strategy especially during this time of significant change in the utility business. However, in certain circumstances, such as the transition from one chief executive officer to another, the Board believes it may be appropriate for the role of Chairman and CEO to be split.

 

Under the Company’s Principles of Corporate Governance, in circumstances where the Chairman of the Board is not independent or where the positions of Chairman and Chief Executive Officer are filled by the same person, the Board considers it useful and appropriate to designate a Lead Director. The Company already has policies and practices in place to provide independent oversight of management and the Company’s strategy. The Board currently includes 11 independent directors among its 12 members. The Board routinely holds executive sessions at which only independent directors are present, and, each year, the independent directors select a Lead Director responsible for facilitating and chairing the independent directors sessions.

 

Mr. Hoaglin has been the Lead Director of the Board since April 2012. The purpose of the Lead Director is to promote the independence of the Board in order to represent the interests of the shareholders. The Lead Director is selected by the independent directors.

 

The Lead Director is responsible for working closely with the CEO to finalize information flow to the Board, set meeting agendas and arrange meeting schedules. He also chairs meetings of the independent directors and serves as principal liaison between the independent directors and management. In addition, Mr. Hoaglin has the ability to call special meetings of the Board, as needed, and also has the authority to retain outside legal counsel or other advisors as needed by the Board. He provides a channel of communication between the directors and management, assures that directors receive timely and necessary information in advance of meetings and receives communications from shareholders on behalf of non-employee directors.

 

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Communicating with the Board

 

Anyone who would like to communicate directly with our Board, our independent directors as a group or our Lead Director, may submit a written communication to American Electric Power Company, Inc., P.O. Box 163609, Attention: AEP Independent Directors, Columbus, Ohio 43216. The Company’s Corporate Secretary reviews such inquiries or communications, and communications other than advertising or promotions of a product or service are forwarded to our Board, our independent directors as a group or our Lead Director, as appropriate.

 

Transactions with Related Persons

 

The American Electric Power Company, Inc. Related Person Transaction Approval Policy (Policy) was adopted by the Board in December 2006. The written Policy is administered by the Committee on Directors and Corporate Governance. A copy of the Policy is available on our website at www.aep.com/investors/corporateleadersandgovernance.

 

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

 

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

 

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

 

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

 

Since January 1, 2014, there have been no transactions and there are no currently proposed transactions, involving an amount exceeding $120,000 in which AEP was or is expected to be a participant and in which any Related Person had a direct or indirect material interest.

 

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Director Compensation

 

Directors who are employees of the Company receive no additional compensation for service as a director other than accidental insurance coverage. The table below shows the elements and amount of compensation that we paid to our non-employee directors for 2014.

 

Compensation Element


   Until
October 1, 2014


     On and After
October 1, 2014


 

Annual Retainer (1)

   $ 97,000       $ 100,000   

Annual Stock Unit Awards (2)

     145,000         150,000   

Committee Chair Annual Retainers (1):

                 

Audit Committee

     20,000         25,000   

HR Committee

     20,000         20,000   

Audit Committee Member Annual Retainers (1)

     15,000         15,000   

HR Committee Member Annual Retainers (1)

     10,000         10,000   

Lead Director Annual Retainer (1)

     30,000         30,000   

(1)   Retainer amounts are paid in cash in quarterly installments.
(2)   In 2014, pursuant to the Stock Unit Accumulation Plan for Non-Employee Directors, each non-employee director serving a full year was awarded $146,250 in AEP stock units. These AEP stock units are credited to directors quarterly, based on the closing price of AEP Common Stock on the payment date. Amounts equivalent to cash dividends on the AEP stock units accrue as additional AEP stock units. AEP stock units are paid to each non-employee director in cash shortly after termination of service unless the director has elected to further defer payment.

 

The Board has determined that Board compensation should consist of a mix of cash and AEP stock units. In September 2014, upon the recommendation of the Committee on Directors and Corporate Governance and taking into account comparative data from Meridian Compensation Partners, LLC, an outside independent consultant (“Meridian”), the Board determined that effective October 1, 2014, (i) the amount of AEP stock units awarded to non-employee directors pursuant to the Stock Unit Accumulation Plan should increase from $145,000 annually to $150,000 annually, (ii) the amount of the annual cash retainer paid to non-employee directors should increase from $97,000 annually to $100,000 annually and (iii) the amount of the annual cash retainer for the Audit Committee Chair should be increased from $20,000 annually to $25,000 annually.

 

The Board believes that the director compensation set forth above compensates directors appropriately for all general services that are rendered as a director, committee member, committee chair or as Lead Director, including education and training appropriate to the director’s responsibilities. The Company believes, however, that special compensation can be appropriate when individual directors are asked to undertake special assignments requiring a significant amount of additional time, effort and responsibility. The Board’s Special Compensation Policy provides for directors to be compensated at a daily rate when called upon to undertake special additional services beyond those contemplated by the Annual Retainer. Under the Special Compensation Policy, the Committee on Directors and Corporate Governance determines (a) the amount of any special compensation in light of the actual or anticipated time, effort and responsibility required of the director and (b) the form of special compensation, which may include a per diem fee, an hourly fee, a flat fee or any other reasonable payment or payments. No special compensation was paid for services provided in 2014.

 

Expenses.    Directors are reimbursed for expenses incurred in attending Board, committee and shareholder meetings. Directors are also reimbursed for reasonable expenses associated with other business activities that benefit the Company, including participation in director education programs.

 

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Spouses may occasionally join directors on Company aircraft when a director is traveling to or from Board meetings or other business activities. The Company generally provides for, or reimburses the expenses of, the directors and their spouses for attendance at such meetings. The Board does not provide tax gross-ups on any director perquisites.

 

Retainer Deferral Plan.    The Retainer Deferral Plan for Non-Employee Directors is a non-qualified deferred compensation plan that permits non-employee directors to choose to defer up to 100 percent of their annual cash retainer and fees into a variety of investment fund options, all with market-based returns, including an AEP stock fund. The Plan permits the non-employee directors to defer receipt until termination of service or for a period that results in payment commencing not later than five years after termination of service.

 

Insurance.    AEP maintains a group 24-hour accident insurance policy to provide a $1,000,000 accidental death benefit for each director, $100,000 for each spouse of a director and $50,000 for all dependent children. The current policy, effective September 1, 2012 to September 1, 2015, has a premium of $28,905.

 

Stock Ownership.    Non-employee directors are required by our Corporate Governance Principles to own AEP common stock or AEP stock units worth five times their annual equity award, which is met within the first five years of a non-employee director’s term by requiring the director to hold the AEP stock units awarded under the Stock Unit Accumulation Plan. Each non-employee director is required to hold these stock units until termination of service.

 

After five years of service on the Board, non-employee directors receive contributions to an AEP stock fund under the Stock Unit Accumulation Plan. During open trading windows they may subsequently transfer those amounts into other investment fund options, similar to those in the Retainer Deferral Plan.

 

Matching Gifts Program.    Directors may participate in our Matching Gifts Program on the same terms as AEP employees. Under the program, AEP will match between $250 and $1,000 per higher education institution each year in charitable contributions from a director.

 

Charitable Award Program.    AEP is continuing a memorial gift program for former Central and South West Corporation directors and executive officers who had been previously participating in this program. The program currently has 26 participants, including Dr. Sandor. Under this program, AEP makes donations in a director’s name to up to three charitable organizations in an aggregate amount of up to $500,000, payable by AEP upon such person’s death. AEP maintains corporate-owned life insurance policies to support portions of the program. AEP paid an annual premium of $116,383 on those policies for 2014.

 

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2014 Director Compensation Table

 

The following table presents the compensation provided by the Company in 2014 to our non-employee directors.

 

Name


   Fees
Earned
Or
Paid in
Cash ($)


     Stock
Awards
($)
(2)(3)


     All Other
Compensation
($)
(4)


     Total
($)


 

David. J. Anderson

     112,750         146,250         642         259,642   

J. Barnie Beasley, Jr.(1)

     103,426         134,179         642         238,247   

Ralph D. Crosby, Jr.  

     127,750         146,250         642         274,642   

Linda A. Goodspeed

     112,750         146,250         642         259,642   

Thomas E. Hoaglin

     137,750         146,250         642         284,642   

Sandra Beach Lin

     112,750         146,250         642         259,642   

Michael G. Morris(1)

     30,119         45,023         642         75,784   

Richard C. Notebaert

     107,750         146,250         642         254,642   

Lionel L. Nowell III

     134,000         146,250         1,392         281,642   

Stephen S. Rasmussen

     105,250         146,250         642         252,142   

Oliver G. Richard III

     107,750         146,250         642         254,642   

Richard L. Sandor(1)

     30,119         45,023         5,118         80,260   

Sara M. Tucker

     112,750         146,250         1,642         260,642   

John F. Turner(1)

     34,777         45,023         642         80,442   

(1)   Mr. Beasley was appointed a director in February 2014. Messrs. Morris’, Sandor’s and Turner’s terms as a director ended effective as of April 22, 2014, the date of our 2014 Annual Meeting.
(2)   The dollar amounts reported represent the grant date fair value calculated in accordance with FASB ASC Topic 718 of AEP stock units granted under the Stock Unit Accumulation Plan for Non-Employee Directors, without taking into account estimated forfeitures. AEP stock units are credited to directors quarterly.
(3)   Each non-employee director who served the full year received 2,677.446 AEP stock units in 2014. Due to their service for less than a full year, Messrs. Morris, Sandor and Turner each received 878.592 AEP stock units, and Mr. Beasley received 2,439.166 AEP stock units. The current directors had the following aggregate number of AEP stock units at 2014 year-end: Mr. Anderson (12,430), Mr. Beasley, (2,471) Mr. Crosby (33,266), Ms. Goodspeed (34,069), Mr. Hoaglin (27,285), Ms. Lin (7,635), Mr. Notebaert (12,430), Mr. Nowell (37,965), Mr. Rasmussen (7,087), Mr. Richard (5,936) and Ms. Tucker (23,025).
(4)   The amounts reported in All Other Compensation consists of (a) a premium of $642 for accidental death insurance policy, (b) matching gift contributions of $750 for Mr. Nowell and $1,000 for Ms. Tucker and (c) an amount of $4,476 for Dr. Sandor’s participation in the Central and South West Corporation Memorial Gift Program.

 

Insurance

 

AEP and the AEP System Companies and their directors and officers are insured, subject to certain exclusions and deductibles, against losses resulting from any claim or claims made against them while acting in their capacities as directors and officers. Such insurance, effective March 15, 2014 to March 15, 2015, is provided by: Associated Electric & Gas Insurance Services Ltd., Energy Insurance Mutual Ltd., Zurich American Insurance Company, U.S. Specialty Insurance Company, Arch Insurance Company, Travelers Casualty and Surety Co. of America, Westchester Fire Insurance Company (ACE), Berkley Insurance Co., RSUI Insurance Company, Alterra America Insurance Company, Scottsdale Indemnity Company (Freedom Specialty), Arch Insurance Co., Illinois National Fire Insurance Company (AIG), Allied World Assurance Company Ltd. (AWAC), Liberty Mutual Insurance Company, Endurance Risk Solutions Assurance Co., Catlin Specialty Insurance Company (Catlin, Inc.) and ACE Bermuda LTD. The total cost of this insurance is $3,281,062.

 

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Fiduciary liability insurance provides coverage for AEP System companies and their affiliated trusts, their directors and officers, and any employee deemed to be a fiduciary or trustee, for breach of fiduciary responsibility, obligation, or duties as imposed under the Employee Retirement Income Security Act of 1974. Such insurance, effective March 15, 2014 to March 15, 2015, is provided by U.S. Specialty Insurance Company, XL Specialty Insurance Co., Energy Insurance Mutual Ltd., and Scottsdale Indemnity Company (Freedom Specialty). The total cost of this insurance is $561,320.

 

Item 2. Proposal to Ratify Appointment of Independent Registered Public Accounting Firm

 

The Audit Committee is responsible for the appointment, fees and oversight of the Company’s independent registered public accounting firm. The Audit Committee has appointed the firm of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for 2015. The Audit Committee reviews and assesses annually the qualifications and performance of the independent registered public accounting firm and considers, as appropriate, the rotation of the independent registered public accounting firm. Additionally, the Audit Committee is involved in the selection and mandated rotation of the lead engagement partner from Deloitte & Touche LLP. The Audit Committee believes that the continued retention of Deloitte & Touche LLP as our independent registered public accounting firm is in the best interest of the Company and our shareholders, and we are asking our shareholders to ratify the selection of Deloitte & Touche LLP as our independent registered public accounting firm for 2015. Although action by the shareholders in this matter is not required, the Audit Committee believes that it is appropriate to seek shareholder ratification of this appointment in light of the critical role played by the independent registered public accounting firm in maintaining the integrity of the Company’s financial controls and reporting, and will seriously consider shareholder input on this issue. Whether or not the appointment of Deloitte & Touche LLP is ratified by the shareholders, the Audit Committee may, in its discretion, change the appointment at any time during the year if it determines that such change would be in the best interests of the Company and its shareholders.

 

One or more representatives of Deloitte & Touche LLP will be in attendance at the annual meeting on April 21, 2015. The representatives will have the opportunity to make a statement, if desired, and will be available to respond to appropriate questions from shareholders.

 

Vote Required.

 

Approval of this proposal requires the affirmative vote of holders of a majority of the votes cast at the meeting.

 

Your Board of Directors recommends a vote FOR this Item 2.

 

Audit and Non-Audit Fees

 

The following table presents fees for professional audit services rendered by Deloitte & Touche LLP for the audit of the Company’s annual financial statements for the years ended December 31, 2014 and December 31, 2013, and fees billed for other services rendered by Deloitte & Touche LLP during those periods.

 

     2014

     2013

 

Audit Fees(1)

   $ 11,689,000       $ 12,344,000   

Audit-Related Fees(2)

   $ 781,000       $ 706,000   

Tax Fees(3)

   $ 137,000       $ 587,000   
    


  


TOTAL

   $ 12,607,000       $ 13,637,000   
    


  


 

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(1)   Audit fees in 2013 and 2014 consisted primarily of fees related to the audit of the Company’s annual consolidated financial statements, including each registrant subsidiary. Audit fees also included auditing procedures performed in accordance with Sarbanes-Oxley Act Section 404 and the related Public Company Accounting Oversight Board Auditing Standard Number 5 regarding the Company’s internal control over financial reporting. This category also includes work generally only the independent registered public accounting firm can reasonably be expected to provide.
(2)   Audit-related fees consisted principally of regulatory, statutory and employee benefit plan audits.
(3)   Tax fees consisted principally of advisory services. Tax services are rendered based upon facts already in existence, transactions that have already occurred, as well as tax consequences of proposed transactions.

 

The Audit Committee has considered whether the provision of services other than audit services by Deloitte & Touche LLP and its domestic and global affiliates is compatible with maintaining independence, and the Audit Committee believes that this provision of services is compatible with maintaining Deloitte & Touche LLP’s independence.

 

Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Registered Public Accounting Firm

 

The Audit Committee’s policy is to pre-approve all services provided by the independent registered public accounting firm. These services may include audit services, audit-related services, tax services and other services. Pre-approval is provided for up to one year and any pre-approval is detailed as to the particular service or category of services and is subject to a specific limitation. The independent registered public accounting firm and management are required to report to the Audit Committee at each regular meeting regarding the extent of services provided by the independent registered public accounting firm in accordance with this pre-approval policy, and the fees for the services performed to date. The Audit Committee Chairman may also pre-approve particular services on a case-by-case basis. In 2014, all Deloitte & Touche LLP services were pre-approved by the Audit Committee in accordance with this policy.

 

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Audit Committee Report

 

The Audit Committee reviews AEP’s financial reporting process as well as the internal control over financial reporting on behalf of the Board. Management has the primary responsibility for the financial statements and the reporting process, including the system of internal control over financial reporting.

 

The Audit Committee met seven times during the year and held discussions, some of which were in private, with management, the internal auditor, and the independent registered public accounting firm. Management represented to the Audit Committee that AEP’s consolidated financial statements were prepared in accordance with generally accepted accounting principles. Management has also concluded that the Company’s internal control over financial reporting was effective as of December 31, 2014. The Audit Committee has reviewed and discussed the audited consolidated financial statements and internal control over financial reporting with management, the internal auditor and the independent registered public accounting firm. The Audit Committee discussed with the independent registered public accounting firm the matters required to be discussed by the Public Company Accounting Oversight Board (PCAOB).

 

In addition, the Audit Committee had discussions with and received written communications from the independent registered public accounting firm regarding its independence as required by the PCAOB. The Audit Committee has also received written communication regarding the results of the independent registered public accounting firm’s internal quality control reviews and procedures and other matters, as required by the New York Stock Exchange listing standards.

 

In reliance on the reviews, communications and discussions referred to above, the Audit Committee recommended to the Board that the audited financial statements be included in AEP’s Annual Report on Form 10-K for the year ended December 31, 2014, for filing with the SEC.

 

Audit Committee Members

Lionel L. Nowell, III, Chair

David J. Anderson

J. Barnie Beasley, Jr.

Linda A. Goodspeed

Sandra Beach Lin

Sara Martinez Tucker

 

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Item 3. Advisory Vote on Executive Compensation

 

In accordance with the requirements of Section 14A of the Securities Exchange Act, we are including in these proxy materials a separate resolution for shareholders to vote upon, on an advisory (non-binding) basis, the compensation paid to our named executive officers as disclosed in this proxy statement in accordance with the SEC’s rules.

 

As described in detail under the heading “Compensation Discussion and Analysis,” our executive compensation programs are designed to attract, motivate, and retain our named executive officers who are critical to our success. Under these programs, our named executive officers are rewarded for the achievement of annual and long-term goals. Please read the “Compensation Discussion and Analysisbeginning on page 40 for additional details about the 2014 compensation of our named executive officers.

 

The HR Committee continually reviews the compensation programs for our named executive officers to ensure they achieve the desired goals of aligning our executive compensation structure with our shareholders’ interests and current market practices. As a result of its review process, the HR Committee maintains the following executive compensation practices:

 

   

Emphasizing long-term incentive compensation to promote the longer-term interests of the Company and encourage management to make decisions that are aligned with shareholders’ interests;

 

   

Tying the value of a substantial portion (70 percent) of this long-term compensation to two robust measures of shareholder value:

 

   

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

 

   

Three year cumulative operating earnings per share compared to a Board approved objective;

 

   

Maintaining a clawback policy that allows the Board to recoup any excess incentive compensation paid to our named executive officers and other key members of our executive team if the financial results on which the awards were based are materially restated due to misconduct of the executive.

 

We are asking our shareholders to indicate their support for our named executive officer compensation as described in this proxy statement. This proposal, commonly known as a “say-on-pay” proposal, gives our shareholders the opportunity to express their views on our named executive officers’ compensation. This advisory vote is not intended to address any specific item of compensation, but rather the overall compensation of our named executive officers and the philosophy, policies and practices described in this proxy statement. Accordingly, we ask our shareholders to vote “FOR” the following resolution at the Annual Meeting:

 

“RESOLVED, that the compensation paid to the Company’s named executive officers, as disclosed in the Company’s Proxy Statement for the 2015 Annual Meeting of Shareholders pursuant to rules of the SEC, including the Compensation Discussion and Analysis, compensation tables and related narrative disclosure is hereby APPROVED.”

 

While the Board intends to consider carefully the results of this vote, the say-on-pay vote is advisory only, and therefore will not be binding on the Company or our Board of Directors.

 

Vote Required.

 

Approval of this proposal requires the affirmative vote of holders of a majority of the votes cast at the meeting.

 

Your Board of Directors recommends a vote FOR this Item 3.

 

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Item 4: Proposal to Approve The American Electric Power System 2015 Long-Term Incentive Plan

 

The Board is requesting that shareholders vote in favor of adopting the American Electric Power System 2015 Long-Term Incentive Plan (the “2015 Plan”), which was approved by the Board of Directors on February 24, 2015, subject to shareholder approval. The 2015 Plan has been established to replace, on a prospective basis, the Amended and Restated American Electric Power System Long-Tern Incentive Plan (the “Prior Plan”), which was previously approved by shareholders and expires on April 26, 2020. If approved by shareholders, the 2015 Plan will become effective as of April 21, 2015 and will replace the Prior Plan for any new grants made after April 21, 2015. Any awards previously granted under the Prior Plan will continue to vest and/or be exercisable in accordance with their original terms and conditions. If shareholders do not approve the 2015 Plan, it will not be adopted and no grants will be made under it.

 

Subject to adjustment upon the occurrence of various corporate events as described in the proposed 2015 Plan, the maximum number of shares requested for shareholder approval under the proposed 2015 Plan is 10,000,000 shares. If the proposed 2015 Plan is approved by shareholders, based on its historic grant practices, the Company anticipates that the requested share authorization under the proposed 2015 Plan will last for a significant portion of its ten-year term.

 

The proposed 2015 Plan is intended to develop employees’ sense of proprietorship and personal involvement in the development and financial success of the Company, thereby advancing the interests of the Company and its shareholders. In order to build a stable and experienced management team, the Company seeks to maintain and strengthen these individuals’ desire to remain with the Company as well as to attract individuals to become employees. As with the Prior Plan, the ultimate goal of the 2015 Plan is to encourage those individuals who are and will be responsible for the Company’s future growth and continued success to have a greater personal financial investment in the Company through ownership of our Common Stock.

 

In addition, as with the Prior Plan, the Company’s Board of Directors has determined that it would be in the Company’s best interests to preserve the HR Committee’s flexibility under the 2015 Plan to grant certain performance awards that are intended to qualify for the “qualified performance-based compensation” exception from the $1 million limit on deductibility of compensation paid to each of the chief executive officer and the other three most highly compensated executive officers (other than the chief financial officer) imposed by Section 162(m) of the IRC (“Section 162(m)”). In approving the 2015 Plan, shareholders will also be approving the material terms of the performance goals under the 2015 Plan that are intended to qualify certain performance awards under the 2015 Plan for the “qualified performance-based compensation” exception under Section 162(m). Section 162(m) requires shareholder re-approval of the material terms of the performance goals under the 2015 Plan every five years. Accordingly, if shareholders approve the 2015 Plan, shareholders will need to re-approve the material terms of the performance goals under the plan no later than the Company’s annual meeting of shareholders in 2020 in order to preserve the HR Committee’s flexibility to grant awards intended to constitute qualified performance-based compensation under Section 162(m) after the Company’s annual meeting of shareholders in 2020. In addition, notwithstanding shareholders’ approval of the 2015 Plan, no assurance can be given that awards under the 2015 Plan intended by the HR Committee to satisfy the requirements for qualified performance-based compensation under Section 162(m) will in fact do so. Furthermore, even if the 2015 Plan is approved by shareholders, the HR Committee may still grant awards that are not intended to constitute qualified performance-based compensation under Section 162(m) if the HR Committee determines that granting such awards is in the best interests of the Company.

 

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Key Features of The Plan

 

The 2015 Plan retains many of the features of the Prior Plan in addition to including updates of certain provisions. As with the Prior Plan, all awards for employees can only be made pursuant to the authority of the HR Committee, and with respect to awards to non-employee directors, all awards can only be made pursuant to the authority of the Board.

 

Key features of the 2015 Plan are described below but are qualified in their entirety by reference to the full text of the 2015 Plan attached as Exhibit B to this proxy statement.

 

   

Subject to adjustment upon the occurrence of various corporate events as described in the 2015 Plan, the maximum number of shares that may be granted under the 2015 Plan is 10,000,000 shares.

 

   

This share request will result in overall dilution of 2.0 percent, assuming all the available shares are issued. An analysis of similar utility companies indicates this is below the industry median. The analysis also showed that AEP’s three-year average grant history of 0.3 percent of outstanding shares annually has been well below the industry median.

 

   

The maximum aggregate value of awards that may be granted to any non-employee member of our Board of Directors during any calendar year is $700,000.

 

   

Any shares related to awards under the 2015 Plan that terminate by expiration, forfeiture, cancellation, or otherwise without the issuance of such shares, are settled in cash in lieu of shares, or are exchanged with the HR Committee’s permission, prior to the issuance of shares, for awards not involving shares, shall be available again for grants under the 2015 Plan.

 

   

Shares subject to an award under the 2015 Plan will not again be available for issuance under the 2015 Plan if the shares are (i) shares tendered or withheld in payment of the exercise price of an option, (ii) shares delivered to or withheld by the Company to satisfy any tax withholding liabilities, or (iii) shares covered by a stock-settled stock appreciation right that were not issued upon the settlement of the stock appreciation right.

 

   

Awards may include stock options (including ISOs and nonqualified stock options (“NQSOs”)), stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares, cash-based awards and other stock-based awards.

 

   

Shares issued pursuant to “Full Value Awards” (awards other than stock options or stock appreciation rights, e.g., restricted stock, restricted stock units, performance shares, performance units if settled with stock, or other stock-based awards) shall reduce the 2015 Plan’s share authorization at a rate of 1 to 1, while shares that are covered by stock option or stock appreciation rights shall reduce the 2015 Plan’s share authorization at a rate of 0.286 to 1.

 

   

Unless the Company obtains prior shareholder approval, the 2015 Plan does not allow reloads, repricing, or exchanges of stock options or stock appreciation rights for cash (other than in connection with a change of control of the Company), stock options to be issued at a discount to fair market value, or stock options or stock appreciation rights to be transferred by a participant for consideration.

 

   

Awards granted under the 2015 Plan are subject to “clawback” in certain circumstances under the Company’s compensation recoupment policy as such policy is in effect from time to time.

 

   

The exercise price of options and the grant price of stock appreciation rights must be at least equal to 100 percent of the fair market value of the shares as determined on the date of the grant.

 

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The maximum term of options and stock appreciation rights is 10 years.

 

   

The HR Committee may provide in an option award agreement or in a stock appreciation right agreement (as applicable), that if, on the last day of the term of the option or the stock appreciation right, the fair market value of one share exceeds the exercise price per share of the option or the grant price per share of the stock appreciation right (as applicable), and the holder of the option or stock appreciation right has not exercised the option or the stock appreciation right and it has not otherwise expired, the option or stock appreciation right will be deemed to have been exercised by its holder on such day.

 

   

The HR Committee may grant dividend equivalents based on the dividends declared on shares that are subject to any Full Value Award; provided that the dividend equivalents will be subject to any performance conditions that apply to the underlying award. Dividends or dividend equivalents will not accrue, be granted or be paid with respect to shares that are subject to an outstanding option or stock appreciation right.

 

   

Annual award limits set forth in the 2015 Plan are as follows:

 

Award(s)


  

Annual Limit


Stock Options

  

2,000,000 shares

Stock Appreciation Rights

  

2,000,000 shares

Restricted Stock or Restricted Stock Units

  

400,000 shares

Performance Units or Performance Shares

   Value of 400,000 shares or 400,000 shares (each measured at target); up to 2 shares (or the cash value of 2 shares) may be issued for each performance share or performance share unit based on performance (including any applicable dividend equivalent)

Cash-Based Awards

  

$15 million

Other Stock-Based Awards

  

400,000 shares

 

   

The performance goals upon which the payment or vesting of an award that is intended to constitute qualified performance-based compensation under Section 162(m) are limited to certain performance measures as listed below and as set forth in the 2015 Plan:

 

   

earnings measures (including, for example, primary earnings per share, fully diluted earnings per share, operating earnings per share, net income, pre-tax income, operating income, earnings before interest, taxes, depreciation and amortization or any combination thereof, and net operating profits after taxes);

 

   

expense control (including, for example, operations & maintenance expense, total expenditures, expense ratios, and expense reduction);

 

   

customer measures (including, for example, customer satisfaction, service cost, service levels, responsiveness, bad debt collections or losses, and reliability—such as outage frequency, outage duration, and frequency of momentary outages);

 

   

safety measures (including, for example, recordable case rate, severity rate, fatalities and vehicle accident rate);

 

   

diversity measures (including, for example, female and minority placement utilization rates);

 

   

environmental measures (including, for example, emissions, project completion milestones, regulatory/legislative/cost recovery goals, and notices of violation);

 

   

revenue measures (including, for example, revenue, direct margin and net margin);

 

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shareholder return measures (including, for example, total shareholder return, economic value added, cumulative shareholder value added, return on equity, return on capital, return on assets, dividend payout ratio and cash flow(s)—such as operating cash flows, free cash flow, discounted cash flow return on investment and cash flow in excess of cost of capital or any combination thereof);

 

   

valuation measures (including, for example, stock price increase, price to book value ratio, and price to earnings ratio);

 

   

capital and risk measures (including, for example, debt to equity ratio, dividend payout as percentage of net income and diversification of business opportunities);

 

   

employee satisfaction and engagement;

 

   

project measures (including, for example, completion of key milestones);

 

   

production measures (including, for example, generating capacity factor, performance against the Institute of Nuclear Power Operation index, generating equivalent availability, heat rates, effective forced outage rates and production cost); and

 

   

such other individual performance objective that is measured solely in terms of quantitative targets related to AEP or any subsidiary or AEP’s or any such subsidiary’s business.

 

The HR Committee will determine whether the performance targets or goals that have been chosen for a particular performance award have been met and may provide in an award when the award is established that any performance measure may be made subject to pre-specified adjustments to remove the effects of restructurings, dispositions, changes in tax or accounting rules, or similar non-recurring or extraordinary events to the extent consistent with the requirements of Code Section 162(m).

 

Awards that are intended to constitute qualified performance-based compensation under Section 162(m) may not be adjusted upward, but the HR Committee has the discretion to adjust these awards downward. The HR Committee has the discretion to grant awards that do not qualify for the performance-based compensation exception under Section 162(m). Generally, awards may be paid in the form of cash, shares of common stock, or in any combination, as determined by the HR Committee.

 

Administration

 

The 2015 Plan will be administered by the HR Committee. The HR Committee will have full and exclusive discretionary authority, subject to the provisions of the 2015 Plan, to establish rules and regulations necessary for the proper administration of the 2015 Plan. All actions taken and all interpretations and determinations made by the HR Committee shall be final and binding.

 

Eligibility

 

Employees and non-employee directors of the Company or any of its subsidiaries or affiliates are eligible to receive awards under the 2015 Plan. From time to time, the HR Committee (or as to non-employee directors, the Board) will determine who will be granted awards.

 

While all employees are eligible to receive awards under the 2015 Plan, the HR Committee currently expects that approximately 950 employees will initially participate in the 2015 Plan.

 

Change of Control

 

Under the 2015 Plan, the HR Committee may provide for the effect of a change in control of the Company (as defined in the 2015 Plan) upon an award granted under the Plan. Such provisions may include:

 

   

The acceleration or extension of time periods for purposes of exercising, vesting in, or realizing gain from an award;

 

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The waiver or modification of performance or other conditions related to payment or other rights under an award;

 

   

Providing for the early settlement of an award for an equivalent cash value; or

 

   

Such other modification or adjustment to an award as the HR Committee deems appropriate.

 

Termination of Employment

 

Under the 2015 Plan, the HR Committee will determine and provide in the applicable award agreement the effect, if any, on an award of the occurrence of the award holder’s termination of employment from the Company.

 

Amendment and Termination of the 2015 Plan

 

The HR Committee may, at any time and from time to time, alter, amend, modify, suspend, or terminate the 2015 Plan and any award agreement in whole or in part; except that, without the prior approval of the Company’s shareholders and except as permitted under the 2015 Plan’s adjustment provision, options or SARs awarded under the 2015 Plan will not be repriced, replaced, or regranted through cancellation, or by lowering the exercise price of a previously granted option or the grant price of a previously granted SAR, or exchanged for a cash payment or other awards (other than in connection with a change of control of the Company) and no material amendment of the 2015 Plan will be made without shareholder approval if shareholder approval is required by law, regulation, or a stock exchange rule.

 

Other than as described in the following sentence, no termination, amendment, suspension, or modification of the 2015 Plan or an award agreement will adversely affect in any material way any award previously granted under the 2015 Plan, without the written consent of the holder of the award. The Board of Directors may amend the 2015 Plan or an award agreement, to take effect retroactively or otherwise, as deemed necessary or advisable for the purpose of conforming the 2015 Plan or an award agreement to any present or future law that relates to the 2015 Plan (including, but not limited to, Section 409A of the Internal Revenue Code), and to the administrative regulations and rulings promulgated thereunder.

 

Unless terminated earlier by the HR Committee, the 2015 Plan will terminate on April 21, 2025.

 

Recoupment of Incentive Compensation

 

All awards are subject to the Company’s compensation recoupment policy as such policy may be in effect from time to time.

 

Federal Income Tax Consequences

 

The following is a general description of the current federal income tax consequences to participants and AEP relating to awards that may be granted under the 2015 Plan based on present tax law. This summary does not purport to cover all federal employment tax or other federal tax consequences that may be associated with the 2015 Plan, nor does it cover state, local, or non-U.S. taxes. Pursuant to SEC disclosure requirements, this summary includes a description of the federal income tax consequences of the issuance and exercise of stock options, as well as other awards that may be granted under the 2015 Plan. We note, however, that the Company has not issued stock options since 2006.

 

A participant will not recognize income upon the grant of a nonqualified stock option to purchase shares of Common Stock. Upon exercise of the option, the participant will recognize ordinary compensation income equal to the excess of the fair market value of the shares of Common

 

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Stock on the date the option is exercised over the exercise price for such shares. AEP will be entitled to a deduction equal to the amount of ordinary compensation income recognized by the participant. The deduction will be allowed at the same time that the participant recognizes the income.

 

A participant will not recognize income upon the grant of an incentive stock option to purchase shares of Common Stock and will not recognize income upon exercise of the option, provided the participant was an employee of the AEP System at all times from the date of grant until three months prior to exercise. Where a participant who has exercised an incentive stock option sells the shares of Common Stock acquired upon exercise more than two years after the grant date and more than one year after exercise, capital gain or loss will be recognized equal to the difference between the sales price and the exercise price. A participant who sells such shares of Common Stock within two years after the grant date or within one year after exercise will recognize ordinary compensation income in an amount equal to the lesser of the difference between (i) the exercise price and the fair market value of such shares on the date of exercise, or (ii) the exercise price and the sales proceeds. Any remaining gain or loss will be treated as a capital gain or loss. AEP will be entitled to a deduction equal to the amount of ordinary compensation income recognized by the participant in this case. The deduction will be allowable at the same time that the participant recognizes the income.

 

Except as otherwise specified under Section 409A of the Internal Revenue Code, the current federal income tax consequences of other awards authorized under the 2015 Plan are generally as follows: stock appreciation rights are subject to taxation to the participant (and deduction by AEP) upon exercise in an amount equal to the appreciation inherent in the value of the underlying shares; restricted stock subject to a substantial risk of forfeiture results in income recognition equal to the excess of the fair market value of the shares of Common Stock over the purchase price (if any) at the time the restrictions lapse (unless the recipient elects to accelerate recognition as of the date of grant); performance awards and dividend equivalents are generally subject to tax at the time of payment. In each of the foregoing cases, AEP will generally have a corresponding deduction at the same time that the participant recognizes income.

 

Section 409A of the Internal Revenue Code provides that participants in a covered nonqualified deferred compensation arrangement will be subject to accelerated taxation and penalties unless the covered plan, both as designed and administered, satisfies specified requirements, including limitations on the timing of deferral and distributions elections, if any, and triggers for the distribution or funding of deferred amounts. Code Section 409A may become applicable to certain types of awards under the 2015 Plan (other than incentive stock options and restricted stock) depending on the terms and conditions to which the award is subject. The Company believes that the terms of the 2015 Plan, as such, should not cause awards under the 2015 Plan to violate the requirements of Code Section 409A.

 

New Plan Benefits

 

All awards to employees and officers under the 2015 Plan will be made at the discretion of the HR Committee. Therefore, it is not possible to determine the amount or form of any award that will be granted to any employee or officer or the average annual equity grant rate in the future, as there are many variables the HR Committee considers in granting equity awards, including compensation of our executive officers compared to the Compensation Peer Group, share price at the time the HR Committee sets executive compensation and, for payouts under our long-term incentive program, performance against pre-determined metrics at the time of settlement. We currently grant awards to our non-employee directors under the Stock Unit Accumulation Plan, which will not be a part of the 2015 Plan. For information about grants made to non-employee directors, see “Director Compensation” on page 18.

 

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Although future grants under the 2015 Plan are not determinable at this time, for illustrative purposes and not necessarily indicative of the shares that might be awarded in the future under the 2015 Plan, the table below sets forth certain information about performance units and restricted stock units that were granted for 2014. No stock options were granted.

 

2014 Equity-Based Incentive Award Grants Under The Prior Plan

 

     2014-2016 Performance Units(1)

     Restricted Stock Units(2)

 

Name and Position


   Target
Number of
Units


     Grant Date
Fair Value


     Number of
Units


     Grant Date
Fair Value


 

Nicholas K. Akins,

                                   

Chairman and Chief Executive Officer

     101,907       $ 4,704,027         43,674       $ 2,015,992   

Brian X. Tierney,

                                   

Executive Vice President and Chief Financial Officer

     28,529       $ 1,316,899         12,226       $ 564,352   

Robert P. Powers,

                                   

Executive Vice President and Chief Operating Officer

     28,529       $ 1,316,899         12,226       $ 564,352   

David M. Feinberg,

                                   

Executive Vice President, General Counsel and Secretary

     14,596       $ 673,751         6,255       $ 288,731   

Lana L. Hillebrand,

                                   

Senior Vice President and Chief Administrative Officer

     13,601       $ 627,822         5,829       $ 269,067   

All executive officers as a group (9 persons)

     230,445       $ 10,637,341         98,760       $ 4,558,762   

Non-executive officer employee group

     410,326       $ 19,004,413         185,768       $ 8,639,497   

 


(1)   Payment for the performance units will be made in cash. The 2014-2016 performance units are subject to three-year performance measures tied to the Company’s total shareholder return and cumulative operating earnings per share. The amount payable at the end of the three-year performance period may be anywhere from 0% to 200 % of an individual’s target, depending on the Company’s three-year performance. The dollar amounts set forth in the Grant Date Fair Value column are equal to the grant date fair value. For additional information on the 2014-2016 Performance Units, see “Performance Units” beginning on page 52.
(2)   The dollar amounts set forth in the Grant Date Fair Value column are equal to the grant date fair value. For additional information on Restricted Stock Units, see “Restricted Stock Units” beginning on page 53.

 

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EQUITY COMPENSATION PLAN INFORMATION

 

The following table presents information as of December 31, 2014, with respect to the shares of Common Stock that may be issued under the Company’s existing equity compensation plans.

 

Plan Category


   Number of Securities
to be Issued Upon
Exercise of
Outstanding
Options,
Warrants and
Rights
(a)


     Weighted-
Average
Exercise
Price of
Outstanding
Options,
Warrants
and Rights
(b)


     Number of Securities
Remaining
Available
for Future Issuance
Equity
Compensation Plans
(excluding securities
reflected in column
(a))
(c)


 

Equity compensation plans approved by security holders

     —           NA         15,825,643   

Equity compensation plans not approved by security holders

     —           —           —     

Total

     —           NA         15,825,643   

 

Additional Information

 

The closing price per share on the NYSE of the Company’s Common Stock on February 24, 2015 was $59.28. The Company intends to register the shares issuable under the 2015 Plan under the Securities Act of 1933, as amended, after it receives shareholder approval.

 

The Board believes that it is in the best long-term interests of both shareholders and employees of the Company to maintain a progressive stock-based incentive program in order to attract and retain the services of outstanding employees and to encourage such employees to have a greater financial investment in the Company.

 

Vote Required.

 

Approval of this proposal requires the affirmative vote of holders of a majority of the votes cast at the meeting. In addition, under the rules of the NYSE, an abstention will have the same effect as a vote against this proposal.

 

Your Board of Directors recommends a vote FOR this Item 4.

 

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OVERVIEW OF PROPOSALS 5 AND 6

PROPOSALS TO ELIMINATE SUPERMAJORITY VOTE PROVISIONS IN AEP’S RESTATED CERTIFICATE OF INCORPORATION AND BYLAWS

 

Overview

 

Proposals 5 and 6 request amendments of (1) the Company’s Restated Certificate of Incorporation to delete the provision on business combinations with interested shareholders; and (2) the Company’s Bylaws to eliminate the supermajority vote provisions. The Company believes these proposed amendments of the Restated Certificate of Incorporation and Bylaws are in the best interests of the Company and its shareholders and therefore proposes that shareholders approve separate proposals for the amendments to the Restated Certificate of Incorporation and Bylaws. The amendments contemplated by Proposals 5 and 6 are not conditioned upon one another or upon the approval of any other proposal. If shareholders approve Proposals 5 and 6, it will remove all the supermajority voting requirements in the Company’s Restated Certificate of Incorporation and Bylaws.

 

Item 5. Proposal to Amend the Company’s Restated Certificate of Incorporation to Eliminate Article 7

 

The Board of Directors is unanimously recommending approval of an amendment to the Company’s Restated Certificate of Incorporation (the “Restated Certificate”) that would eliminate Article 7 of the Restated Certificate. The text of Article 7 is attached to this proxy statement as Exhibit C. Article 7 is what is commonly referred to as a “fair price provision” that stipulates that certain minimum price and procedural requirements, intended for the protection of the Company and its shareholders as a whole, be observed by any person or group (Interested Stockholder) which acquires more than five percent of the issued and outstanding shares of capital stock of the Company having voting power (Voting Stock) and then seeks to accomplish a merger or other business combination or transaction which would eliminate or could significantly change the interests of the remaining shareholders (Business Combination), unless approved by a majority of disinterested Directors. Article 7 provides that the affirmative vote of the holders of at least (1) 75% of the issued and outstanding Voting Stock, voting together as a single class, and (2) a majority of the issued and outstanding Voting Stock beneficially owned by persons other than the Interested Stockholder, voting together as a single class, is required in order to:

 

   

approve a Business Combination with an Interested Stockholder if the minimum price and procedural requirements specified in Article 7 are not followed; and

 

   

amend, alter, change, repeal, or adopt any provision inconsistent with Article 7 of the Certificate of Incorporation.

 

The fair price provision was designed to help the Company defend against certain kinds of tender offers, known as coercive, two-tiered tender offers. In this type of takeover, a potential acquirer commences a tender offer for the shares needed to gain control of a company, and then effects a transaction with the company to obtain the remaining shares at a lower price or for less favorable consideration. This creates pressure on shareholders to accept the initial tender offer, even if they believe the price is inadequate. The fair price provision was not designed to prevent a takeover, but instead to encourage a potential acquirer to negotiate with the Board to ensure all shareholders receive adequate consideration for their shares.

 

The Board is committed to implementing and maintaining effective corporate governance policies and practices to ensure that the Company is governed with high standards of accountability and in the best interests of the shareholders. After considering shareholder input, including a shareholder proposal, and considering the advantages and disadvantages of maintaining the fair price provision in the Restated Certificate, the Board has determined that it is appropriate to eliminate this provision by removing Article 7 in its entirety from the Restated Certificate. The

 

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Board understands that eliminating supermajority voting provisions is considered by many commentators and investors to be a best practice in corporate governance. In addition, the Board notes that the New York Shareholders Protection Act provides similar protections against the type of transactions the fair price provision was designed to defend against, and that a separate fair price provision in the Restated Certification is unnecessary. As a result, the Board has voted to approve, and to recommend to the Company’s shareholders that they approve, the elimination of Article 7 of the Restated Certificate.

 

If this Proposal is approved, the Company will implement it by filing an amendment to the Restated Certificate with the State of New York promptly after the Annual Meeting. If our shareholders do not approve the amendment, Article 7 of the Restated Certificate will remain in effect. The approval of Proposal 5 is not conditioned upon the approval of Proposal 6.

 

Vote Required.

 

Approval of this proposal requires the affirmative vote of holders of a majority of the shares outstanding.

 

Your Board of Directors recommends a vote FOR this Item 5.

 

Item 6. Proposal to Amend the Company’s Bylaws to Eliminate the Supermajority Provisions

 

Currently, the Company’s Bylaws provide that the provisions of Section 7 other than those relating to the number of directors constituting the Board of Directors, and the provisions of Section 16 may be amended or added to by the affirmative vote of the holders of two-thirds of the outstanding shares. This proposal seeks to amend the Bylaws to eliminate these supermajority vote provisions in the Bylaws and replace the voting standard with the vote standard of a majority of shares outstanding. These sections relate to the Company’s current practice of the annual election of directors. The text of the proposed amendment to Section 16 of the Bylaws, marked to show changes from the current Section 16, is included as Exhibit D to this Proxy Statement. If adopted, any provision of the Bylaws could be amended by the shareholders upon the approval of a majority of shares outstanding.

 

The proposed amendments to the Company’s Bylaws are the result of the Board’s ongoing review of our corporate governance principles, including consideration of a shareholder proposal on this topic. As part of its analysis, the Board recognized that supermajority vote requirements are intended to provide protection against potentially self-interested action by minority shareholders. However, while such protections can be beneficial to shareholders, as corporate governance standards have evolved, many investors and commentators now view these greater-than-majority voting provisions as limiting a board’s accountability to shareholders and the ability of shareholders to effectively participate in corporate governance.

 

The Board of Directors considered the arguments in favor of and against removing these supermajority requirements from the Company’s Bylaws and determined that removing these requirements is in the best interests of the Company and its shareholders. Because approval of a majority of the voting power of the Company would still be required to effect action under the revised provisions, the Board believes this proposal affords sufficient protection of shareholder interests while being responsive to the prevailing views regarding best corporate governance practices.

 

The approval of Proposal 6 is not conditioned upon the approval of Proposal 5. If Proposal 6 is not approved by the shareholders, AEP’s current supermajority vote provisions in the Bylaws will remain in place.

 

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Vote Required.

 

Approval of this proposal requires the affirmative vote of holders of two-thirds of the shares outstanding.

 

Your Board of Directors recommends a vote FOR this Item 6.

 

Item 7. Shareholder Proposal on Proxy Access

 

We are not responsible for the accuracy or content of the shareholder proposal or its supporting statement. After careful consideration, the Board has recommended a vote against the shareholder proposal for the reasons set forth following the proposal. The name and address of the shareholder submitting the proposal, as well as the number of shares held, will be furnished by us to any shareholder promptly upon the receipt of any oral or written request therefore.

 

A shareholder submitting a proposal must appear personally or by proxy at the meeting to move the proposal for consideration. The shareholder proposal will be approved if it is introduced and voted on at the meeting and it receives the affirmative vote of a majority of all the votes cast on the matter.

 

The following proposal, reproduced verbatim, was submitted by a shareholder for inclusion in this proxy statement.

 

RESOLVED: Shareholders of American Electric Power Company, Inc. (the “Company”) ask the board of directors (the “Board”) to adopt, and present for shareholder approval, a “proxy access” bylaw. Such a bylaw shall require the Company to include in proxy materials prepared for a shareholder meeting at which directors are to be elected the name, Disclosure and Statement (as defined herein) of any person nominated for election to the board by a shareholder or group (the “Nominator”) that meets the criteria established below. The Company shall allow shareholders to vote on such nominee on the Company’s proxy card.

 

The number of shareholder-nominated candidates appearing in proxy materials shall not exceed one quarter of the directors then serving. This bylaw, which shall supplement existing rights under Company bylaws, should provide that a Nominator must:

 

a) have beneficially owned 3% or more of the Company’s outstanding common stock continuously for at least three years before submitting the nomination;

 

b) give the Company, within the time period identified in its bylaws, written notice of the information required by the bylaws and any Securities and Exchange Commission rules about (i) the nominee, including consent to being named in the proxy materials and to serving as director if elected; and (ii) the Nominator, including proof it owns the required shares (the “Disclosure”); and

 

c) certify that (i) it will assume liability stemming from any legal or regulatory violation arising out of the Nominator’s communications with the Company shareholders, including the Disclosure and Statement; (ii) it will comply with all applicable laws and regulations if it uses soliciting material other than the Company’s proxy materials; and (c) to the best of its knowledge, the required shares were acquired in the ordinary course of business and not to change or influence control at the Company.

 

The Nominator may submit with the Disclosure a statement not exceeding 500 words in support of the nominee (the “Statement”). The Board shall adopt procedures for promptly resolving disputes over whether notice of a nomination was timely, whether the Disclosure and Statement satisfy the bylaw and applicable federal regulations, and the priority to be given to multiple nominations exceeding the one-quarter limit.

 

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Supporting Statement

 

We believe proxy access is a fundamental shareholder right that will make directors more accountable and contribute to increased shareholder value. The CFA Institute’s 2014 assessment of pertinent academic studies and the use of proxy access in other markets similarly concluded that proxy access:

 

   

Would “benefit both the markets and corporate boardrooms, with little cost or disruption.”

 

   

Has the potential to raise overall US market capitalization by up to $140.3 billion if adopted market-wide. (http://www.cfapubs.org/doi/pdf/10.2469/ccb.v2014.n9.1)

 

The proposed bylaw terms enjoy strong investor support—votes for similar shareholder proposals averaged 55% from 2012 through September 2014- and similar bylaws have been adopted by companies of various sizes across industries, including Chesapeake Energy, Hewlett-Packard, Western Union and Verizon.

 

*****

 

The Board Unanimously Recommends a Vote AGAINST This Proposal.

 

The Board’s Response

 

Summary

 

The Board of Directors has carefully considered this shareholder proposal and recommends that shareholders vote AGAINST this proposal for the reasons set forth below.

 

Proxy access is a procedure designed to facilitate company-financed proxy contests in director elections consisting of the Board’s nominees as well as one or more candidates nominated by shareholders meeting certain eligibility requirements. Given the eligibility thresholds in the proposal, the proposed proxy access would make it too easy for special interest groups with political and other agendas to submit nominations and potentially expose our Company to significant disruption. This proposal would permit any combination of shareholders beneficially owning 3% of the shares of the Company for three years to nominate candidates representing up to 25% of the Board of Directors. The Board believes that the 3% threshold is very low, and the proposal fails to contain any limit on how many shareholders can combine to satisfy that threshold. In addition, the Board believes that the ability to nominate and replace 25% of the Board of Directors is an excessively high percentage. Moreover, the proposal ignores the effective voice shareholders already have at our Company, undercuts the critical role of the independent Committee on Directors and Corporate Governance (the “Corporate Governance Committee”), and introduces an unnecessary and potentially expensive and destabilizing dynamic into the Board election process. In short, the proposal advances a solution for a problem that does not exist at our Company and does so at the risk of considerable harm to our Company and its shareholders.

 

Our strong performance as well as our sound governance practices and policies demonstrate that proxy access is not necessary at AEP and could be contrary to our shareholders’ best interests.

 

As mentioned above, the proposal is unrelated to any perceived performance deficiencies; in fact, the proposal ignores our Company’s outstanding performance. In 2010, we started the year with an opening stock price of $35.10. Five years later, on December 31, 2014, our stock closed at $60.72, representing a 73% increase. This performance has helped drive our Company’s strong total shareholder returns (“TSR”). Our Company’s TSR has outperformed that of the S&P Electric Utilities Index and the entire S&P 500 Index for the past five years as shown in the chart below.

 

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LOGO

 

Our strong performance highlights that the proposal does not seek to address any performance deficiencies at AEP. Indeed, materials published by the Boardroom Accountability Project (the “Project”), which identify 75 publicly-held companies that received proxy access proposals and the reasons those publicly-held companies were selected, indicate that our Company was targeted because of “Fossil Fuel” – not for any inadequacy related to corporate governance, executive compensation or performance. “Fossil Fuel” is not a compelling rationale to adopt proxy access, and the Board of Directors does not believe that a “Fossil Fuel” inspired proxy contest would be in the best interests of our shareholders. In particular, the Board of Directors is concerned that the rationale for this submission illustrates the potential misuse of proxy access by single purpose, special interest groups (or other shareholders) focused on personal, political or other issues that are incompatible with the best interests of our Company and its shareholders.

 

The proposal advances a solution for a problem that does not exist at our Company, as AEP’s corporate governance policies and practices are already among the most responsive and highly rated of our peers. 

 

Shareholders evaluating the proposal should consider it in the context of our overall corporate governance practices. The Board believes that its implementation of numerous corporate governance and executive compensation measures demonstrates its responsiveness and accountability to our shareholders. For example:

 

   

Our directors have been elected annually since 1952;

 

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Due to our robust director independence standards, all of our directors are independent, other than our CEO;

 

   

Our directors are elected by a majority vote standard in uncontested elections;

 

   

We have an independent Lead Director of the Board with defined and extensive duties;

 

   

Our shareholders are able to call a special shareholders’ meeting;

 

   

We have an annual advisory vote on executive compensation;

 

   

Our shareholders are able to:

 

   

Communicate with any director, any Board committee or the full Board (as discussed above under “Communicating with the Board” on page 16). At its regular meetings, our Corporate Governance Committee reviews correspondence from shareholders relating to the business of the Board;

 

   

Propose director nominees to the Corporate Governance Committee, which, in turn, evaluates and considers such nominees at its regular meetings in the same manner as it would any nominee recommended by a Board member, management, search firm or other source (as discussed above under “Selection of Director Candidates” on page 14 and “Shareholder Proposals and Nominations” on page 86);

 

   

Submit proposals for consideration at an Annual Meeting and for inclusion in AEP’s proxy statement for that meeting; and

 

   

Submit proposals, including nominations of director candidates, directly at an annual meeting.

 

In addition, in separate proposals to be voted on at the Annual Meeting (Proposals No. 5 and 6), our Board is recommending that shareholders approve amendments to our Articles of Incorporation and Bylaws that would eliminate supermajority shareholder voting requirements.

 

The proposal would bypass our independent Corporate Governance Committee’s process for identifying and recommending director nominees who would best serve our shareholders’ long-term interests.

 

An effective board of directors is composed of individuals with a diverse and complementary blend of experiences, skills and perspectives. Our Corporate Governance Committee and our Board of Directors are best situated to assess the particular qualifications of potential director nominees and determine whether they will contribute to an effective and well-rounded Board that operates openly and collaboratively and represents the best interests of all shareholders. The Corporate Governance Committee, which is comprised entirely of independent, non-employee directors, has developed Criteria for Evaluating Directors and a process for identifying and recommending director candidates for election by our shareholders, which are described in our Principles of Corporate Governance and discussed above under “Director Qualifications” on page 13. The Corporate Governance Committee’s process is thoughtfully designed to identify and nominate director candidates who possess a combination of skills, professional experience and diversity of backgrounds necessary to oversee our business and who can contribute to the overall effectiveness of our Board and its committees.

 

Additionally, as noted above in “Annual Board Evaluations,” as part of the Board’s self-assessment, the Corporate Governance Committee oversees the evaluation of the qualifications and performance of each incumbent Director prior to the Board nominating an incumbent Director for an additional term. Moreover, the Corporate Governance Committee carefully reviews and considers the independence of all potential nominees, which often is a complex undertaking in light of the broad scope of the Company’s business.

 

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Through this process, we believe that our Corporate Governance Committee and Board achieve the optimal balance of directors that best serves all of our shareholders.

 

Shareholders already have a voice in this process through their ability to nominate potential directors for consideration by the Corporate Governance Committee. The proposal, however, would enable any holder or group of holders of as little as 3% of our outstanding shares to bypass the Corporate Governance Committee’s process by placing directly into nomination candidates who may fail to meet the independence or other qualifications established by the Committee, fail to contribute to the desired mix of perspectives, or fail to represent the interests of shareholders as a whole. In contrast, our Corporate Governance Committee has a fiduciary duty to act in good faith for the best interests of the Company and all of our shareholders.

 

The proposal could undermine the effectiveness of our corporate governance.

 

The Board believes that there are several significant risks associated with proxy access, which could harm our Company, our Board of Directors and shareholders by:

 

   

Significantly Disrupting Company and Board Operations.    If proxy access is approved, contested director elections could become routine and substantially disrupt Company affairs and the effective functioning of our Board of Directors without adding significant value to the current process. As a result, our management and directors would be forced to divert their time from managing and overseeing Company business to focusing on proxy contests in the election of directors. Additionally, proxy access may cause relatively high turnover, potentially leading to an inexperienced board that lacks sufficient knowledge and understanding of our current and past business to provide meaningful and effective oversight of our operations and long-term strategies. Abrupt changes in the composition of our Board of Directors could impair our ability to develop and execute our long-term strategy.

 

   

Fragmentation of the Board of Directors.    The election of shareholder-nominated directors could create factions on the Board, leading to dissension and delay and thus precluding the Board’s ability to function effectively. A politicized Board cannot be effective in serving the best interests of all our shareholders.

 

   

Discouraging Highly Qualified Director Candidates from Serving.    The prospect of routinely standing for election in a contested situation may deter highly qualified individuals from Board service. The prospect of a perennial campaign may also cause incumbent directors to become excessively risk averse, thereby impairing their ability to provide sound and prudent guidance with respect to our operations and interests.

 

   

Encouraging Short-Termism.    The Board believes that the introduction of regular contested elections could encourage a short-term focus on the management of the business that would not be in the best interests of our shareholders. Moreover, under the proposal, a shareholder could threaten a contested election with virtually no cost to the shareholder merely to extract concessions from the Company relating to that shareholder’s special interest.

 

*    *    *    *

 

The Board believes that the current measures the Company employs for the nomination and election of Directors have led to a Board that is responsive to shareholder input and that promotes a strategy of long-term value creation. Disruption of the Board’s functioning could adversely affect the pursuit of our long-term strategy and put shareholder value at risk. For the foregoing reasons, we believe that this proposal is unnecessary, creates risk of considerable harm to our Company, and is not in the best interests of our shareholders.

 

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For these reasons, the Board unanimously recommends that our shareholders vote AGAINST this proposal and will so vote proxies received that do not otherwise specify.

 

Vote Required.

 

Approval of this proposal requires the affirmative vote of holders of a majority of the votes cast at the meeting.

 

Your Board of Directors recommends a vote AGAINST this Item 7.

 

Other Business

 

The Board of Directors does not intend to present to the meeting any business other than the election of directors, the ratification of the appointment of the independent registered public accounting firm, the advisory vote on the compensation of the named executive officers, the adoption of the long-term incentive plan, the amendment to Restated Certificate and the amendment to the Bylaws as disclosed in this proxy statement.

 

If any other business not described herein should properly come before the meeting for action by the shareholders, the persons named as proxies on the proxy card or their substitutes will vote the shares represented by them in accordance with their best judgment. At the time this proxy statement was printed, the Board of Directors was not aware of any other matters that might be presented.

 

Compensation Discussion and Analysis

 

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

Mr. Tierney

   Executive Vice President and Chief Financial Officer

Mr. Powers

   Executive Vice President and Chief Operating Officer

Mr. Feinberg

   Executive Vice President and General Counsel

Ms. Hillebrand

   Senior Vice President and Chief Administrative Officer

 

Executive Summary

 

2014 Business Performance Highlights.     AEP’s shareholders received a 35.1 percent total shareholder return in 2014 which was above the total shareholder return for the S&P 500 Electric Utilities Index of 31.2 percent and was well above the total shareholder return for the S&P 500 of 13.7 percent. The Company’s 2014 operating earnings were $3.43 per share, which exceeded our original operating earnings guidance for the year of $3.20-$3.40 per share. At the beginning of the year, the HR Committee established threshold (0 percent of target payout), target and maximum (200 percent of target payout) operating earnings per share measures for 2014 annual incentive compensation at $3.15, $3.30 and $3.45 per share, respectively. The HR Committee increased the performance target for annual incentive compensation by $0.15 per share from AEP’s 2013 target, a 4.7 percent increase, which was in line with AEP’s growth target for operating earnings.

 

During 2014, our transmission business thrived and contributed 31 cents per share to 2014 earnings. In 2014, AEP Transmission Holding Company’s net plant assets grew by approximately $1.1 billion to $2.7 billion, an increase of 65 percent. We also benefitted from successful regulatory proceedings in several states and strong margins from our regulated and nonregulated generation.

 

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The reliable performance of our generation fleet during colder than normal temperatures early and late in 2014 gave us the ability to advance spending from future years into 2014, and we continued our focus on process improvements. The Company increased its quarterly dividend by six percent in October 2014. And, for the third year in a row, the Company did not experience a fatal employee accident.

 

Throughout this CD&A, we refer to operating earnings, which is a non-GAAP financial measure. Exhibit A to this proxy statement contains a reconciliation of GAAP earnings per share to operating earnings per share for 2014.

 

2014 Earned Incentive Compensation Highlights. The Company’s 2014 operating earnings per share, together with the Company’s performance on strategic measures and safety, produced an initial score of 172.7 percent of target. The HR Committee also established two extra credit goals for 2014, a 7.5 percent credit for zero fatalities and up to a 5 percent credit for cultural improvement. The Company did not experience a fatal employee accident in 2014, which resulted in a 7.5 percent addition to the score. The HR Committee subjectively considered the Company’s achievement of culture improvements, which included sustainable cost savings from employee engagement, and awarded 2.5 percent for this measure. As a result, the overall annual incentive funding for AEP’s executive officers was 182.7 percent of target for 2014.

 

The cumulative operating earnings per share score for the 2012-2014 performance units was 112.3 percent of target. The relative total shareholder return (TSR) measure at the end of the performance period was at the 75th percentile of the S&P 500 Electric Utilities Industry Index, which produced a score of 183.3 percent of target. The operating earnings per share and TSR scores combined to produce an overall score of 147.8 percent of target for the 2012-2014 performance period. As a result, 147.8 percent of the 2012-2014 performance units outstanding at year-end were earned.

 

Other Highlights.    Effective January 1, 2014, the HR Committee replaced all of the Company’s change in control agreements to eliminate the provisions that provided a tax gross-up for excise taxes. Prior to this change, some of the named executive officers had change in control agreements that provided for a payment that offset the effect of an excise tax with a “gross-up” payment that would have reimbursed those executives for any excise tax on an after-tax basis.

 

As part of the HR Committee’s independent compensation consultant’s comprehensive review of the Company’s executive compensation in September 2013, the consultant noted that the Company’s practice of using a mix of electric utility and general industry peers differed from the majority practice in the utility industry. Therefore, the HR Committee approved changing the Company’s peer group effective for 2014. The HR Committee retained all of the existing utility peer companies and added three utility peer companies, but removed all of the general industry companies. The HR Committee made these changes because it determined that an all utility peer group provides more meaningful compensation comparisons and because other similar utility companies are the primary competitors for the Company’s executive talent. In addition, recent consolidations and mergers in the utility industry increased the size of a number of the utility peer companies making them more comparable to the Company in terms of revenues.

 

Corporate Governance Highlights.    For many years, the Company has:

 

   

Had significant stock ownership requirements for its executive officers;

 

   

Tied a substantial portion of the compensation for its executives to annual and long-term performance;

 

   

Had a policy that allows the Company to claw back incentive compensation in certain circumstances; and

 

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Had an insider trading policy that prohibits our executives and directors from hedging their AEP stock holdings or holding them in margin accounts without Company approval.

 

The HR Committee has made several changes to the Company’s executive compensation program in the last several years to align with best practices, including:

 

   

Granting long-term incentive awards with change in control provisions that include a double trigger that results in vesting of these awards only if there is a change in control and an involuntary or constructive separation from service;

 

   

Eliminating company paid country club memberships for executive officers;

 

   

Generally eliminating personal use of Company provided aircraft, to the extent that such use has an incremental cost to the Company;

 

   

Eliminating tax gross-ups, other than for relocations;

 

   

Amending the Company’s Insider Trading Policy to prohibit directors and executive officers from pledging Company stock; and

 

   

Eliminating the reimbursement and tax gross-up for excise taxes triggered under change in control agreements.

 

Results of 2014 Advisory Vote to Approve Executive Compensation

 

At the Company’s annual meeting of shareholders held in April 2014, approximately 96 percent of the votes cast on the Company’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 the Company’s say-on-pay vote and other sources of stakeholder feedback when establishing compensation programs and making compensation decisions for the named executive officers.

 

The Board decided that AEP will hold an advisory vote on the compensation of named executive officers at each annual meeting of shareholders until the next required shareholder vote to determine the frequency of the advisory votes on executive compensation. Because the Dodd-Frank Act requires that such frequency votes be held at least once every six years, we currently expect the next shareholder vote on frequency to occur at the Company’s 2017 annual meeting of shareholders.

 

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 those 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;

 

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Align the interests of the Company’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 the Company’s business strategy by tying annual incentive awards to an operating earnings per share target 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 is intended to create a total compensation opportunity (base salary, annual incentive opportunity and long-term incentive opportunity) that, on average, is equal to the median of AEP’s Compensation Peer Group, as described under Compensation Peer Group on page 44. 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. See the Human Resources Committee Report on page 58 for additional information about Meridian’s independence.

 

Compensation Program Design

 

The compensation program for executive officers includes base salary, annual incentive compensation, long-term incentive compensation, a comprehensive benefits program and limited perquisites. The Company 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, safety, zero fatality and corporate culture objectives.

 

For 2014, operating earnings per share constituted 75 percent of the performance measure for annual incentive compensation and the remaining 25 percent of the performance measure for annual incentive compensation was tied to strategic and safety goals. In addition, the HR Committee established two extra credit goals for 2014: zero fatalities and culture, which could add an additional 7.5 percent and up to 5 percent to the score, respectively.

 

For 2014, the majority of AEP’s long-term incentive compensation (70 percent) was awarded in the form of performance units with three-year performance measures tied to (1) AEP’s total shareholder return relative to all 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 remaining 30 percent of AEP’s long-term incentive compensation was awarded as restricted stock units (RSUs) which 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 also uses long-term incentives as a retention tool to foster management continuity. The performance units are subject to a three-year vesting period.

 

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 2014, 66 percent of the target total direct compensation for the CEO and 57 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 21 per-

 

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cent of the CEO’s target total direct compensation and an additional 17 percent on average for the other named executive officers were provided in the form of RSUs (grant date value) which are tied to AEP’s stock price.

 

LOGO

 

Compensation Peer Group

 

The HR Committee, supported by its independent compensation consultant, 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 within an approximate revenue range of 0.5 to 2.0 times AEP’s revenues.

 

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For 2014, the AEP’s Compensation Peer Group consisted of the 17 utility companies shown below.

 

AES Corporation

Centerpoint Energy, Inc.

Consolidated Edison Inc.

Dominion Resources, Inc.

DTE Energy Company

Duke Energy Corporation

Edison International

Entergy Corporation

Exelon Corporation

FirstEnergy Corp.

NextEra Energy, Inc.

PPL Corporation

PG&E Corporation

Public Service Enterprise Group Inc.

Sempra Energy

Southern Company

Xcel Energy Inc.

 

The table below shows that, at the time the Compensation Peer Group data was collected in July 2013, AEP’s revenue was above the 50th percentile, and closer to the 75th percentile, of the combined peer group.

 

2014 Compensation Peer Group

 

     Revenue
($ million)


 

Compensation Peer Group

        

25th Percentile

   $ 11,128   

50th Percentile

   $ 13,418   

75th Percentile

   $ 15,320   

AEP

   $ 14,945   

 

The HR Committee’s independent compensation consultant annually provides the HR Committee with an executive compensation study covering all executive officer positions and other executive positions based on survey information for the Compensation Peer Group. The methodology and job matches used in this study are generally determined by the HR Committee’s independent compensation consultant based on descriptions of each executive’s responsibilities and are reviewed with the HR Committee. The standard benchmark is the median value of total compensation paid by the Compensation Peer Group to officers serving in similar capacities. 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.

 

For 2014, the HR Committee benchmarked compensation for named executive officer positions to similar positions in the Compensation Peer Group. Where possible, market values were further adjusted for relative size based on revenues using regression analysis. To the extent that the total compensation opportunity is above or below the +/- 15 percent target range around the Compensation Peer Group median, the HR Committee adjusts elements of pay over time to bring the executive’s total compensation opportunity into the target range. The HR Committee’s independent compensation consultant completes an annual executive compensation study. The October 2013

 

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study, which was used for 2014 executive compensation decisions, found that, in aggregate, for the named executive officers, each of base salary, total cash compensation and total direct compensation was within the +/- 15 percent market competitive range.

 

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Executive Compensation Program Detail

 

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

 

Component

 

Purpose


 

Key Attributes


     

Base Salary

 

•    To provide a market-competitive and consistent minimum level of compensation.

 

•    A 3 percent executive merit budget was approved by the HR Committee for 2014.

 

•    Merit and other salary increases for executives are awarded by the HR Committee based on a variety of factors, which are described under Base Salary on page 48.

     

Annual Incentive Compensation

 

•    To focus executive officers on achieving annual earnings objectives and other performance objectives that are critical to AEP’s success.

 

•    The performance objectives for 2014 included:

 

•    Operating Earnings (75 percent weight)

 

•    Safety (10 percent weight)

 

•    Strategic Initiatives (15 percent weight)

 

•    Zero Fatalities (7.5 percent extra credit), and

 

•    Culture (up to 5 percent extra credit).

 

•    To communicate and align executive and employee efforts with the Company’s performance objectives.

 

•    Annual incentive targets are established by the HR Committee based on market competitive compensation information provided by the HR Committee’s independent compensation consultant.

 

•    Actual awards generally may vary within a range of 0 percent to 200 percent of each executive’s annual incentive target.

 

•    Operating earnings per share was chosen as the primary performance measure for 2014.

 

•    An operating earnings per share threshold of $3.15 per share was established that provided annual incentive funding for the plan as a whole only if the threshold was reached.

 

•    The CEO’s award is determined by the independent members of the Board of Directors and the other NEO awards are determined and approved by the HR Committee and based on:

 

•    Achievement against performance objectives, and

 

•    A subjective evaluation of each named executive officer’s individual performance for the year.

 

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Component

 

Purpose


 

Key Attributes


     

Long-Term Incentive Compensation

 

•    To motivate AEP management to maximize shareholder value by linking a substantial portion of their potential compensation directly to shareholder returns.

 

•    To help ensure that Company management remains focused on longer-term results, which the HR Committee considers essential given the large long-term investments in physical assets required in our business.

 

•    To reduce executive turnover and maintain management consistency.

 

•    For 2014, the HR Committee provided long-term incentive awards in the form of three-year performance units for 70 percent of the grant value and restricted stock units (RSUs) for 30 percent of the grant value.

 

•    Each NEO’s total target long-term incentive award is based on:

 

•     Award guidelines for each salary grade and market competitive compensation information provided by the HR Committee’s independent compensation consultant, and

 

•     A subjective evaluation of the individual’s potential contribution to shareholder value during the performance period.

 

•    For the 2014-2016 performance unit awards, the HR Committee established the following equally weighted performance measures:

 

•     Three-year cumulative operating earnings per share relative to a board approved target, and

 

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

 

Base Salary. Merit and other salary increases for executives are awarded based on:

 

   

The Company’s merit budget,

 

   

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

 

   

The market competitiveness of the executive’s salary,

 

   

Internal comparisons,

 

   

The responsibilities, experience and future potential of each executive,

 

   

Reporting relationships, and

 

   

The impact that any change in base salary may have on other pay elements and the market competitiveness of the executive’s total compensation.

 

The HR Committee approved 3 percent merit budgets for 2014 and 2015 but salary increases varied for individual executive officers based on the factors described above. In addition to merit increases, the HR Committee provided market-based salary increases for 2015 to executives whose salary was below the market competitive range, provided their overall salary increase would not result in total cash compensation or total direct compensation above the market competitive

 

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range. These market-based increases were designed to bring the executive’s salary to the lower end of the market competitive range in combination with a 3 percent merit increase. The overall 2015 salary increases for the named executive officers were 3.2, 2.0, 2.0, 4.0 and 11.2 percent, for Messrs. Akins, Tierney, Powers and Feinberg and Ms. Hillebrand, respectively.

 

Annual Incentive Compensation.

 

Annual Incentive Targets.    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 its independent compensation consultant and Company management, establishes the annual incentive targets for each executive officer position primarily based on market median compensation for the executive’s position as shown in the independent compensation consultant’s annual executive compensation study. For 2014, the HR Committee established the following annual incentive targets for each of the positions held by 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 EVP and Chief Operating Officer (Mr. Powers);

 

   

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

 

   

60 percent of base earnings for the SVP and Chief Administrative Officer (Ms. Hillebrand).

 

Performance Score for Annual Incentive Plan.    In 2014, AEP produced operating earnings per share of $3.43, which exceeded the upper end of the range of the Company’s original earnings guidance. This earnings result, together with the Company’s performance on the measures discussed below (safety and strategic initiatives), produced a result of 172.7 percent of the target award opportunity for executive officers. Because the Company did not experience a fatal employee accident, 7.5 percent was added to the annual incentive award opportunity. In addition, the HR Committee approved a 2.5 percent addition for the culture extra credit measure. These positive adjustments increased the incentive funding to 182.7 percent of target for 2014.

 

For 2014, GAAP earnings per share reported in AEP’s financial statements was $3.34, $0.09 per share lower than operating earnings, primarily because of the termination of a coal contract. Exhibit A to this proxy statement contains a reconciliation of GAAP earnings per share to operating earnings per share.

 

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Annual Performance Objectives.    For 2014, the HR Committee developed a balanced scorecard to tie annual incentive awards to the Company’s safety and strategic objectives for the year. The HR Committee uses this balanced scorecard because it helps mitigate 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 weightings of these measures and the threshold, target and maximum payout levels are determined by the HR Committee and are set forth with 2014 actual results and scores in the table below. We more fully explain the measures and the reasons we chose the measures in the text following the table.

 

     Weight   Threshold    Target    Maximum    Actual
Performance
Result
  

Actual
Award
Score

(as a percent
of target
opportunity)

  Weighted
Score

Operating Earnings Per Share (75%)

   75%   $3.15    $3.30    $3.45    $3.43    185.5%   1.391

Safety (10%)

                                

Recordable Case Rate (the number of Occupational Safety and Health Administration recordable incidents per 200,000 work hours)

   4%   0.99    0.87    0.76    0.92    58.3%   0.023

Severity Rate (the number of lost and restricted duty days due to Occupational Safety and Health Administration recordable incidents per 200,000 work hours)

   5%   19.62    17.35    15.09    24.21    0%   0.000

Contractor Recordable Case Rate (the number of Occupational Safety and Health Administration recordable incidents per 200,000 work hours for major AEP contractors)

   1%   1.73    1.5    1.28    1.44    127.3%   0.013

Strategic Initiatives (15%)

                                

Earnings Growth Trajectory

(the extent of O&M cost acceleration from 2015 and 2016 into 2014)

   15%   $25
million
   $32.5
million
   $40
million
   $47

million

   200%   0.300

Additional Credit Measures

                                

Fatality Adjustment

   NA   +7.5% for completing the

year without a fatal work related

employee incident

   No employee
fatality
   +7.5%   0.075

Culture Adjustment

   NA   Up to +5% for achieving specific

culture and employee engagement objectives, including the achievement of sustainable savings. This is a subjective measure that was scored at +50%.

   Not

Applicable

   +2.5%   0.025

Total Score

                               1.827

 

Operating Earnings.    The HR Committee chose operating earnings per share because it largely reflects management’s performance in operating the Company. It is also strongly correlated with shareholder returns and is the primary measure by which the Company 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 the Company to create long-term shareholder value.

 

Safety.    With safety as an AEP core value, maintaining the safety of AEP employees and the general public is always our primary consideration. Accordingly, safety measures comprised 10

 

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percent of the 2014 scorecard. We measure employee and contractor recordable case rate for both employees and contractors in accordance with the methodology prescribed by the Occupational Safety and Health Administration (OSHA) for recordable incidents. We measure the incident severity rate by the number of lost and restricted duty work days per 200,000 work hours. In addition to these safety measures, the HR Committee also established a fatality credit adjustment for 2014, which is discussed below.

 

Strategic Initiatives.    Fifteen percent of the scorecard was tied to the success of accelerating operations and maintenance expenses from 2015 and 2016 into 2014 to support meeting the Company’s four to six percent earnings growth trajectory.

 

Fatality and Culture Adjustment Credits.    The HR Committee established a fatality adjustment credit for 2014 that would add 7.5 percent to the total score in the event of a fatality free year. The HR Committee also established a culture adjustment credit for 2014 that would add up to 5 percent based on culture improvement, which included measuring sustainable cost savings from employee engagement.

 

2014 Individual Award Calculations.    The calculation of the 2014 annual incentive opportunity is shown in the chart below for each named executive officer. This is the starting point for determining actual annual incentive awards. The HR Committee then subjectively evaluates the individual performance of each named executive officer to determine the actual awards, which are also shown in the table below and in the Non-Equity Incentive Plan Column of the Summary Compensation Table for 2014.

 

Name


   2014
Base
Earnings*


            Annual
Incentive
Target %


           Final
Performance
Score


           Calculated
Annual
Incentive
Opportunity


     2014 Actual
Awards


 

Mr. Akins

   $ 1,235,031         x         125     x         182.7     =       $ 2,820,502       $ 2,950,000   

Mr. Tierney

   $ 692,132         x         80     x         182.7     =       $ 1,011,620       $ 1,050,000   

Mr. Powers

   $ 692,132         x         80     x         182.7     =       $ 1,011,620       $ 1,012,000   

Mr. Feinberg

   $ 566,056         x         65     x         182.7     =       $ 672,219       $ 675,000   

Ms. Hillebrand

   $ 488,294         x         60     x         182.7     =       $ 535,268       $ 560,000   

 

*   Based on earnings paid in 2014, which is slightly different than the salary earned for 2014 shown in the Summary Compensation Table on page 61.

 

The HR Committee believes that annual incentive compensation should not be based purely on a formulaic calculation, such as that shown in the Calculated Annual Incentive Opportunity column above, but should instead be adjusted from this starting point to reflect each executive’s individual performance and contribution. Based on recommendations from the CEO focusing on the individual performance and contribution of the other named executive officers, the HR Committee approved the annual incentive awards shown in the 2014 Actual Awards column. The annual incentive award for the CEO was approved by the independent members of the Board.

 

AEP provides annual incentive compensation to executive officers through the Senior Officer Incentive Plan, which was approved by shareholders at the 2012 annual meeting. This plan establishes the maximum annual incentive award opportunity for each executive officer that is potentially tax deductible by the Company under section 162(m) of the Internal Revenue Code. For further information see discussion under Tax Considerations on page 57.

 

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 2014 award cycle, 70 percent of the long-term incentive grant date value was awarded as performance units and 30 percent of the grant date value was awarded as restricted stock units (RSUs).

 

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The HR Committee establishes awards for each named executive officer position based primarily on market competitive long-term and total compensation information provided by the HR Committee’s independent compensation consultant for similar positions in AEP’s Compensation Peer Group. Long-term incentive awards are approved by the HR Committee, or, for the CEO, by the independent members of the Board. These determinations are made based on:

 

   

Award guidelines for each named executive officer’s position, other than the CEO position, which are established by the HR Committee, which creates an award pool that the HR Committee uses in determining awards for all positions except the CEO position;

 

   

Individual performance assessments. However, any positive discretionary adjustments based on individual performance must generally be offset by negative adjustments for other participants to avoid exceeding the award pool;

 

   

The individual executive’s total direct compensation relative to market median compensation for his or her position as shown in the annual executive compensation study conducted by the HR Committee’s independent compensation consultant; and

 

   

The executive officer’s future potential for advancement.

 

The HR Committee also regularly reviews tally sheets for the CEO that show the potential future payout of outstanding equity awards. These tally sheets show the extent to which the value of the potential payout from all outstanding equity awards is linked to changes in AEP’s stock price and the value likely to be paid from all outstanding equity awards taking Company performance into consideration.

 

2014 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

     101,907         43,674         145,581       $ 6,720,019   

Mr. Tierney

     28,529         12,226         40,755       $ 1,881,251   

Mr. Powers

     28,529         12,226         40,755       $ 1,881,251   

Mr. Feinberg

     14,596         6,255         20,851       $ 962,482   

Ms. Hillebrand

     13,601         5,829         19,430       $ 896,889   

 

These performance units and RSUs provide total direct compensation opportunities to executives that are on average within the market competitive range. Differences between the awards for individual executives primarily reflect differences in market median compensation for the executive as shown in the annual executive compensation study conducted by the HR Committee’s independent compensation consultant, the executive’s performance and the executive’s potential contribution to shareholder value.

 

Performance Units.    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 period and vesting period. Vested performance units are paid out in cash unless they are needed to meet an executive’s stock ownership requirement, in which case some or all of the vested performance units are mandatorily deferred into AEP Career Shares. AEP Career Shares are not paid to participants until after their AEP employment ends.

 

The HR Committee granted performance unit awards for a 2014 – 2016 performance period to each named executive officer. Dividends are reinvested in additional performance units, but those additional performance units are subject to the same performance measures and vesting requirements as the underlying performance units. The total number of performance units held at the end of the performance period is multiplied by the weighted score for the two performance measures shown below to determine the award payout. The maximum score for each performance measure is 200 percent. For further information on these awards, see the description under 2014 Stock

 

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Award Grants beginning on page 65. For the 2014-2016 performance units, the cumulative operating earnings per share target was set at $10.25, which was a 4.2 percent increase over the prior three-year goal.

 

Performance Measures for 2014 – 2016 Performance Units

 

Performance Measure


   Weight

    Threshold
Performance


   Target
Performance


   Maximum Payout
Performance


3-Year Cumulative Operating Earnings Per Share

     50   $9.90

(30% payout)

   $10.25

(100% payout)

   $10.97

(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 companies in our industry.

 

Restricted Stock Units.     Each Restricted Stock Units (RSU) has an economic value equivalent to a share of AEP common stock. The HR Committee granted 30 percent of the aggregate grant date value of the Company’s 2014 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, 2015, May 1, 2016 and May 1, 2017, respectively. Dividends are reinvested in additional RSUs, but those additional RSUs are subject to the same vesting requirements applicable to the underlying RSUs. Upon vesting, these RSUs pay out in cash to executive officers. The HR Committee granted RSU awards that pay out in cash to executive officers because these executives have other means of meeting their stock ownership requirements and might otherwise be prevented from utilizing this compensation for extended periods of time due to restrictions on insider trading.

 

Stock Ownership Requirements.    The HR Committee believes that linking a significant portion of an executive’s financial rewards to the Company’s success, as reflected by the value of AEP stock, gives the executive a stake similar to that of the Company’s shareholders and encourages long-term management strategies that benefit shareholders. Therefore, the HR Committee requires certain officers (47 individuals as of January 1, 2015) to accumulate and hold a specific amount of AEP common stock or stock equivalents. The HR Committee annually reviews the minimum stock ownership level for each executive officer and periodically adjusts these levels. Each named executive officer has met his or her stock ownership requirement or is on pace to meet the requirement within five years of the date it was assigned.

 

The CEO’s stock ownership target is five times his base salary, and the other named executive officers’ targets are three times their respective base salaries.

 

Until the designated multiple of base salary is reached, performance units are mandatorily deferred into AEP Career Shares to the extent necessary to meet an executive’s minimum stock ownership requirement. AEP Career Shares are stock units that are paid out in cash after the executive’s employment at AEP ends. In addition, in the event that an executive has not met his or her minimum stock ownership requirement within five years of the date it was assigned 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.

 

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.

 

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AEP’s named executive officers participate in the same pension and savings plans as other eligible employees. These include tax-qualified defined contribution and defined benefit plans. AEP’s named executive officers also participate in the Company’s non-qualified retirement benefit plans, which are largely designed to 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. As a result, the non-qualified plans allow eligible employees to accumulate higher levels of replacement income upon retirement than would be allowed under the tax-qualified plans alone.

 

The HR Committee recognizes that the non-qualified plans result in the deferral of the Company’s income tax deduction 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 other employees; that these benefits are prevalent among similar companies; and that these benefits are a part of a market competitive total rewards package.

 

The HR Committee limits both the amount and types of compensation that are included in the qualified and non-qualified retirement plans because they 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 the AEP Supplemental Benefit Plan limits eligible compensation to the greater of $1 million or twice the participant’s base salary, and

 

   

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

 

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

 

For executives who 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 relocate internal candidates.

 

Perquisites.    The HR Committee annually reviews the perquisites provided by the Company. In 2014, AEP only 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.

 

While corporate aircraft provides enhanced security, travel flexibility and reduced travel time, which benefits the Company, the HR Committee is sensitive to concerns regarding the expense of corporate aircraft and the public perception regarding personal use of such aircraft. Accordingly, effective October 2009, the HR Committee generally prohibited personal use of corporate aircraft that has an incremental cost to the Company. The Company allows personal travel on business trips using corporate aircraft if there is no incremental cost to the Company. Income is imputed and taxes are withheld on the value of personal travel on corporate aircraft in accordance with IRS standards.

 

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Other Compensation Information

 

Recoupment of Incentive Compensation.

 

The Board believes that incentive compensation should be reimbursed to the Company if, in the Board’s determination:

 

   

Such incentive compensation was predicated upon the achievement of financial or other results that were subsequently materially restated or corrected,

 

   

The executive from whom such reimbursement is sought engaged in misconduct that caused or partially caused the need for the restatement or correction, and

 

   

A lower payment would have been made to the executive based upon the restated or corrected financial results.

 

The Board adopted this clawback policy in February 2007, and the HR Committee has directed the Company to design and administer all of the Company’s incentive compensation programs in a manner that provides for the Company’s ability to obtain such reimbursement. The Company 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 the 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 the CEO or other management present. The Chairman of the Board and the Chair of the HR Committee have the authority to call meetings of the HR Committee.

 

The CEO has assigned AEP’s Senior Vice President & Chief Administrative Officer and Director – Compensation and Executive Benefits to support the HR Committee. These individuals work closely with the HR Committee Chairman, the CEO and the HR Committee’s independent compensation consultant, Meridian, to research and develop requested information, prepare meeting materials, implement the HR Committee’s actions and administer the Company’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 the Company 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 all the named executive officers with the HR Committee and recommends their compensation to the HR Committee. 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

 

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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 in recruiting external candidates for certain executive 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 the Company and the interests of shareholders in the event of an anticipated or actual change in control. During such transitions, retaining and continuing to motivate the Company’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 the Company, 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 the Company 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 its independent compensation consultant, 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 bonus for each of the named executive officers. Most of the other executives covered by change in control agreements have the lesser multiple of 2.0 times base salary and bonus. 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.

 

Effective January 1, 2014, the HR Committee replaced all of the Company’s change in control agreements to eliminate a provision that provided a tax gross-up for excise taxes. Prior to this date, some of the named executive officers had change in control agreements that provided for a payment that offset the effect of an excise tax with a “gross-up” payment that would have reimbursed those executives for any excise tax on an after tax basis.

 

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 the Company without cause or by the executive for good reason, then a pro rata portion of the executive’s outstanding performance units will vest and be paid at the target performance score. All outstanding RSU awards granted before December 2010 also fully vest in the event of a change in control. A double trigger was added to RSU awards granted on or after this date. This double trigger requires that an executive’s employment be terminated under defined circumstances within one year after a change in control in order for all of the executive’s outstanding restricted stock units to vest.

 

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 maintains a broad-based severance plan that provides two weeks of base pay per year of service to all employees, including 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

 

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employees include outplacement services and access to health benefits at active employee rates for up to 18 months (or until age 65 for employees who are at least age 50 with 10 years of service at the time of their severance).

 

Named executive officers and other employees remain eligible for an annual incentive award based on their eligible pay for the year, which reflects the portion of the year that they worked, if they separate from service prior to year-end due to their retirement or death. 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 2014, executive officers were also entitled to one year of continued financial counseling service in the event they are severed from service as the result of a restructuring, consolidation or downsizing. In the event of their death, their spouse or the executor of their estate would be eligible for this benefit.

 

The Company also has an Executive Severance Plan (the “Executive Severance Plan”) that provides severance benefits to selected officers of the Company, 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 above; 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 the Company and agreement not to compete with the Company for two years. For further information on the Executive Severance Plan, see the description under Potential Payments Upon Termination of Employment or Change in Control beginning on page 74. 

 

Insider Trading, Hedging and Pledging.    The Company maintains an insider trading policy that 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 placing AEP stock in margin accounts without the approval of the Company and from pledging AEP stock as collateral for any loan.

 

Tax Considerations.     Section 162(m) of the Internal Revenue Code (Section 162 (m)) limits the Company’s ability to deduct compensation in excess of $1,000,000 paid in any year to the Company’s CEO or any of the next three highest compensated named executive officers, other than the CFO. The HR Committee considers the limits imposed by Section 162(m) when designing compensation and benefit programs. Because the annual incentive compensation awarded in 2014 was performance-based and awarded by a committee of independent outside directors pursuant to the Senior Officer Incentive Plan (the SOIP), which was approved by shareholders, it is consistent with the requirements for tax deductibility by the Company under Section 162(m). The HR Committee established 0.75 percent of income before discontinued operations, extraordinary items and the cumulative effect of accounting changes (Adjusted Income) as the performance measure for the 2014 SOIP and further allocated a specific percentage of Adjusted Income to each executive officer. In this way, the HR Committee retains the flexibility to make awards that are based on individual performance in a way that is consistent with the requirements under Section 162(m). In no case did the annual incentive awards paid for 2014 exceed the maximum award provided under the SOIP.

 

Performance units, which were granted under the shareholder approved Long-Term Incentive Plan, are also consistent with the requirements for tax deductibility by the Company under Section 162(m). For the 2014-2016 performance period, the HR Committee established cumulative

 

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three-year income before discontinued operations, extraordinary items and the cumulative effect of accounting changes (Adjusted Income) as the performance measure with a threshold (0 percent) payout at $1 billion and a maximum (200 percent) payout at $2.5 billion. Because these awards are based on an objective definition of earnings that was approved by shareholders as part of the long-term incentive plan, they are consistent with the requirements for tax deductibility by the Company under Section 162(m). However, the HR Committee retains the discretion to reduce the payout.

 

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.

 

By meeting the requirements for performance based compensation under Section 162(m) for annual incentive compensation and performance units, these payments are potentially tax deductible for the Company. However, 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 intends to continue to utilize shareholder approved plans and performance based awards to allow the Company to deduct most annual and long-term incentive compensation paid to named executive officers. The HR Committee may still grant awards that are not intended to constitute qualified performance-based compensation under Section 162(m) if the HR Committee determines that granting such awards is in the best interests of the Company.

 

Finally, Section 409A of the Internal Revenue Code imposes additional taxes on named executive officers whose deferred compensation fails to comply with Section 409A. The Company has reviewed its compensation arrangements to help ensure they comply with applicable Section 409A requirements.

 

Human Resources Committee Report

 

Membership and Independence.    The Board has determined that each member of the HR Committee is an independent director, as defined by the NYSE listing standards. Each member of the HR Committee is also a “non-employee director” for purposes of SEC Rule 16b-3 and an “outside director” for purposes of Section 162(m). Each member of the HR Committee attends professional development training that addresses topics of specific relevance to public company compensation committees.

 

Purpose.    The primary purpose of the HR Committee is to provide independent oversight of the compensation and human resources policies and practices of the Company. The primary objective of the HR Committee with respect to executive compensation is to ensure that executive officers are compensated in a manner that is consistent with the Company’s business strategy, risk tolerance, competitive practices, internal equity considerations, and Company and Board policies.

 

Functions and Process.    The HR Committee operates under a written charter reviewed annually by the Board. This charter is available on AEP’s website at www.aep.com/investors/corporateleadersandgovernance.

 

The HR Committee annually reviews AEP’s executive compensation in the context of the performance of management and the Company. The HR Committee reviews and approves the compensation for all executive officers, other than the CEO, and other senior officers. With respect to the compensation of the CEO, the HR Committee is responsible for making compensation recommendations to the independent members of the Board, who review and approve the CEO’s compensation.

 

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In carrying out its responsibilities, the HR Committee addressed many aspects of AEP’s human resource and executive compensation programs and practices in 2014, including:

 

   

Establishing annual and long-term performance objectives for executive officers;

 

   

Assessing the performance of the CEO, other executive officers and the Company relative to those established performance objectives;

 

   

Conducting an evaluation of the CEO based on written comments from board members, senior AEP management, and the audit firm partner overseeing AEP’s external audit;

 

   

Determining the mix of base salary, annual incentive compensation and long-term equity based compensation for executive officers;

 

   

Assessing the competitiveness of 2014 and proposed 2015 target compensation for all executive officers relative to AEP’s Compensation Peer Group;

 

   

Determining the mix of performance units and restricted stock units issued as long-term incentive awards;

 

   

Reviewing and approving the base salaries, annual incentive awards and long-term incentive award opportunities for 24 officers;

 

   

Assessing compensation risk;

 

   

Reviewing and approving change in control agreements;

 

   

Reviewing the Company’s workforce safety efforts and results;

 

   

Reviewing the senior management succession and development plans; and

 

   

Reviewing and approving reports to shareholders regarding executive compensation.

 

In establishing performance objectives, the HR Committee considers the interests of other major AEP stakeholders, such as AEP’s customers, employees, and the communities in which AEP operates, in addition to those of AEP’s shareholders. For example, the HR Committee tied 2014 annual incentive compensation for all executive officers to measures that included employee safety, while also tying funding for annual incentive compensation to AEP’s operating earnings per share.

 

In determining executive compensation, the HR Committee considers all relevant factors, including:

 

   

Company performance;

 

   

The CEO’s individual performance, based, in part, on a leadership assessment that specifically covers integrity and ethics, communication, willingness to confront tough issues, business acumen, strategic planning, teamwork, and fostering a high performance culture;

 

   

Individual performance and compensation recommendations for other executive officers as assessed by the CEO and their direct manager;

 

   

Market competitive compensation survey information from the executive compensation study conducted by the HR Committee’s independent compensation consultant;

 

   

Succession planning;

 

   

Executive retention;

 

   

The responsibilities and experience of each executive officer;

 

   

Compensation history;

 

   

The impact salary changes may have on other elements of total rewards;

 

 

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The impact of compensation on risk taking; and

 

   

The expense implications of any changes.

 

The HR Committee’s Independent Compensation Consultant.    The HR Committee engaged Meridian to provide recommendations to the HR Committee regarding AEP’s executive compensation and benefit programs and practices. The HR Committee is authorized to retain and terminate consultants and advisors without management approval and has the sole authority to approve their fees. Among other assignments, the HR Committee’s independent compensation consultant provides an annual executive compensation study and a report on current executive compensation and benefits trends within the electric utility industry.

 

The HR Committee annually assesses and discusses the independence of its executive compensation consultant. Meridian did not provide any services to AEP, other than the work it performed for the HR Committee, and the work it performed for the Committee on Directors and Corporate Governance on director compensation. The HR Committee concluded that Meridian was independent and that there was no conflict of interest.

 

The HR Committee also annually assesses the performance and objectivity of its executive compensation consultant and has found that the advice provided by Meridian was of a high quality, objective and appropriate for the Company. The HR Committee regularly holds executive sessions with Meridian to help ensure that they receive full and independent advice and that Meridian is not unduly influenced by the Company’s management.

 

In fulfilling its oversight responsibilities, the HR Committee reviewed and discussed with management the Compensation Discussion and Analysis set forth in this proxy statement. Based on its review and these discussions, the HR Committee recommended to the Board that the Compensation Discussion and Analysis be included in this proxy statement and incorporated by reference into the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

 

Human Resources Committee Members

 

Ralph D. Crosby, Jr., Chair

Thomas E. Hoaglin

Richard C. Notebaert

Stephen S. Rasmussen

Oliver G. Richard, III

 

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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—

    2014        1,240,754        —          6,720,019        2,950,000        359,787        102,960        11,373,520   

Chairman of the Board and

Chief Executive Officer

    2013        1,204,615        —          6,720,167        2,430,000        155,741        102,065        10,612,588   
    2012        903,461        —          4,600,008        1,500,000        176,312        106,709        7,286,490   

Brian X. Tierney

    2014        695,339        —          1,881,251        1,050,000        269,994        82,448        3,979,032   

Executive Vice President and

Chief Financial Officer

    2013        675,086        —          1,893,044        875,500        0        77,689        3,521,319   
    2012        652,500        —          1,896,860        800,000        228,760        49,467        3,627,587   

Robert P. Powers

    2014        695,339        —          1,881,251        1,012,000        746,589        82,706        4,417,885   

Executive Vice President and Chief Operating Officer

    2013        675,086        —          1,893,044        875,500        0        78,184        3,521,814   
    2012        652,500        —          1,896,860        800,000        586,359        60,809        3,996,528   

David M. Feinberg—

    2014        568,679        —          962,482        675,000        69,384        63,293        2,338,838   

Executive Vice President and General Counsel

    2013        552,115        —          1,050,302        585,000        36,057        55,309        2,278,783   
    2012        451,731                857,807        450,000        30,361        37,044        1,826,943   

Lana L. Hillebrand(6)

    2014        490,680        —          896,889        560,000        147,547        55,902        2,151,018   

Senior Vice President and Chief Administrative Officer

    2013        471,808        —          1,146,251        480,000        8,193        64,386       2,170,638   
    2012        19,884        464,000        —          —          8,002        —          483,884   

(1)   Amounts in the salary column are composed of executive salaries earned for the year shown, which include 261 days of pay for 2014, which 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 our Long-Term Incentive Plan. See Note 15 to the Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2014 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 the Company’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 2014 performance units is equal to $9,408,054 for Mr. Akins, $2,633,798 for Messrs. Powers and Tierney, $1,347,502 for Mr. Feinberg and $1,255,644 for Ms. Hillebrand; and the maximum amount payable for the 2013 performance units is equal to $9,807,454 for Mr. Akins, $2,807,952 for Messrs. Powers and Tierney, $1,352,936 for Mr. Feinberg and $1,220,475 for Ms. Hillebrand. The 2012 performance units vested on December 31, 2014 and are shown in the Option Exercises and Stock Vested for 2014 table. The RSUs vest over a forty month period. For further information on these awards, see the Grants of Plan-Based Awards for 2014 table on page 63 and the Outstanding Equity Awards at Fiscal Year-End for 2014 table on page 66.
(3)   The amounts shown in this column are annual incentive compensation paid under the Senior Officer Incentive Plan for the year shown. At the outset of each year, the HR Committee sets annual incentive targets and performance criteria that are used after year-end to determine if and the extent to which executive officers may receive annual incentive award payments under this plan.

 

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(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 the Company’s financial statements. See the Pension Benefits for 2014 table on page 69, and related footnotes for additional information. See Note 8 to the Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2014 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 2014 include: (a) Company contributions to the Company’s Retirement Savings Plan, (b) Company contributions to the Company’s Supplemental Retirement Savings Plan and (c) perquisites. The amounts are listed in the following table:

 

Type


   Nicholas K.
Akins


     Brian X.
Tierney


     Robert P.
Powers


     David M.
Feinberg


     Lana L.
Hillebrand


 

Retirement Savings Plan Match

   $ 11,373       $ 11,700       $ 11,700       $ 11,700       $ 11,700   

Supplemental Retirement Savings Plan Match

   $ 78,300       $ 58,843       $ 58,843       $ 40,097       $ 31,873   

Perquisites

   $ 13,287       $ 11,905       $ 12,163       $ 11,496       $ 12,329   

Total

   $ 102,960       $ 82,448       $ 82,706       $ 63,293       $ 55,902   

 

       Perquisites provided in 2014 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). None of the individual perquisites had a value exceeding $25,000 for a named executive officer.
(6)   Ms. Hillebrand has an agreement with the Company pursuant to which we paid her $464,000 in 2012 to offset the loss of near-term compensation payments that she forfeited by coming to work at the Company. In addition, she was granted an additional $310,000 in RSUs in 2013 to offset the loss of stock units that she forfeited when she left her prior employer.

 

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Grants of Plan-Based Awards for 2014

 

The following table provides information on plan-based awards granted in 2014 to each of our named executive officers.

 

Name


  Grant
Date
Approval(1)


    Grant
Date


    Estimated Future
Payouts Under Non-Equity
Incentive Plan Awards(2)


    Estimated Future
Payouts Under
Equity Incentive Plan
Awards(4)


    All Other
Stock
Awards:
Number of
Shares of
Stock or
Units
(#)(7)


    Grant Date
Fair

Value of
Stock and
Option
Awards
($)(8)


 
      Threshold
($)


    Target
($)


    Maximum
($)(3)


    Threshold
(#)(5)


    Target
(#)


    Maximum
(#)(6)


     

Nicholas K. Akins

                                                                               

2014 Senior Officer Incentive Plan

                    —          1,543,789        3,859,473                                           

2014 – 2016 Performance Units

    12/10/13        1/1/14                                15,286        101,907        203,814                4,704,027   

Restricted Stock Units

    12/10/13        1/1/14                                                        43,674        2,015,992   

Brian X. Tierney

                                                                               

2014 Senior Officer Incentive Plan

                    —          553,706        1,384,265                                           

2014 – 2016 Performance Units

    12/10/13        1/1/14                                4,279        28,529        57,058                1,316,899   

Restricted Stock Units

    12/10/13        1/1/14                                                        12,226        564,352   

Robert P. Powers

                                                                               

2014 Senior Officer Incentive Plan

                    —          553,706        1,384,265                                           

2014 – 2016 Performance Units

    12/10/13        1/1/14                                4,279        28,529        57,058                1,316,899   

Restricted Stock Units

    12/10/13        1/1/14                                                        12,226        564,352   

David M. Feinberg(8)

                                                                               

2014 Senior Officer Incentive Plan

                    —          367,936        919,840                                           

2014 – 2016 Performance Units

    12/10/13        1/1/14                                2,189        14,596        29,192                673,751   

Restricted Stock Units

    12/10/13        1/1/14                                                        6,255        288,731   

Lana L. Hillebrand

                                                                               

2014 Senior Officer Incentive Plan

                    —          292,976        732,440                                           

2014 – 2016 Performance Units

    12/10/13        1/1/14                                2,040        13,601        27,202                627,822   

Restricted Stock Units

    12/10/13        1/1/14                                                        5,829        269,067   

(1)   On December 10, 2013, the HR Committee and the independent members of the Board of Directors approved performance unit awards and restricted stock units, effective January 1, 2014, under our Long-Term Incentive Plan. The performance and vesting period for performance unit awards is January 1, 2014 through December 31, 2016. The restricted stock units vest in three equal installments on May 1, 2015, May 1, 2016 and May 1, 2017.
(2)   Represents potential payouts under the Senior Officer Incentive Plan (SOIP), which are based on base earnings paid during the year.
(3)   The amounts shown in this column represent 250 percent of the target award for each of the named executive officers.
(4)   Represents performance units awarded under our Long-Term Incentive Plan for the 2014-2016 performance period. These awards generally vest at the end of the three year performance period based on our attainment of specified performance measures. For further information on these awards, see the description under 2014 Stock Award Grants below. The number of performance units does not include additional units that may accrue due to dividend credits.
(5)   The amounts shown in the Threshold column represent 15% of the target award for each of the named executive officers because the Operating Earnings Per Share measure has a 30% payout for threshold performance, the Total Shareholder Return measure has a 0% payout for threshold performance and these measures are equally weighted. However, the Operating Earnings Per Share threshold does not guarantee a minimum payout because the score would be 0% of target if threshold performance is not achieved.
(6)   The amounts shown in this column represent 200 percent of the target award for each of the named executive officers.
(7)   Represents restricted stock units awarded under the Long-Term Incentive Plan. These awards generally vest in three equal installments on May 1, 2015, May 1, 2016 and May 1, 2017. The number of restricted stock units does not include additional units that may accrue due to dividend credits.

 

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(8)   Amount represents the grant date fair value of performance units and restricted stock units measured in accordance with the guidance in FASB ASC Topic 718, utilizing the assumptions discussed in Note 15 to our consolidated financial statements for the fiscal year ended December 31, 2014, without taking into account estimated forfeitures. With respect to performance units, the grant date fair value assumes the target number of performance units granted will vest. The actual number of performance units earned will depend on AEP’s performance over the 2014 through 2016 period, which could vary from 0 percent to 200 percent of the target award plus dividend credits. The value of performance units earned will be equal to AEP’s average closing share price for the last 20 trading days of the performance period multiplied by the number of performance units earned.

 

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

 

2014 Stock Award Grants.    Effective January 1, 2014, the named executive officers were granted long-term incentive awards as part of AEP’s regular annual grant cycle. These awards were granted with double trigger change in control provisions that provide early vesting of awards in the event of a change in control and a covered separation from service. Of these awards, 70 percent were granted in the form of performance units for the 2014-2016 three-year performance period that generally vest, subject to the participant’s continued AEP employment, at the end of the performance period. Performance units are generally equivalent in value to shares of AEP common stock. Dividend equivalents are reinvested in additional performance units with the same vesting conditions as the underlying performance units.

 

The 2014-2016 performance units, including the dividend credits, are subject to two equally weighted performance measures for the three-year performance period, which are:

 

   

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

 

   

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

 

These performance measures are described in detail in Compensation Discussion and Analysis-Performance Units beginning on page 52. The scores for these performance measures determine the percentage of the performance units earned at the end of the performance period and can range from zero percent to 200 percent of the target. Generally, recipients must remain employed by AEP through the end of the vesting period to receive a payout. For further information, see Potential Payments Upon Termination of Employment or Change in Control beginning on page 74.

 

The remaining 30 percent of AEP’s long-term incentive awards were granted in the form of RSUs that generally vest, subject to the executive officer’s continued employment, in three equal installments on May 1, 2015, May 1, 2016 and May 1, 2017. Generally, recipients must remain employed by AEP through the vesting date to receive a payout for the RSUs that vest on such date. Upon vesting, the RSUs pay out in cash to executive officers. For further information, see Potential Payments Upon Termination of Employment or Change in Control beginning on page 74.

 

Employment Agreements.

 

Mr. Powers has an agreement with the Company, which credits him with 17 additional years of service under AEP’s Supplemental Benefit Plan. In 1997, the Company granted additional years of credited service to Mr. Powers when he joined AEP to offset pension benefits that he would have been able to earn from his prior employer due to his length of service at that company. For further information on this, see note (2) under Pension Benefits for 2014 on page 69.

 

Ms. Hillebrand has an agreement with the Company pursuant to which the Company paid her $464,000 in 2012 to offset the loss of near-term compensation payments that she forfeited by coming to work at the Company. In addition, she was granted an additional $310,000 in RSUs on February 26, 2013 to offset the loss of stock units that she forfeited when she left her prior employer. One-third of these restricted stock units vested on May 1, 2014. The remaining restricted stock units will vest in equal amounts on May 1, 2015 and May 1, 2016. Ms. Hillebrand’s agreement also provides her a payment of one times her annual salary plus her target annual incentive opportunity if she terminates her employment for good reason as defined in her agreement. For further information, see Potential Payments Upon Termination of Employment or Change in Control beginning on page 74.

 

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Outstanding Equity Awards at Fiscal Year-End for 2014

 

The following table provides information with respect to holdings of restricted stock units and performance units by the named executive officers at December 31, 2014. The named executive officers do not have any outstanding stock options.

 

     Stock Awards

 

Name


   Number of
Shares or
Units of
Stock That
Have Not
Vested (#)


     Market
Value of
Shares or
Units of
Stock
That
Have Not
Vested
($)


     Equity Incentive
Plan Awards:
Number of
Unearned
Shares, Units
or Other
Rights That
Have
Not Vested
(#)


     Equity Incentive
Plan Awards:
Market or
Payout Value
of Unearned
Shares,
Units or
Other Rights
That Have Not
Vested ($)(1)


 

Nicholas K. Akins

                                   

2013 – 2015 Performance Units(2)

                       108,965         13,232,710   

2014 – 2016 Performance Units(2)

                       105,840         12,853,210   

Restricted Stock Units(3)

     16,840         1,022,525                     

2012 Restricted Stock Units(4)

     16,812         1,020,825                     

2013 Restricted Stock Units(5)

     31,133         1,890,396                     

2014 Restricted Stock Units(6)

     45,360         2,754,259                     

Brian X. Tierney

                                   

2013 – 2015 Performance Units(2)

                       30,695         3,727,601   

2014 – 2016 Performance Units(2)

                       29,630         3,598,267   

Restricted Stock Units(3)

     16,840         1,022,525                     

2012 Restricted Stock Units(4)

     6,933         420,972                     

2013 Restricted Stock Units(5)

     8,770         532,514                     

2014 Restricted Stock Units(6)

     12,698         771,023                     

Robert P. Powers

                                   

2013 – 2015 Performance Units(2)

                       30,695         3,727,601   

2014 – 2016 Performance Units(2)

                       29,630         3,598,267   

Restricted Stock Units(3)

     16,840         1,022,525                     

2012 Restricted Stock Units(4)

     6,933         420,972                     

2013 Restricted Stock Units(5)

     8,770         532,514                     

2014 Restricted Stock Units(6)

     12,698         771,023                     

David M. Feinberg

                                   

2013 – 2015 Performance Units(2)

                       15,347         1,863,740   

2014 – 2016 Performance Units(2)

                       15,159         1,840,909   

2012 Restricted Stock Units(4)

     3,350         203,412                     

2013 Restricted Stock Units(5)

     4,385         266,257                     

2014 Restricted Stock Units(6)

     6,496         394,437                     

Lana L. Hillebrand

                                   

2013 – 2015 Performance Units(2)

                       13,560         1,646,726   

2014 – 2016 Performance Units(2)

                       14,126         1,715,461   

2013 Restricted Stock Units(5)

     8,662         525,957                     

2014 Restricted Stock Units(6)

     6,054         367,599                     

(1)   Pursuant to applicable SEC rules, the market value of the performance units reported in this column was computed by multiplying the closing price of AEP’s common stock on December 31, 2014 ($60.72) by the maximum number of performance units issuable (200% of the target amount set forth in the preceding column) because the payout for the 2012-2014 performance units was above target. However, the actual number of performance units credited upon vesting will be based on AEP’s actual performance over the applicable three year period.
(2)   AEP currently grants performance units at the beginning of each year with a three-year performance and vesting period. This results in awards for overlapping successive three-year performance periods. These awards generally vest at the end of the three year performance period. The performance units awarded for the 2012 – 2014 performance period vested at December 31, 2014 and are shown in the Options Exercises and Stock Vested for 2014 table below. The awards shown for the 2013 – 2015 and 2014 – 2016 performance periods include performance units resulting from reinvested dividends which are subject to the same performance criteria.
(3)   These restricted stock units were granted on August 3, 2010 in connection with a CEO transition plan and include restricted stock units resulting from reinvested dividends. These remaining units will vest, subject to the executive officer’s continued employment, on August 3, 2015.

 

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(4)   Amounts include restricted stock units resulting from reinvested dividends. They will vest, subject to the executive officer’s continued employment, on May 1, 2015. These restricted stock units were granted on January 25, 2012. Mr. Feinberg also was granted 600 restricted stock units pursuant to the promotional award program that were approved by the HR Committee on February 26, 2013.
(5)   Amounts include restricted stock units resulting from reinvested dividends. They will vest, subject to the executive officer’s continued employment, in two equal installments, on May 1, 2015 and May 1, 2016. These restricted stock units were granted on February 26, 2013.
(6)   These restricted stock units were granted on December 10, 2013 and include restricted stock units resulting from reinvested dividends. They will vest, subject to the executive officer’s continued employment, in three equal installments, on May 1, 2015, May 1, 2016 and May 1, 2017.

 

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Option Exercises and Stock Vested for 2014

 

The following table provides information with respect to the vesting of RSUs and performance units granted to our named executive officers. The named executive officers did not exercise any stock options in 2014.

 

     Option Awards

     Stock Awards

 

Name


   Number
of Shares
Acquired
on
Exercise
(#)


     Value
Realized
on
Exercise
($)


     Number
of Shares
Acquired
on
Vesting
(#)(1)


     Value
Realized
on
Vesting ($)
(2)


 

Nicholas K. Akins

                     164,743         9,561,992   

Brian X. Tierney

                     78,885         4,507,663   

Robert P. Powers

                     78,549         4,489,912   

David M. Feinberg

                     29,457         1,731,498   

Lana L. Hillebrand

                     4,212         222,520  

(1)   This column includes the following performance units for the 2012 – 2014 performance period that vested on December 31, 2014: 111,820 for Mr. Akins; 46,110 for Mr. Tierney; 46,110 for Mr. Powers; and 22,216 for Mr. Feinberg. This column also includes the following RSUs that vested on May 2, 2014: 36,392 for Mr. Akins; 16,244 for Mr. Tierney; 15,908 for Mr. Powers; 7,241 for Mr. Feinberg; and 4,212 for Ms. Hillebrand. This column also includes 16,531 RSUs that vested on August 4, 2014 for Messrs. Akins, Powers and Tierney.
(2)   As is required, the value included in this column for the 2012-2014 performance units is computed by multiplying the number of units by the market value of these units on the vesting date of December 31, 2014 ($60.72). However, the actual value realized from these units was based on the 20-day average closing market price of AEP common stock prior to the vesting date ($59.582). 20,262 of Mr. Feinberg’s vested performance units ($1,230,309 of the value set forth in the table) were deferred into AEP Career Shares on February 13, 2015. For a description of AEP Career Shares, see discussion under Stock Ownership Requirements on page 53. This column also includes the value of RSUs that vested on May 2, 2014 and August 4, 2014, which had a market value of $52.83 per share and $51.40 per share, respectively.

 

2012 – 2014 Performance Units

 

Performance units that were granted for the 2012 – 2014 performance period vested on December 31, 2014. The combined score for the 2012-2014 performance period was 147.8 percent of target. The final score calculation for these performance measures is shown in the chart below.

 

Performance Measures


  Threshold
Performance


  Target
Performance


  Maximum
Payout
Performance


  Actual
Performance


  Score

  Weight

  Weighted
Score


 

3-Year Cumulative

Earnings Per Share

  $8.73

(0% payout)

  $9.73

(100% Payout)

  $10.703

(200% Payout)

  $9.849   112.3%   50%     56.1%   

3-Year Total

Shareholder Return vs.

S&P Electric Utilities

  20th

Percentile

(0% Payout)

  50th

Percentile

(100% Payout)

  80th

Percentile

(200% Payout)

  75th

Percentile

  183.3%   50%     91.7%   

Composite Result

                            147.8

 

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Pension Benefits for 2014

 

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

 

Name


  

Plan Name


   Number of
Years
Credited
Service (#)


     Present Value
of
Accumulated
Benefit($)(1)


     Payments
During
Last
Fiscal
Year($)


 

Nicholas K Akins

   AEP Retirement Plan      32.6              523,800         —     
     CSW Executive Retirement Plan      32.6              896,992         —     

Brian X. Tierney

   AEP Retirement Plan      16.7              283,925         —     
     AEP Supplemental Benefit Plan      16.7              945,942         —     

Robert P. Powers

   AEP Retirement Plan      16.5              558,763         —     
     AEP Supplemental Benefit Plan      33.5  (2)         4,312,303         —     

David M. Feinberg

   AEP Retirement Plan      3.7              49,115         —     
     AEP Supplemental Benefit Plan      3.7              99,440         —     

Lana L. Hillebrand

   AEP Retirement Plan      19.6  (3)         340,825         —     
     AEP Supplemental Benefit Plan      19.6              83,849         —     

(1)   The Present Value of Accumulated Benefits is based on the benefit accrued under the applicable plan through December 31, 2014, and the following assumptions (which are consistent with those used in AEP’s financial statements):

 

   

The named executive officer retires at age 65 (or, for Mr. Tierney and Mr. Powers, retires at age 62), and commences the payment of benefits (the “accrued benefit”).

 

   

The value of the annuity benefit at the named executive officer’s assumed retirement age is determined based upon the accrued benefit, an assumed interest rate of 4.00 percent, 3.90 percent and 3.90 percent for the benefits accrued under the AEP Retirement Plan, AEP Supplemental Benefit Plan and the CSW Executive Retirement Plan, respectively, and assumed mortality based upon modified versions of the RP-2014 mortality tables. The value of the lump sum benefit at that assumed retirement age is determined based upon the accrued benefit, an assumed interest rate of 5.00 percent and assumed mortality based on the 2015 IRS Applicable Mortality table. The present value of both the annuity benefit and the lump sum benefit at each executive’s current age is based upon an assumed interest rate of 4.00 percent, 3.90 percent and 3.90 percent for the benefits accrued under the AEP Retirement Plan, AEP Supplemental Benefit Plan and CSW Executive Retirement Plan, respectively.

 

   

The present value of the accrued benefit is weighted based on 75 percent lump sum and 25 percent annuity (or 40 percent lump sum and 60 percent annuity for Mr. Powers due to his eligibility for early retirement under the final average pay benefit formula), based on the assumption that participants elect those benefit options in that proportion.

 

(2)   Mr. Powers has a letter agreement with AEP that credits him with years of service in addition to his actual years of service with AEP. Pursuant to that agreement, the Company credited 17 additional years of service to Mr. Powers when he joined AEP in 1997 to offset pension benefits that he would have been able to earn from his prior employer due to his length of service at that company. The additional years of service credit have augmented the present value of his accumulated benefits under the AEP Supplemental Benefit Plan by $2,551,893.
(3)  

The benefit available to Ms. Hillebrand from the AEP Retirement Plan consists of two pieces: one under the Central and South West Corporation Cash Balance Retirement Plan (the “CSW Retirement Plan”) attributable to her prior period of service between December 15, 1982 and June 30, 2000 (her “CSW Retirement Plan Benefit”) and one under the cash balance formula

 

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since her return on December 17, 2012. Her CSW Retirement Plan Benefit will be paid to her either as a lump sum or in one of the annuity options offered by the plan. The amount available to her as a lump sum would be the greater of (i) her CSW Retirement Plan cash balance account ($203,163 as of December 31, 2014), or (ii) the lump sum value of her CSW Retirement Plan protected minimum normal retirement annuity (which had accrued during the 14.5 year period until her traditional pension formula benefit became frozen effective July 1, 1997), calculated using a factor based on then applicable interest and mortality assumptions as well as an assumed future cost of living adjustment rate of 3.00%. The payment available to her as an annuity would be based on the greater of (i) her CSW Retirement Plan protected minimum normal retirement annuity ($3,279 per month) or (ii) the life annuity equivalent of her then CSW Retirement Plan cash balance account, calculated using a factor based on then applicable interest and mortality assumptions.

 

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

 

AEP Retirement Plan.    The AEP Retirement Plan is a tax-qualified defined benefit pension plan under which benefits are generally determined by reference to a cash balance formula. The AEP Retirement Plan also encompasses the Central and South West Corporation Cash Balance Retirement Plan (the “CSW Retirement Plan”), which was merged into the AEP Retirement Plan effective December 31, 2008. As of December 31, 2014, each of the named executive officers was vested in their AEP Retirement Plan benefit.

 

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

 

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

 

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

 

Sum of Age Plus

Years of Service


   Applicable
Percentage


 

Less than 30

     3.0

30-39

     3.5

40-49

     4.5

50-59

     5.5

60-69

     7.0

70 or more

     8.5

 

Each year, the IRS calculates a limit on the amount of eligible pay that can be used to calculate pension benefits in a qualified plan. For 2014, the limit was $260,000.

 

  2.   Interest Credits.    All amounts in the cash balance accounts earn interest at the average interest rate on 30-year Treasury securities for the month of November of the prior year, with a floor of 4 percent. For 2014, the interest rate was 4 percent.

 

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

 

Grandfathered AEP Participants may become entitled to a subsidized benefit under the final average pay formula if they would retire early (that is, once they have remained employed past age 55 with at least three years of service). The benefit payable under the final average pay formula would be unreduced if it commences at age 62 or later and is reduced by 3 percent for each year prior to age 62 that the benefits are commenced. Mr. Powers is eligible for such early retirement benefits.

 

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

 

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

 

Participants do not become vested in their AEP Supplemental Plan benefit until they become vested in their AEP Retirement Plan benefit or upon a change in control. As of December 31, 2014, each of the named executive officers, was fully vested in their AEP Supplemental Benefit Plan benefit.

 

CSW Executive Retirement Plan.    The CSW Executive Retirement Plan is a nonqualified defined benefit pension plan. It generally provides eligible participants with benefits that are in excess of those provided under the terms of the former CSW Retirement Plan (which was merged into the AEP Retirement Plan) as determined upon the participant’s termination of employment. The excess benefits are calculated without regard to the limitations imposed by the Internal Revenue Code on annual compensation and annual benefits. As of December 31, 2014, Mr. Akins was fully vested in his CSW Executive Retirement Plan benefit.

 

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Nonqualified Deferred Compensation for 2014

 

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

 

Name


   Plan
Name(1)


   Executive
Contributions
in Last FY(2)
($)


     Registrant
Contributions
in Last FY(3)
($)


     Aggregate
Earnings
in Last
FY(4)
($)


     Aggregate
Withdrawals/
Distributions
($)


     Aggregate
Balance at
Last FYE(5)
($)


 

Nicholas K. Akins

   SRSP      104,400         78,300         49,129         —           1,146,372   
     ICDP      —           —           25,036         —           297,139   
     SORP      1,121,500         —           1,467,134         —           5,871,642   

Brian X. Tierney

   SRSP      78,458         58,843         489,615         —           2,753,913   
     SORP      —           —           262,031         —           1,048,757   

Robert P. Powers

   SRSP      78,458         58,843         423,959         —           3,175,292   
     ICDP      —           —           54,097         —           914,513   
     SORP      —           —           736,969         —           2,949,578   

David M. Feinberg

   SRSP      53,463         40,097         6,782         —           219,314   
     SORP      400,370         —           133,379         —           533,749   

Lana L. Hillebrand

   SRSP      42,498         31,873         2,538         —           99,625   
     SORP      —           —           —           —           0   

(1)   “SRSP” is the American Electric Power System Supplemental Retirement Savings Plan. “ICDP” is the American Electric Power System Incentive Compensation Deferral Plan. “SORP” is the American Electric Power System Stock Ownership Requirement Plan.
(2)   The amounts set forth under “Executive Contributions in Last FY” for the SRSP are reported in the Summary Compensation Table as either (i) Salary for 2014 or (ii) the Non-Equity Incentive Plan Compensation for 2013.
(3)   The amounts set forth under “Registrant Contributions in Last FY” for the SRSP are reported in the All Other Compensation column of the Summary Compensation Table.
(4)   No amounts set forth under “Aggregate Earnings in Last FY” have been reported in the Summary Compensation Table as there were no above market or preferential earnings credited to any named executive officer’s account in any of the plans.
(5)   The amounts set forth in the “Aggregate Balance at Last FYE” column for the SRSP include the SRSP amounts reported in the “Executive Contributions in Last FY” and “Registrant Contributions in Last FY” columns. In addition, the “Aggregate Balance at Last FYE” for the SRSP includes the following amounts previously reported in the Summary Compensation Table for prior years: $448,756 for Mr. Akins, $625,284 for Mr. Tierney, $662,269 for Mr. Powers, $116,147 for Mr. Feinberg and $22,575 for Ms. Hillebrand. The amounts set forth in the “Aggregate Balance at Last FYE” for the SORP include the SORP amounts reported in the “Executive Contributions in Last FY.” In addition, the “Aggregate Balance at Last FYE” for the SORP includes the following amounts previously reported in the Summary Compensation Table for prior years: $1,548,919 for Mr. Akins, $5,297 for Mr. Tierney and $4,980 for Mr. Powers.

 

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

 

   

The American Electric Power System Supplemental Retirement Savings Plan;

 

   

The American Electric Power System Incentive Compensation Deferral Plan; and

 

   

The American Electric Power System Stock Ownership Requirement Plan.

 

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

 

   

Participants can defer up to 50 percent of their base salary and annual incentive award in excess of the IRS’ eligible compensation limit for qualified plans, which was $260,000 for 2014, up to $2,000,000.

 

   

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

 

   

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

 

   

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

 

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

 

   

AEP does not offer any matching contributions.

 

   

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

 

   

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

 

Stock Ownership Requirement Plan.    This plan assists executives in achieving their minimum stock ownership requirements. It does this primarily by tracking the executive’s AEP Career Shares. AEP Career Shares are a form of deferred compensation, which are unfunded and unsecured general obligations of AEP. The rate of return on AEP Career Shares is equivalent to the

 

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total return on AEP stock with dividends reinvested. Participants may not withdraw any amount credited to their account until their termination of employment with AEP. AEP Career Shares are paid in cash. Participants may elect to take distribution of their AEP Career Shares in the same manner as described above for the Supplemental Retirement Savings Plan.

 

Potential Payments Upon Termination of Employment or Change in Control

 

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

 

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

 

   

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

 

   

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

 

   

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

 

   

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

 

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

 

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

 

Severance-Eligible executives may continue financial counseling and tax preparation services for one year following their termination up to a maximum annual incremental cost to the Company for 2014 of $12,380 plus related incidental expenses of the advisor.

 

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In addition, Ms. Hillebrand has an agreement that entitles her to a payment of one times her annual salary plus her target annual incentive opportunity if she terminates her employment because her duties are changed without her consent, provided that her termination is not a Qualifying Termination (as defined in the Company’s long-term incentive awards). See Change in Control below. Payment is conditioned upon her releasing AEP from all claims, including claims for any other severance benefits.

 

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

 

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

 

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

 

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

 

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

 

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

 

  (v)   a material violation of any of the rules of conduct of behavior of the Company;

 

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

 

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

 

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

 

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

 

If benefits under the Executive Severance Plan are triggered, the affected named executive officers would receive pay continuation of two times their base salary and target annual incentive payable over two years. In addition, a pro-rated portion of their outstanding performance units and

 

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restricted stock units would vest. The pro-rated performance units will not become payable until the end of the performance period and remain subject to all performance objectives. Any severance benefits payable under the Executive Severance Plan are conditioned on the execution of an agreement by the executive officer releasing claims against the Company and committing to a non-competition obligation.

 

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

 

   

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

 

   

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

 

   

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

 

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

 

   

A lump sum payment equal to 2.99 or 2.0, as applicable, times the named executive officer’s annual base salary plus target annual incentive compensation award under the annual incentive program as in effect at the time of termination; and

 

   

Outplacement services.

 

In December 2013, the HR Committee amended all of the Company’s change in control agreements to eliminate the provision that provided a tax gross-up for excise taxes.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

  (iv)   Insubordination;

 

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

 

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

 

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

 

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

 

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

 

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

 

Termination Scenarios

 

The following tables show the incremental compensation and benefits that would have been paid to each named executive officer who was employed by AEP on December 31, 2014 assuming the hypothetical circumstances cited in each column occurred on December 31, 2014 and calculated in accordance with the methodology required by the SEC. In connection with any actual termination or change of control transaction, the Company may enter into agreements or establish arrangements that provide additional benefits or amounts, or may alter the terms of benefits described below.

 

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With respect to annual incentive compensation for the completed year, the initial calculated annual incentive opportunity is shown, (before any discretionary adjustment), which varies from the actual value paid and reported in the Summary Compensation Table on page 61.

 

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

 

No information is provided for terminations due to disability because it is not AEP’s practice to terminate the employment of any employee so long as they remain eligible for AEP’s long-term disability benefits. AEP successively provides sick pay and then long-term disability benefits for up to two years to employees with a disability that prevents them from returning to their job. Such disability benefits continue (generally until the employee reaches age 65) for employees that cannot perform any occupation for which they are reasonably qualified. Because disabled participants remain employed by the Company, they continue to vest in long-term incentive awards while they are disabled. AEP treats a participant’s disability as a termination to the extent required by the regulations issued under Internal Revenue Code Section 409A, but such terminations only trigger the payment of benefits that had previously vested. In addition, restricted stock unit awards granted effective on or after January 1, 2011 allow participants terminated due to disability to continue to vest as if their employment had continued.

 

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Potential Incremental Compensation and Benefits

That Would Have Been Provided as the Result of Employment Termination

as of December 31, 2014

For Nicholas K. Akins

 

Executive Benefits and Payments
Upon Termination


   Resignation
or Retirement


     Severance

     Involuntary
Termination
for Cause


     Change-In-
Control


     Death

 

Compensation:

                                            

Base Salary ($1,236,000)

   $ 0       $ 2,472,000       $ 0       $ 3,695,640       $ 0   

Annual Incentive for Completed Year(1)

   $ 2,820,502       $ 2,820,502       $ 0       $ 2,820,502       $ 2,820,502   

Other Payment for Annual Incentives(2)

   $ 0       $ 3,090,000       $ 0       $ 4,619,550       $ 0   

Long-Term Incentives:(3)

                                            

2013-2015 Performance Units(4)

   $ 0       $ 4,410,903       $ 0       $ 6,616,355       $ 4,410,903   

2014-2016 Performance Units(4)

   $ 0       $ 2,142,202       $ 0       $ 6,426,605       $ 2,142,202   

Restricted Stock Units

   $ 0       $ 340,842       $ 0       $ 1,022,525       $ 1,022,525   

2012 Restricted Stock Units

   $ 0       $ 691,838       $ 0       $ 1,020,825       $ 1,020,825   

2013 Restricted Stock Units

   $ 0       $ 749,252       $ 0       $ 1,890,396       $ 1,890,396   

2014 Restricted Stock Units

   $ 0       $ 826,278       $ 0       $ 2,754,259       $ 2,754,259   

Benefits:

                                            

Financial Counseling

   $ 0       $ 12,380       $ 0       $ 12,380       $ 12,380   

Outplacement Services(5)

   $ 0       $ 28,000       $ 0       $ 28,000       $ 0   

Total Incremental Compensation and Benefits

   $ 2,820,502       $ 17,584,197       $ 0       $ 30,907,037       $ 16,073,992   

 

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

 

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Potential Incremental Compensation and Benefits

That Would Have Been Provided as the Result of Employment Termination

as of December 31, 2014

For Brian X. Tierney

 

Executive Benefits and Payments Upon
Termination


   Resignation
or Retirement


     Severance

     Involuntary
Termination
for Cause


     Change-In-
Control


     Death

 

Compensation:

                                            

Base Salary ($692,675)

   $ 0       $ 1,385,350       $ 0       $ 2,071,098       $ 0   

Annual Incentive for Completed Year(1)

   $ 1,011,620       $ 1,011,620       $ 0       $ 1,011,620       $ 1,011,620   

Other Payment for Annual Incentives(2)

   $ 0       $ 1,108,280       $ 0       $ 1,656,879       $ 0   

Long-Term Incentives:(3)

                                            

2013-2015 Performance Units(4)

   $ 0       $ 1,242,534       $ 0       $ 1,863,800       $ 1,242,534   

2014-2016 Performance Units(4)

   $ 0       $ 599,711       $ 0       $ 1,799,134       $ 599,711   

Restricted Stock Units

   $ 0       $ 340,842       $ 0       $ 1,022,525       $ 1,022,525   

2012 Restricted Stock Units

   $ 0       $ 285,287       $ 0       $ 420,972       $ 420,972   

2013 Restricted Stock Units

   $ 0       $ 211,063       $ 0       $ 532,514       $ 532,514   

2014 Restricted Stock Units

   $ 0       $ 231,307       $ 0       $ 771,023       $ 771,023   

Benefits:

                                            

Financial Counseling

   $ 0       $ 12,380       $ 0       $ 12,380       $ 12,380   

Outplacement Services(5)

   $ 0       $ 28,000       $ 0       $ 28,000       $ 0   

Total Incremental Compensation and Benefits

   $ 1,011,620       $ 6,456,374       $ 0       $ 11,189,945       $ 5,613,279   

 

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

 

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Potential Incremental Compensation and Benefits

That Would Have Been Provided as the Result of Employment Termination

as of December 31, 2014

For Robert P. Powers

 

Executive Benefits and Payments Upon
Termination


   Resignation
or Retirement


     Severance

     Involuntary
Termination
for Cause


     Change-In-
Control


     Death

 

Compensation:

                                            

Base Salary ($692,675)

   $ 0       $ 1,385,350       $ 0       $ 2,071,098       $ 0   

Annual Incentive for Completed Year(1)

   $ 1,011,620       $ 1,011,620       $ 0       $ 1,011,620       $ 1,011,620   

Other Payment for Annual Incentives(2)

   $ 0       $ 1,108,280       $ 0       $ 1,656,879       $ 0   

Long-Term Incentives:(3)

                                            

2013-2015 Performance Units(4)

   $ 1,242,534       $ 1,242,534       $ 0       $ 1,863,800       $ 1,242,534   

2014-2016 Performance Units(4)

   $ 599,711       $ 599,711       $ 0       $ 1,799,134       $ 599,711   

Restricted Stock Units

   $ 0       $ 340,842       $ 0       $ 1,022,525       $ 1,022,525   

2012 Restricted Stock Units

   $ 0       $ 285,287       $ 0       $ 420,972       $ 420,972   

2013 Restricted Stock Units

   $ 0       $ 211,063       $ 0       $ 532,514       $ 532,514   

2014 Restricted Stock Units

   $ 0       $ 231,307       $ 0       $ 771,023       $ 771,023   

Benefits:

                                            

Financial Counseling

   $ 0       $ 12,380       $ 0       $ 12,380       $ 12,380   

Outplacement Services(5)

   $ 0       $ 28,000       $ 0       $ 28,000       $ 0   

Total Incremental Compensation and Benefits

   $ 2,853,865       $ 6,456,374       $ 0       $ 11,189,945       $ 5,613,279   

 

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

 

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Potential Incremental Compensation and Benefits

That Would Have Been Provided as the Result of Employment Termination

as of December 31, 2014

For David M. Feinberg

 

Executive Benefits and Payments Upon
Termination


   Resignation
or Retirement


     Severance

     Involuntary
Termination
for Cause


     Change-In-
Control


     Death

 

Compensation:

                                            

Base Salary ($566,500)

   $ 0       $ 1,133,000       $ 0       $ 1,693,835       $ 0   

Annual Incentive for Completed Year(1)

   $ 672,219       $ 672,219       $ 0       $ 672,219       $ 672,219   

Other Payment for Annual Incentives(2)

   $ 0       $ 736,450       $ 0       $ 1,100,993       $ 0   

Long-Term Incentives:(3)

                                            

2013-2015 Performance Units(4)

   $ 0       $ 621,247       $ 0       $ 931,870       $ 621,247   

2014-2016 Performance Units(4)

   $ 0       $ 306,818       $ 0       $ 920,454       $ 306,818   

2012 Restricted Stock Units

   $ 0       $ 136,219       $ 0       $ 203,412       $ 203,412   

2013 Restricted Stock Units

   $ 0       $ 105,523       $ 0       $ 266,257       $ 266,257   

2014 Restricted Stock Units

   $ 0       $ 118,331       $ 0       $ 394,437       $ 394,437   

Benefits:

                                            

Financial Counseling

   $ 0       $ 12,380       $ 0       $ 12,380       $ 12,380   

Outplacement Services(5)

   $ 0       $ 28,000       $ 0       $ 28,000       $ 0   

Total Incremental Compensation and Benefits

   $ 672,219       $ 3,870,187       $ 0       $ 6,223,857       $ 2,476,770   

 

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

 

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Potential Incremental Compensation and Benefits

That Would Have Been Provided as the Result of Employment Termination

as of December 31, 2014

For Lana L. Hillebrand

 

Executive Benefits and Payments Upon
Termination


   Resignation
or Retirement


     Severance

     Involuntary
Termination
for Cause


     Change-In-
Control


     Death

 

Compensation:

                                            

Base Salary ($488,800)

   $ 0       $ 977,600       $ 0       $ 977,600       $ 0   

Annual Incentive for Completed Year(1)

   $ 535,268       $ 535,268       $ 0       $ 535,268       $ 535,268   

Other Payment for Annual Incentives(2)

   $ 0       $ 586,560       $ 0       $ 586,560       $ 0   

Long-Term Incentives:(3)

                                            

2013-2015 Performance Units(4)

   $ 0       $ 548,909       $ 0       $ 823,363       $ 548,909   

2014-2016 Performance Units(4)

   $ 0       $ 285,910       $ 0       $ 857,731       $ 285,910   

2013 Restricted Stock Units

   $ 0       $ 208,440       $ 0       $ 525,957       $ 525,957   

2014 Restricted Stock Units

   $ 0       $ 110,280       $ 0       $ 367,599       $ 367,599   

Benefits:

                                            

Financial Counseling

   $         $ 12,380       $ 0       $ 12,380       $ 12,380   

Outplacement Services(5)

   $ 0       $ 28,000       $ 0       $ 28,000       $ 0   

Total Incremental Compensation and Benefits

   $ 532,268       $ 3,293,347       $ 0       $ 4,714,458       $ 2,276,023   

(1)   Executive officers and all other employees are eligible for an annual incentive award based on their earnings for the year if they remain employed with AEP through year-end, if they die or if they incur a retirement-eligible termination. The amount shown is based on the calculated annual incentive opportunity, as shown on page 51, but all annual incentives for executive officers are awarded at the discretion of the HR Committee or independent members of the Board pursuant to the award determination process described in the Compensation Discussion and Analysis.
(2)   Represents a payment of two times the applicable target annual incentive opportunity in the event of a severance. Represents a payment of 2.99 times the applicable target annual incentive opportunity for each of the named executive officers, other than Ms. Hillebrand whose multiple was 2.0, in the event of a change in control. Ms. Hillebrand’s target multiple was increased to 2.99 effective January 1, 2015.
(3)   The long-term incentive values shown represent the values that would be paid under such circumstances shown in each column, which are different from the values calculated in accordance with FASB ASC Topic 718.
(4)   The target value of performance unit awards are shown. The actual value paid in the event of resignation or retirement, severance or death, if any, will depend on the actual performance score for the full performance period. Any payments for awards under those circumstances are not paid until the end of the three year performance period. In the event of a qualifying termination in connection with a change in control, awards would be paid at a target performance score as soon as administratively practical after the change in control.
(5)   Represents the maximum cost of Company paid outplacement services, which the Company provides through an unaffiliated third party vendor.

 

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The following table shows the value of previously earned and vested compensation and benefits as of December 31, 2014, that would have been provided to each named executive officer following a termination of his or her employment on December 31, 2014. In all cases, these amounts were generally earned or vested over multiple years of service to the Company.

 

Non-Incremental Post-Termination Compensation and Benefits on December 31, 2014

 

Name


   Long-Term Incentives

     Benefits

        
   Vested
Performance
Units
(1)


     AEP Career
Shares
(2)


     Vacation
Payout
(3)


     Post Retirement
Benefits
(4)


     Deferred
Compensation
(5)


 

Nicholas K. Akins

   $ 6,789,710       $ 5,983,774       $ 43,269       $ 1,366,812       $ 1,443,511   

Brian X. Tierney

   $ 2,799,799       $ 1,068,793       $ 26,642       $ 944,853       $ 2,753,913   

Robert P. Powers

   $ 2,799,799       $ 3,005,944       $ 31,250       $ 3,973,161       $ 4,089,805   

David M. Feinberg

   $ 1,348,956       $ 543,930       $ 21,788       $ 142,383       $ 219,314   

Lana L. Hillebrand

   $ 0       $ 0       $ 17,860       $ 374,846       $ 99,625   

(1)   Represents the value of performance units that vested on December 31, 2014 calculated using the market value of these shares on December 31, 2014. However, the actual value realized or deferred to AEP Career Shares from these performance units in February 2015 was based on the 20-day average closing market price of AEP common stock prior to the vesting date.
(2)   Represents the value of AEP share equivalents deferred mandatorily into AEP’s Stock Ownership Requirement Plan calculated using the market value of these shares on December 31, 2014. However, the actual value that would have been realized from these AEP share equivalents would have been determined using the 20-day average closing market price of AEP common stock prior to the date of termination.
(3)   Represents accumulated but unused vacation.
(4)   Represents the lump sum benefit calculated for the named executive officer pursuant to the terms of the AEP Retirement Plan, AEP Supplemental Benefit Plan and CSW Executive Retirement Plan, as applicable.
(5)   Includes balances from the Supplemental Retirement Savings Plan and Incentive Compensation Deferral Plans, but does not include AEP Career Share balances, which are listed separately in column (2).

 

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Share Ownership of Directors and Executive Officers

 

The following table sets forth the beneficial ownership of AEP Common Stock and stock-based units as of February 19, 2015 for all Directors, director nominees, each of the persons named in the Summary Compensation Table and all Directors and executive officers as a group.

 

Unless otherwise noted, each person had sole voting and investment power over the number of shares of AEP Common Stock set forth across from his or her name. Fractions of shares and units have been rounded to the nearest whole number.

 

Name


   Shares(a)

    Stock
Units(b)


     Total(c)

 

N. K. Akins

     41,103        98,547         139,650   

D. J. Anderson

     0        12,430         12,430   

J. B. Beasley, Jr

     0        2,471         2,741   

R. D. Crosby, Jr.

     0        33,266         33,266   

D. M. Feinberg

     0        29,220         29,220   

L. A. Goodspeed

     0        34,069         34,069   

L. L. Hillebrand

     0        0         0   

T. Hoaglin

     1,000        27,285         28,285   

S. B. Lin

     1,000        7,635         8,635   

R. C. Notebaert

     0        12,430         12,430   

L. L. Nowell III

     0        37,965         37,965   

R. P. Powers

     1,000        72,743         73,743   

R. S. Rasmussen

     0        7,087         7,087   

O. G. Richard III

     2,195        5,936         8,131   

B. X. Tierney

     9,226        40,490         49,716   

S. M. Tucker

     1,532 (d)      23,025         24,557   

All directors, nominees and executive officers as a group (20 persons)

     61,435 (e)      533,926         595,361   

(a)   None of the shares is pledged. This column also includes share equivalents held in the AEP Retirement Savings Plan.
(b)   This column includes amounts deferred in stock units and held under the Stock Unit Accumulation Plan for Non-Employee Directors and amounts deferred in share equivalents in the Retainer Deferral Plan for Non-Employee Directors. This column also includes amounts deferred in share equivalents held under AEP’s Supplemental Retirement Savings Plan, AEP’s Incentive Compensation Deferral Plan and the following numbers of AEP Career Shares: Mr. Akins, 98,547; Mr. Feinberg, 29,220; Mr. Powers, 49,505; Mr. Tierney, 17,602; and all directors and executive officers as a group, 278,294.
(c)   This column does not include restricted stock units that will not vest within 60 days.
(d)   Includes 32 shares held by family members of Ms. Tucker over which she disclaims beneficial ownership.
(e)   As of February 19, 2015, the directors and executive officers as a group beneficially owned less than one percent of the outstanding shares of the Company’s common stock.

 

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Section 16(a) Beneficial Ownership Reporting Compliance

 

Section 16(a) of the Exchange Act requires AEP’s executive officers, directors and persons who beneficially own more than 10 percent of AEP’s Common stock to file initial reports of ownership and reports of changes in ownership of AEP Common Stock with the SEC. Executive officers and directors are required by SEC regulations to furnish AEP with copies of all reports they file. Based solely on a review of the copies of such reports furnished to AEP and written representations from AEP’s executive officers and directors during the fiscal year ended December 31, 2014, AEP believes that all of its directors and executive officers timely met all of their respective Section 16(a) filing requirements during 2014.

 

Share Ownership of Certain Beneficial Owners

 

Set forth below are the only persons or groups known to AEP as of February 15, 2015, with beneficial ownership of five percent or more of AEP Common Stock.

 

     AEP Shares

 

Name and Address of

Beneficial Owner


   Amount of
Beneficial
Ownership


    Percent of
Class


 

BlackRock, Inc.

55 East 52nd Street

New York, NY 10022

     36,630,319 (a)      7.5

The Vanguard Group

100 Vanguard Boulevard

Malvern, PA 19355

     28,625,824 (b)      5.85

State Street Corporation

One Lincoln Street

Boston, MA 02111

     25,957,263 (c)      5.3

(a)   Based on the Schedule 13G filed with the SEC, BlackRock, Inc. reported that it has sole power to vote 31,390,091 shares and sole dispositive power for 36,630,319 shares.
(b)   Based on the Schedule 13G filed with the SEC, The Vanguard Group reported that it has sole power to vote 872,858 shares, sole dispositive power for 27,819,338 shares and shared dispositive power for 806,486 shares.
(c)   Based on the Schedule 13G filed with the SEC, State Street Corporation reported that it has shared voting power to vote 25,957,263 shares and shared dispositive power for 25,957,263 shares.

 

Shareholder Proposals and Nominations

 

To be included in AEP’s proxy statement and form of proxy for the 2016 annual meeting of shareholders, any proposal which a shareholder intends to present at such meeting must be received by AEP, attention: Thomas G. Berkemeyer, Assistant Secretary, at AEP’s office at 1 Riverside Plaza, Columbus, OH 43215 by November 14, 2015.

 

Notice to nominate a director must include your name, address, and number of shares you own; the name, age, business address, residence address and principal occupation of the nominee and the number of shares beneficially owned by the nominee. It must also include all the information required in AEP’s Policy on Consideration of Candidates for Director Recommended by Shareholders. A copy of this Policy is posted on our website at www.aep.com/investors/corporateleadersandgovernance. All such notices must be received by AEP, attention: Thomas G. Berkemeyer, Assistant Secretary, at AEP’s office at 1 Riverside Plaza, Columbus, OH 43215 by November 14, 2015. The Assistant Secretary will forward the recommendations to the Committee on Directors and Corporate Governance for consideration.

 

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For any proposal intended to be presented by a shareholder without inclusion in AEP’s proxy statement and form of proxy for the 2016 annual meeting, the proxies named in AEP’s form of proxy for that meeting will be entitled to exercise discretionary authority on that proposal unless AEP receives notice of the matter by January 25, 2016. However, even if notice is timely received, the proxies may nevertheless be entitled to exercise discretionary authority on the matter to the extent permitted by SEC regulations.

 

Solicitation Expenses

 

These proxies are being solicited by our Board of Directors. The costs of this proxy solicitation will be paid by AEP. Proxies will be solicited principally by mail and the Internet, but some telephone or personal solicitations of holders of AEP Common Stock may be made. Any officers or employees of the AEP System who make or assist in such solicitations will receive no additional compensation for doing so. AEP will request brokers, banks and other custodians or fiduciaries holding shares in their names or in the names of nominees to forward copies of the proxy-soliciting materials to the beneficial owners of the shares held by them, and AEP will reimburse them for their expenses incurred in doing so at rates prescribed by the New York Stock Exchange. We have engaged Morrow & Co., LLC, 470 West Ave., Stamford, Connecticut 06902, to assist us with the solicitation of proxies for an estimated fee of $34,500, plus reasonable out-of-pocket expenses.

 

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Exhibit A

 

Reconciliation of GAAP and Non-GAAP Financial Measures.

 

The Company reports its financial results in accordance with generally accepted accounting principles (“GAAP”). However, AEP’s management believes that the Company’s operating earnings provide users with additional meaningful financial information about the Company’s performance. Management also uses these non-GAAP financial measures when communicating with stock analysts and investors regarding its earnings outlook and results. Non-GAAP financial measures should be viewed in addition to, and not as an alternative for, the Company’s reported results prepared in accordance with GAAP.

 

For additional details regarding the reconciliation of GAAP and non-GAAP financial measures below, see the Company’s Current Report on Form 8-K filed with the SEC on January 28, 2015.

 

     EPS  

Operating Earnings

   $ 3.43   

Special Items

        

Mark-to-Market Hedging

     (0.01

Coal Contract Termination

     (0.08

GAAP Reported Earnings

   $ 3.34   

 

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Exhibit B

 

 

 

American Electric Power System 2015 Long-Term Incentive Plan

 

 

 

 


Table of Contents

Table of Contents

     Page  

ARTICLE 1 - ESTABLISHMENT, EFFECTIVENESS, PURPOSE AND DURATION

     B-1   

Section 1.01. Establishment.

     B-1   

Section 1.02. Effectiveness.

     B-1   

Section 1.03. Purpose of This Plan.

     B-1   

Section 1.04. Duration of This Plan.

     B-1   

ARTICLE 2 - DEFINITIONS

     B-1   

ARTICLE 3 - ADMINISTRATION

     B-4   

Section 3.01. General.

     B-4   

Section 3.02. Authority of the Committee.

     B-4   

Section 3.03 Delegation.

     B-4   

ARTICLE 4 - SHARES SUBJECT TO THIS PLAN AND MAXIMUM AWARDS

     B-5   

Section 4.01. Number of Shares Available for Awards.

     B-5   

Section 4.02. Share Usage.

     B-5   

Section 4.03. Annual Award Limits.

     B-5   

Section 4.04. Adjustments in Authorized Shares.

     B-6   

Section 4.05. Source of Shares.

     B-7   

ARTICLE 5 - ELIGIBILITY AND PARTICIPATION

     B-7   

Section 5.01. Eligibility.

     B-7   

Section 5.02. Actual Participation.

     B-7   

ARTICLE 6 - STOCK OPTIONS

     B-7   

Section 6.01. Grant of Options.

     B-7   

Section 6.02. Award Agreement.

     B-7   

Section 6.03. Option Price.

     B-7   

Section 6.04. Term of Options. Each

     B-7   

Section 6.05. Exercise of Options.

     B-7   

Section 6.06. Payment.

     B-7   

Section 6.07. Restrictions on Share Transferability.

     B-8   

Section 6.08. Termination of Employment.

     B-8   

Section 6.09. Automatic Option Exercise.

     B-8   

ARTICLE 7 - STOCK APPRECIATION RIGHTS

     B-8   

Section 7.01. Grant of SARs.

     B-8   

Section 7.02. SAR Award Agreement.

     B-8   

Section 7.03. Grant Price.

     B-9   

Section 7.04. Term of SAR.

     B-9   

Section 7.05. Exercise of SARs.

     B-9   

Section 7.06. Settlement of SARs.

     B-9   

Section 7.07. Termination of Employment.

     B-9   

Section 7.08. Other Restrictions.

     B-9   

Section 7.09. Automatic SAR Exercise.

     B-9   

ARTICLE 8 - RESTRICTED STOCK AND RESTRICTED STOCK UNITS

     B-9   

Section 8.01. Grant of Restricted Stock or Restricted Stock Units.

     B-9   

Section 8.02. Restricted Stock or Restricted Stock Unit Award Agreement.

     B-10   

Section 8.03. Other Restrictions.

     B-10   

Section 8.04. Certificate Legend.

     B-10   

Section 8.05. Voting Rights.

     B-10   

Section 8.06. Termination of Employment.

     B-10   

ARTICLE 9 - PERFORMANCE UNITS / PERFORMANCE SHARES

     B-10   

Section 9.01. Grant of Performance Units / Performance Shares.

     B-10   

Section 9.02. Value of Performance Units / Performance Shares.

     B-11   

Section 9.03. Earning of Performance Units / Performance Shares.

     B-11   

Section 9.04. Form and Timing of Payment of Performance Units / Performance Shares.

     B-11   

Section 9.05. Termination of Employment.

     B-11   

 

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ARTICLE 10 - CASH-BASED AWARDS AND OTHER STOCK-BASED AWARDS

     B-11   

Section 10.01. Grant of Cash-Based Awards.

     B-11   

Section 10.02. Other Stock-Based Awards.

     B-11   

Section 10.03. Value of Cash-Based and Other Stock-Based Awards.

     B-11   

Section 10.04. Payment of Cash-Based Awards and Other Stock-Based Awards.

     B-12   

Section 10.05. Termination of Employment.

     B-12   

ARTICLE 11 - TRANSFERABILITY OF AWARDS

     B-12   

ARTICLE 12 - PERFORMANCE MEASURES

     B-12   

Section 12.01. Awards Under This Article 12.

     B-12   

Section 12.02. Performance Goals.

     B-12   

Section 12.03. Performance Measures.

     B-12   

Section 12.04. Evaluation of Performance.

     B-13   

Section 12.05. Certification of Performance.

     B-13   

Section 12.06. Adjustment of Performance-Based Compensation.

     B-13   

Section 12.07. Committee Discretion.

     B-13   

ARTICLE 13 - DIRECTOR AWARDS

     B-13   

ARTICLE 14 - DIVIDEND EQUIVALENTS

     B-13   

ARTICLE 15 - BENEFICIARY DESIGNATION

     B-14   

ARTICLE 16 - RIGHTS OF PARTICIPANTS

     B-14   

Section 16.01. Employment.

     B-14   

Section 16.02. Participation.

     B-14   

Section 16.03. Rights as a Shareholder.

     B-14   

ARTICLE 17 - CHANGE OF CONTROL

     B-14   

17.01. Effect of Change in Control.

     B-14   

17.02. Definition of Change in Control

     B-14   

ARTICLE 18 - AMENDMENT AND TERMINATION

     B-15   

18.01 Amendment and Termination of the Plan and Awards

     B-15   

18.02 Adjustment of Awards Upon the Occurrence of Certain Unusual or Nonrecurring Events.

     B-15   

18.03 Awards Previously Granted.

     B-15   

18.04 Amendment to Conform to Law.

     B-15   

ARTICLE 19 - WITHHOLDING

     B-16   

ARTICLE 20 - SUCCESSORS

     B-16   

ARTICLE 21 - GENERAL PROVISIONS

     B-16   

Section 21.01. Forfeiture Events.

     B-16   

Section 21.02. Legend.

     B-16   

Section 21.03. Gender and Number.

     B-16   

Section 21.04. Severability.

     B-16   

Section 21.05. Requirements of Law.

     B-17   

Section 21.06. Delivery of Title.

     B-17   

Section 21.07. Inability to Obtain Authority.

     B-17   

Section 21.08. Investment Representations

     B-17   

Section 21.09. Uncertificated Shares.

     B-17   

Section 21.10. Unfunded Plan.

     B-17   

Section 21.11. No Fractional Shares.

     B-17   

Section 21.12. Retirement and Welfare Plans.

     B-17   

Section 21.13. Deferred Compensation.

     B-17   

Section 21.14. Non-exclusivity of this Plan.

     B-18   

Section 21.15. No Constraint on Corporate Action.

     B-18   

Section 21.16. Governing Law.

     B-18   

Section 21.17. Indemnification

     B-18   

Section 21.18. No Guarantee of Favorable Tax Treatment

     B-18   

 

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Table of Contents

American Electric Power System 2015 Long-Term Incentive Plan

 

ARTICLE 1 - ESTABLISHMENT, EFFECTIVENESS, PURPOSE AND DURATION

 

Section 1.01. Establishment. American Electric Power Company, Inc., a New York corporation (hereinafter referred to as the “Company”), establishes an incentive compensation plan to be known as the American Electric Power System 2015 Long-Term Incentive Plan (hereinafter referred to as this “Plan”), as set forth in this document.

 

Section 1.02. Effectiveness. This Plan shall become effective upon shareholder approval (the “Effective Date”) and shall remain in effect as provided in Section 1.04. Subject to the approval of the Company’s shareholders of this Plan, no further awards shall be granted under the Prior Plan as of the Effective Date.

 

Section 1.03. Purpose of This Plan. The purposes of the Plan are to: (a) strengthen the alignment of interests between those Employees and Directors of the Company and its Subsidiaries who share responsibility for the success of the business and those of the Company’s shareholders, (b) facilitate the use of long-term incentive compensation and the provisions of market competitive total compensation to Employees, (c) increase Employee ownership of shares of the Company’s common stock to encourage ownership behaviors, and (d) encourage Plan Participant retention. This Plan permits the grant of Nonqualified Stock Options, Incentive Stock Options, Stock Appreciation Rights, Restricted Stock, Restricted Stock Units, Performance Shares, Performance Units, Cash-Based Awards and Other Stock-Based Awards.

 

Section 1.04. Duration of This Plan. Unless sooner terminated as provided herein, this Plan shall terminate ten years from the Effective Date. After this Plan is terminated, no Awards may be granted but Awards previously granted shall remain outstanding in accordance with their applicable terms and conditions and this Plan’s terms and conditions. Notwithstanding the foregoing, no Incentive Stock Options may be granted more than ten years after the earlier of (a) adoption of this Plan by the Board, or (b) the Effective Date.

 

ARTICLE 2 - DEFINITIONS

 

Whenever used in this Plan, the following terms shall have the meanings set forth below, and when the meaning is intended, the initial letter of the word shall be capitalized.

 

Affiliate” means any corporation or other entity (including, but not limited to, a partnership or a limited liability company) that is affiliated with the Company through stock or equity ownership or otherwise, including each Subsidiary and any other corporation or entity designated as an Affiliate for purposes of this Plan by the Committee.

 

Aggregate Share Authorization” has the meaning set forth in Section 4.01.

 

Annual Award Limit” has the meaning set forth in Section 4.03.

 

Award” means, individually or collectively, a grant under this Plan of Nonqualified Stock Options, Incentive Stock Options, Stock Appreciation Rights, Restricted Stock, Restricted Stock Units, Performance Shares, Performance Units, Cash-Based Awards, or Other Stock-Based Awards, in each case subject to the terms of this Plan.

 

Award Agreement” means either (i) an agreement entered into by the Company and a Participant setting forth the terms and provisions applicable to an Award granted under this Plan, or (ii) a written or electronic statement issued by the Company to a Participant describing the terms

 

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and provisions of such Award, including any amendment or modification thereof. The Committee may provide for the use of electronic, Internet, or other non-paper Award Agreements, and the use of electronic, Internet, or other non-paper means for the acceptance thereof and actions thereunder by a Participant.

 

Board” or “Board of Directors” means the Board of Directors of the Company.

 

Cash-Based Award” means an Award, denominated in cash, granted to a Participant as described in Article 10.

 

Code” means the U.S. Internal Revenue Code of 1986, as amended from time to time. For purposes of this Plan, references to sections of the Code shall be deemed to include references to any applicable regulations or other published guidance thereunder and any successor or similar provision.

 

Committee” means the Human Resources Committee of the Board or a subcommittee thereof, or any other committee designated by the Board to administer this Plan. The members of the Committee shall be appointed from time to time by the Board. The Committee shall consist of three or more persons, each of whom qualifies as a “non-employee director” within the meaning of Rule 16b-3 of the Exchange Act and as an “outside director” within the meaning of Code Section 162 (m).

 

Company” has the meaning set forth in Section 1.01, and any successor thereto as provided in Article 21.

 

Covered Employee” means any Participant who, in the sole judgment of the Committee, could be treated as a “covered employee” under Section 162(m) at the time income may be recognized by such Participant in connection with an Award that is intended to qualify for exemption under Section 162(m).

 

Director” means any individual who is a member of the Board of Directors of the Company and who is not an Employee of the Company.

 

Director Award” means any Award granted, whether singly, in combination, or in tandem, to a Participant who is a Director pursuant to such applicable terms, conditions, and limitations as the Board may establish in accordance with this Plan.

 

Effective Date” has the meaning set forth in Section 1.02.

 

Employee” means any individual designated as an employee of the Company, its Affiliates, and/or its Subsidiaries on any of their payroll records.

 

Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time. For purposes of this Plan, references to sections of the Exchange Act shall be deemed to include references to any applicable regulations or other published guidance thereunder and any successor or similar provision.

 

Fair Market Value” or “FMV” means a price that is based on the opening, closing, actual, high, low, or average selling prices of a Share reported on the New York Stock Exchange (“NYSE”) or other established stock exchange (or exchanges) on the applicable date, the preceding trading day, the next succeeding trading day, or an average of trading days, as determined by the Committee in its discretion. Unless the Committee determines otherwise or unless otherwise specified in an Award Agreement, Fair Market Value shall be the closing price of a Share on the date in question (or, if there is no reported sale on such date, on the last preceding date on which

 

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Table of Contents

Shares were publicly traded). In the event that Shares are not publicly traded at the time a determination of their value is required to be made hereunder, the determination of their Fair Market Value shall be made by the Committee in such manner as it deems appropriate.

 

Full Value Award” means an Award other than an Award in the form of a Nonqualified Stock Option, Incentive Stock Option or Stock Appreciation Right, and which is settled by the issuance of Shares.

 

Grant Price” means the price established at the time of grant of an SAR pursuant to Article 7, used to determine whether there is any payment due upon exercise of the SAR.

 

Incentive Stock Option” or “ISO” means an Option to purchase Shares granted under Article 6 to an Employee that is designated as an Incentive Stock Option and intended to meet the requirements of Code Section 422.

 

Nonqualified Stock Option” or “NQSO” means an Option that is not intended to meet the requirements of Code Section 422, or that otherwise does not meet such requirements.

 

Option” means an Incentive Stock Option or a Nonqualified Stock Option, as granted pursuant to Article 6.

 

Option Price” means the price at which a Share may be purchased by a Participant pursuant to an Option.

 

Option Term” means the period of time during which an Option is exercisable as the Committee shall determine at the time of grant; provided, however, no Option shall be exercisable later than the tenth anniversary of its grant date.

 

Other Stock-Based Award” means an equity-based or equity-related Award not otherwise described by the terms of this Plan, granted pursuant to Article 10.

 

Participant” means any eligible individual as set forth in Article 5 to whom an Award is granted.

 

Performance-Based Compensation” means compensation under an Award that is intended to satisfy the requirements of Code Section 162(m) for certain performance-based compensation paid to Covered Employees.

 

Performance Measures” means measures as described in Article 12 on which the performance goals are based and which are approved by the Company’s shareholders pursuant to this Plan in order to satisfy the requirements for Performance-Based Compensation.

 

Performance Period” means the period of time during which pre-established performance goals must be met in order to determine the degree of payout and/or vesting with respect to an Award.

 

Performance Share” means an Award granted pursuant to Article 9 that is denominated in Shares, the value of which at the time it is payable is determined based on achievement of corresponding performance criteria.

 

Performance Unit” means an Award granted under Article 9 that is denominated in dollars, the value of which at the time it is payable is determined based on achievement of corresponding performance criteria.

 

Period of Restriction” means the period when Restricted Stock or Restricted Stock Units are subject to a substantial risk of forfeiture (based on the performance of services, the achievement of performance goals, or the occurrence of other events as determined by the Committee, in its discretion), as provided in Article 8.

 

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Person” shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act and used in Sections 13(d) and 14(d) thereof, including a “group” as defined in Section 13(d) thereof.

 

Plan” has the meaning set forth in Section 1.01, as the same may be amended from time to time.

 

Plan Year” means the calendar year.

 

Prior Plan” means the Amended and Restated American Electric Power System Long-Term Incentive Plan, last approved by shareholders on April 27, 2010, as amended.

 

Prior Plan Award” means an award granted under the Prior Plan that is outstanding as of the Effective Date.

 

Restricted Stock” means an Award granted pursuant to Article 8, as set forth therein.

 

Restricted Stock Unit” means an Award granted pursuant to Article 8, as set forth therein.

 

Share” means a share of common stock of the Company.

 

Stock Appreciation Right” or “SAR” means an Award, designated as an SAR, granted pursuant to Article 7.

 

Subsidiary” means any corporation or other entity, whether domestic or foreign, in which the Company has or obtains, directly or indirectly, a proprietary interest of 50% or more by reason of stock ownership or otherwise.

 

ARTICLE 3 - ADMINISTRATION

 

Section 3.01. General. The Committee shall be responsible for administering this Plan, subject to this Article 3 and the other provisions of this Plan. The Committee may employ attorneys, consultants, accountants, agents, and other individuals, any of whom may be an Employee, and the Committee, the Company, and its officers and Directors shall be entitled to rely upon the advice, opinions, or valuations of any such individuals. All actions taken and all interpretations and determinations made by the Committee shall be final and binding upon the Participants, the Company, and all other interested persons.

 

Section 3.02. Authority of the Committee. The Committee shall have full discretionary power to interpret the terms and the intent of this Plan and any Award Agreement or other agreement or document ancillary to or in connection with this Plan, to determine eligibility for Awards and to adopt such rules, regulations, forms, instruments, and guidelines for administering this Plan as the Committee may deem necessary or proper. Such authority shall include, but not be limited to, selecting Award recipients, establishing all Award terms and conditions, including the terms and conditions set forth in Award Agreements, granting Awards as an alternative to or as the form of payment for grants or rights earned or due under compensation plans or arrangements of the Company, construing any ambiguous provision of the Plan or any Award Agreement, and, subject to Article 18, adopting modifications and amendments to this Plan or any Award Agreement, including without limitation, any that are necessary to comply with or qualify for the laws of the countries and other jurisdictions in which the Company, its Affiliates, and/or its Subsidiaries operate.

 

Section 3.03 Delegation. To the extent permitted under applicable law, the Committee may delegate to one or more of its members or to one or more employees of the Company and/or its

 

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Subsidiaries, such administrative duties or powers as it may deem advisable, and the Committee or any individuals to whom it has delegated duties or powers as aforesaid may employ one or more individuals to render advice with respect to any responsibility that the Committee or such individuals may have under this Plan. The Committee may, by resolution, authorize one or more persons who are members of the Committee, members of the Board of Directors of the Company, or an officer of the Company to do one or both of the following on the same basis as can the Committee: (a) designate Employees to be recipients of Awards; and (b) determine the size of any such Awards; provided, however, (i) the Committee shall not delegate such responsibilities to any such person for Awards granted to an Employee who is, on the relevant date, a Covered Employee or an officer or Director for purposes of Section 16 of the Exchange Act; (ii) the resolution providing such authorization sets forth the total number of Shares underlying Awards such person(s) may grant; and (iii) the person(s) shall report periodically to the Committee regarding the nature and scope of the Awards granted pursuant to the authority delegated.

 

ARTICLE 4 - SHARES SUBJECT TO THIS PLAN AND MAXIMUM AWARDS

 

Section 4.01. Number of Shares Available for Awards. (a) Subject to adjustment as provided in Section 4.04 , the maximum number of Shares available for grant to Participants under this Plan (the “Aggregate Share Authorization”) shall be 10 million Shares. No further Awards may be granted under the Prior Plan as of the Effective Date. The number of shares issuable under the Prior Plan may, however, increase due to dividend shares and performance shares issued in connection with awards outstanding under the Prior Plan.

 

(b) To the extent that a Share is issued pursuant to the grant or exercise of a Full Value Award, it shall reduce the Aggregate Share Authorization by one Share; and, to the extent that a Share is issued pursuant to the grant or exercise of an Award other than a Full Value Award, it shall reduce the Aggregate Share Authorization by 0.286 of a Share.

 

(c) The maximum number of Shares that may be issued pursuant to ISOs under this Plan shall be equal to the Aggregate Share Authorization.

 

(d) The maximum aggregate value of Awards that may be granted to any Director under this Plan during any calendar year shall not exceed $700,000, as determined by the Board based on the value of any Award at the time of grant.

 

Section 4.02. Share Usage. (a) Shares covered by an Award shall be counted as used only to the extent they are actually issued. Except as provided in Section 4.02(b), any Shares related to Awards that terminate by expiration, forfeiture, cancellation, or otherwise without the issuance of such Shares, are settled in cash in lieu of Shares, or are exchanged with the Committee’s permission (prior to the issuance of Shares) for Awards not involving Shares, shall be available again for grant under this Plan.

 

(b) Any Award Shares tendered, exchanged or withheld to cover Option exercise costs, any Award Shares withheld to cover taxes, and all Shares underlying an Award of Stock Appreciation Rights once such Stock Appreciation Rights are exercised, shall be taken into account as Shares issued under this Plan.

 

Section 4.03. Annual Award Limits. The following limits (each an “Annual Award Limit” and, collectively, “Annual Award Limits”) shall apply to grants of Awards under this Plan:

 

(a) Options. The maximum aggregate number of Shares subject to Options granted in any one Plan Year to any one Participant shall be 2,000,000.

 

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(b) SARs. The maximum aggregate number of Shares subject to Stock Appreciation Rights granted in any one Plan Year to any one Participant shall be 2,000,000.

 

(c) Restricted Stock or Restricted Stock Units. The maximum aggregate grant with respect to Awards of Restricted Stock or Restricted Stock Units in any one Plan Year to any one Participant shall be 400,000 Shares.

 

(d) Performance Units or Performance Shares. The maximum aggregate number of Performance Units or Performance Shares that a Participant may be awarded in any one Plan Year shall be 400,000 Shares. As provided in Section 9.03, up to 2 Shares (or the cash value of 2 Shares) may be issued with respect to a Performance Unit or Performance Share, depending on the level of performance, plus any applicable Dividend Equivalents.

 

(e) Cash-Based Awards. The maximum aggregate amount awarded with respect to Cash- Based Awards to any one Participant in any one Plan Year may not exceed $15,000,000, determined as of the date of payment.

 

(f) Other Stock-Based Awards. The maximum aggregate grant with respect to Other Stock- Based Awards pursuant to Section 10.02 in any one Plan Year to any one Participant shall be 400,000 Shares.

 

Section 4.04. Adjustments in Authorized Shares. (a) In the event of any corporate event or transaction (including, but not limited to, a change in the Shares or capitalization of the Company) such as a merger, consolidation, reorganization, recapitalization, separation, partial or complete liquidation, stock dividend, stock split, reverse stock split, split up, spin-off, or other distribution of stock or property of the Company, combination of Shares, exchange of Shares, dividend in kind, or other like change in capital structure, number of outstanding Shares, or distribution (other than normal cash dividends) to shareholders of the Company, or any similar corporate event or transaction, or in the event of unusual or nonrecurring events affecting the Company or the financial statements of the Company or of changes in applicable laws, regulations, or accounting principles, the Committee, in order to prevent dilution or enlargement of Participants’ rights under this Plan, shall substitute or adjust, as applicable, the number and kind of Shares that may be granted under this Plan or under particular forms of Awards, the number and kind of Shares subject to outstanding Awards, the Option Price or Grant Price applicable to outstanding Awards, the Annual Award Limits, and other value determinations applicable to outstanding Awards. The Committee, in its discretion, shall determine the methodology or manner of making such substitution or adjustment.

 

(b) The Committee, in its sole discretion, may also make appropriate adjustments in the terms of any Awards under this Plan to reflect, or that relate to, the changes or distributions described in Section 4.04 and to modify any other terms of outstanding Awards, including modifications of performance goals and changes in the length of Performance Periods. The Committee shall not make any adjustment pursuant to this Section 4.04. that would (i) prevent Performance-Based Compensation from satisfying the requirements of Code Section 162(m), (ii) cause an Award that is otherwise exempt from Code Section 409A to become subject to Section 409A, or (iii) cause an Award that is subject to Code Section 409A to fail to satisfy the requirements of Section 409A. The determination of the Committee as to the foregoing adjustments, if any, shall be conclusive and binding on Participants under this Plan.

 

(c) Subject to the provisions of Article 18 and notwithstanding anything else herein to the contrary, without affecting the number of Shares reserved or available hereunder, the Committee may authorize the issuance or assumption of benefits under this Plan in connection with any merger, consolidation, acquisition of property or stock, or reorganization upon such terms and conditions as it may deem appropriate.

 

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Section 4.05. Source of Shares. The Shares available for issuance under this Plan may be authorized and unissued Shares, treasury Shares or Shares acquired in the open market.

 

ARTICLE 5 - ELIGIBILITY AND PARTICIPATION

 

Section 5.01. Eligibility. Individuals eligible to participate in this Plan include all Employees and Directors.

 

Section 5.02. Actual Participation. Subject to the provisions of this Plan, the Committee may, from time to time, select from all eligible individuals those individuals to whom Awards shall be granted and shall determine, in its sole discretion, the nature of any and all terms permissible by law, and the amount of each Award.

 

ARTICLE 6 - STOCK OPTIONS

 

Section 6.01. Grant of Options. Subject to the terms and provisions of this Plan, Options may be granted to Participants in such number, and upon such terms, and at any time and from time to time as shall be determined by the Committee, in its sole discretion; provided that ISOs may be granted only to eligible Employees of the Company or of any parent or subsidiary corporation (to the extent permitted under Code Sections 422 and 424).

 

Section 6.02. Award Agreement. Each Option grant shall be evidenced by an Award Agreement that shall specify the Option Price, the maximum duration of the Option, the number of Shares to which the Option pertains, the conditions upon which an Option shall become vested and exercisable, and such other provisions as the Committee shall determine which are not inconsistent with the terms of this Plan.

 

Section 6.03. Option Price. The Option Price for each grant of an Option under this Plan shall be determined by the Committee in its sole discretion and shall be specified in the Award Agreement; provided, however, the Option Price must be at least equal to 100% of the FMV of Shares on the date of grant, subject to adjustment as provided for in Section 4.04.

 

Section 6.04. Term of Options. Each Option granted to a Participant shall expire at such time as the Committee shall determine and set forth in the Award Agreement at the time of grant; provided, however, no Option shall be exercisable later than the tenth anniversary date of its grant.

 

Section 6.05. Exercise of Options. Options granted under this Article 6 shall be exercisable at such times and be subject to such restrictions and conditions as the Committee shall in each instance approve, which terms and restrictions need not be the same for each grant or for each Participant; provided, however, that no Option shall be exercisable within one (1) year from its grant date, except in the case of the death of a Participant.

 

Section 6.06. Payment. (a) Subject to Section 6.09, Options granted under this Article 6 shall be exercised by the delivery of a notice of exercise to the Company or an agent designated by the Company in a form specified or accepted by the Committee, or by complying with any alternative procedures which may be authorized by the Committee, setting forth the number of Shares with respect to which the Option is to be exercised, accompanied by full payment for the Shares. The Shares shall become the property of the Participant on the exercise date, subject to any forfeiture conditions specified in the Option.

 

(b) A condition of the issuance of the Shares as to which an Option shall be exercised shall be the payment of the Option Price at the time of the exercise. The Option Price of any Option shall

 

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be payable to the Company in full either (i) in cash or its equivalent; (ii) by tendering (either by actual delivery or attestation) previously acquired Shares having an aggregate Fair Market Value at the time of exercise equal to the Option Price; (iii) by a cashless (broker-assisted) exercise; (iv) by a combination of (i), (ii) and/or (iii); or (v) any other method approved or accepted by the Committee in its sole discretion. Unless otherwise determined by the Committee, all payments under all of the methods indicated above shall be paid in United States dollars.

 

(c) Subject to any governing rules or regulations, as soon as practicable after receipt of written notification of exercise and full payment (including satisfaction of any applicable tax withholding), the Company shall deliver or cause to be delivered to the Participant a statement of holdings as evidence of book entry uncertificated Shares, or at the sole discretion of the Committee upon the Participant’s request, Share certificates in an appropriate amount based upon the number of Shares purchased under the Option(s).

 

Section 6.07. Restrictions on Share Transferability. The Committee may impose such restrictions on any Shares acquired pursuant to the exercise of an Option granted under this Article 6 as it may deem advisable, including, without limitation, minimum holding period requirements, restrictions under applicable federal securities laws, under the requirements of any stock exchange or market upon which such Shares are then listed and/or traded, or under any blue sky or state securities laws applicable to such Shares.

 

Section 6.08. Termination of Employment. Each Participant’s Award Agreement shall set forth the extent, if any, to which the Participant shall have the right to exercise the Option following termination of the Participant’s employment or provision of services to the Company, its Affiliates, and/or its Subsidiaries, as the case may be. Such provisions shall be determined in the sole discretion of the Committee, shall be included in the Award Agreement entered into with each Participant, need not be uniform among all Options granted pursuant to this Article 6, and may reflect distinctions based on the reasons for termination.

 

Section 6.09. Automatic Option Exercise. An Award Agreement may provide that if, on the last day of the term of an Option, the Fair Market Value of one Share exceeds the Option Price plus associated fees, if the Participant has not exercised the Option, and the Option has not otherwise expired, the Option shall be deemed to have been exercised by the Participant on such day. In such event, the Company shall deliver Shares to the Participant in accordance with this Section 6.09, reduced by the number of Shares required for payment of the exercise price and for payment of withholding taxes; any fractional Share shall be settled in cash.

 

ARTICLE 7 - STOCK APPRECIATION RIGHTS

 

Section 7.01. Grant of SARs. Subject to the terms and conditions of this Plan, SARs may be granted to Participants at any time and from time to time as shall be determined by the Committee. Subject to the terms and conditions of this Plan, the Committee shall have complete discretion in determining the number of SARs granted to each Participant and, consistent with the provisions of this Plan, the terms and conditions pertaining to such SARs.

 

Section 7.02. SAR Award Agreement. Each SAR grant shall be evidenced by an Award Agreement that shall specify the Grant Price, the maximum duration of the SAR, the number of Shares to which the SAR pertains, the conditions upon which an SAR shall become vested and exercisable, and such other provisions as the Committee shall determine which are not inconsistent with the terms of this Plan.

 

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Section 7.03. Grant Price. The Grant Price for each grant of an SAR shall be determined by the Committee and shall be specified in the Award Agreement; provided, however, the Grant Price on the date of grant must be at least equal to 100% of the FMV of the Shares as determined on the date of grant.

 

Section 7.04. Term of SAR. The term of an SAR granted under this Plan shall be determined by the Committee, in its sole discretion, and set forth in the Award Agreement at the time of grant; provided, however, that no SAR shall be exercisable later than the tenth anniversary date of its grant.

 

Section 7.05. Exercise of SARs. SARs granted under this Article 7 shall be exercisable at such times and be subject to such restrictions and conditions as the Committee shall in each instance approve, which terms and restrictions need not be the same for each grant or for each Participant; provided, however, that no SAR shall be exercisable within one (1) year from its grant date, except in the case of the death of a Participant.

 

Section 7.06. Settlement of SARs. Upon the exercise of an SAR, a Participant shall be entitled to receive payment from the Company on the exercise date in an amount determined by multiplying: (a) the excess of the Fair Market Value of a Share on the date of exercise over the Grant Price; by (b) the number of Shares with respect to which the SAR is exercised.

 

At the discretion of the Committee, the payment upon SAR exercise may be in cash, Shares, or any combination thereof, or in any other manner approved by the Committee in its sole discretion. The Committee’s determination regarding the form of SAR payout shall be set forth in the Award Agreement pertaining to the grant of the SAR.

 

Section 7.07. Termination of Employment. Each Award Agreement shall set forth the extent to which the Participant shall have the right to exercise the SAR following termination of the Participant’s employment with or provision of services to the Company, its Affiliates, and/or its Subsidiaries, as the case may be. Such provisions shall be determined in the sole discretion of the Committee, shall be included in the Award Agreement entered into with Participants, need not be uniform among all SARs granted pursuant to this Article 7, and may reflect distinctions based on the reasons for termination.

 

Section 7.08. Other Restrictions. The Committee shall impose such other conditions and/or restrictions on any Shares received upon exercise of an SAR granted pursuant to this Plan as it may deem advisable or desirable. These restrictions may include, but shall not be limited to, a requirement that the Participant hold the Shares received upon exercise of an SAR for a specified period of time.

 

Section 7.09. Automatic SAR Exercise. An Award Agreement may provide that if, on the last day of the term of an SAR, the Fair Market Value of one Share exceeds the Grant Price of the SAR plus associated fees, if the Participant has not exercised the SAR, and the SAR has not otherwise expired, the SAR shall be deemed to have been exercised by the Participant on such day. In such event, the Company shall deliver payment to the Participant in accordance with the terms of settlement set forth in Section 7.06.

 

ARTICLE 8 - RESTRICTED STOCK AND RESTRICTED STOCK UNITS

 

Section 8.01. Grant of Restricted Stock or Restricted Stock Units. Subject to the terms and provisions of this Plan, the Committee, at any time and from time to time, may grant Shares of Restricted Stock and/or Restricted Stock Units to Participants in such amounts as the Committee shall determine. Restricted Stock Units shall be similar to Restricted Stock except that no Shares are actually awarded to the Participant on the date of grant.

 

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Section 8.02. Restricted Stock or Restricted Stock Unit Award Agreement. Each Restricted Stock and/or Restricted Stock Unit grant shall be evidenced by an Award Agreement that shall specify the Period (s) of Restriction, the number of Shares of Restricted Stock or the number of Restricted Stock Units granted, and such other provisions as the Committee shall determine.

 

Section 8.03. Other Restrictions. (a) The Committee shall impose such other conditions and/or restrictions on any Shares of Restricted Stock or Restricted Stock Units granted pursuant to this Plan as it may deem advisable including, without limitation, a requirement that Participants pay a stipulated purchase price for each Share of Restricted Stock or each Restricted Stock Unit, restrictions based upon the achievement of specific performance goals, time-based restrictions on vesting following the attainment of the performance goals, time-based restrictions, and/or restrictions under applicable laws or under the requirements of any stock exchange or market upon which such Shares are listed or traded, or holding requirements or sale restrictions placed on the Shares by the Company upon vesting of such Restricted Stock or Restricted Stock Units.

 

(b) To the extent deemed appropriate by the Committee, the Company may retain any certificates or statements of holdings representing Shares of Restricted Stock in the Company’s possession until such time as all conditions and/or restrictions applicable to such Shares have been satisfied or lapse.

 

(c) Except as otherwise provided in this Article 8, Shares of Restricted Stock covered by each Restricted Stock Award shall become freely transferable by the Participant after all conditions and restrictions applicable to such Shares have been satisfied or lapse (including satisfaction of any applicable tax withholding obligations), and Restricted Stock Units shall be paid in cash, Shares, or a combination of cash and Shares as the Committee, in its sole discretion, shall determine.

 

Section 8.04. Certificate Legend. In addition to any legends placed on certificates or statements of holdings pursuant to Section 8.03, each certificate or statement of holdings representing Shares of Restricted Stock granted pursuant to this Plan may bear a legend restricting the transfer of such Shares.

 

Section 8.05. Voting Rights. Unless otherwise determined by the Committee and set forth in a Participant’s Award Agreement, to the extent permitted or required by law, as determined by the Committee, Participants holding Shares of Restricted Stock granted hereunder may be granted the right to exercise full voting rights with respect to those Shares during the Period of Restriction. A Participant shall have no voting rights with respect to any Restricted Stock Units granted hereunder.

 

Section 8.06. Termination of Employment. Each Award Agreement shall set forth the extent to which the Participant shall have the right to retain Restricted Stock and/or Restricted Stock Units following termination of the Participant’s employment with or provision of services to the Company, its Affiliates, and/or its Subsidiaries, as the case may be. Such provisions shall be determined in the sole discretion of the Committee, shall be included in the Award Agreement entered into with each Participant, need not be uniform among all Shares of Restricted Stock or Restricted Stock Units granted pursuant to this Article 8, and may reflect distinctions based on the reasons for termination.

 

ARTICLE 9 - PERFORMANCE UNITS / PERFORMANCE SHARES

 

Section 9.01. Grant of Performance Units / Performance Shares. Subject to the terms and provisions of this Plan, the Committee, at any time and from time to time, may grant Performance Units and/or Performance Shares to Participants in such amounts and upon such terms as the Committee shall determine.

 

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Section 9.02. Value of Performance Units / Performance Shares. Each Performance Unit shall have an initial value that is established by the Committee at the time of grant. Each Performance Share shall have an initial value equal to the Fair Market Value of a Share on the date of grant. The Committee shall set performance goals in its discretion which, depending on the extent to which they are met, will determine the value and/or number of Performance Units/Performance Shares that will be paid out to the Participant.

 

Section 9.03. Earning of Performance Units / Performance Shares. Subject to the terms of this Plan, after the applicable Performance Period has ended, the holder of Performance Units/Performance Shares shall be entitled to receive payout as provided in Section 9.04 on the value and number of Performance Units/Performance Shares earned by the Participant over the Performance Period, to be determined as a function of the extent to which the corresponding performance goals have been achieved. Regardless of the level of performance achieved, in no event will the number of Shares issued (or the amount of cash paid) with respect to a Performance Unit/Performance Share exceed 2 Shares (or the value of 2 Shares), plus any applicable Dividend Equivalents.

 

Section 9.04. Form and Timing of Payment of Performance Units / Performance Shares. Payment of earned Performance Units/Performance Shares shall be as determined by the Committee and as evidenced in the Award Agreement. Any Shares may be granted subject to any restrictions deemed appropriate by the Committee. The determination of the Committee with respect to the form of payout of such Awards shall be set forth in the Award Agreement pertaining to the grant of the Award.

 

Section 9.05. Termination of Employment. Each Award Agreement shall set forth the extent to which the Participant shall have the right to retain Performance Units and/or Performance Shares following termination of the Participant’s employment with or provision of services to the Company, its Affiliates, and/or its Subsidiaries, as the case may be. Such provisions shall be determined in the sole discretion of the Committee, shall be included in the Award Agreement entered into with each Participant, need not be uniform among all Awards of Performance Units or Performance Shares awarded pursuant to this Article 9, and may reflect distinctions based on the reasons for termination.

 

ARTICLE 10 - CASH-BASED AWARDS AND OTHER STOCK-BASED AWARDS

 

Section 10.01. Grant of Cash-Based Awards. Subject to the terms and provisions of the Plan, the Committee, at any time and from time to time, may grant Cash-Based Awards to Participants in such amounts and upon such terms as the Committee may determine.

 

Section 10.02. Other Stock-Based Awards. The Committee may grant other types of equity-based or equity-related Awards not otherwise described by the terms of this Plan (including the grant or offer for sale of unrestricted Shares) in such amounts and subject to such terms and conditions as the Committee shall determine. Such Awards may involve the transfer of actual Shares to Participants, or payment in cash or otherwise of amounts based on the value of Shares and may include, without limitation, Awards designed to comply with or take advantage of the applicable local laws of jurisdictions other than the United States.

 

Section 10.03. Value of Cash-Based and Other Stock-Based Awards. Each Cash-Based Award shall specify a payment amount or payment range as determined by the Committee. Each Other Stock- Based Award shall be expressed in terms of Shares or units based on Shares, as determined by the Committee. The Committee may establish performance goals in its discretion. If the Committee exercises its discretion to establish performance goals, the number and/or value of Cash-Based Awards or Other Stock-Based Awards that will be paid out to the Participant will depend on the extent to which the performance goals are met.

 

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Section 10.04. Payment of Cash-Based Awards and Other Stock-Based Awards. Payment, if any, with respect to a Cash-Based Award or an Other Stock-Based Award shall be made in accordance with the terms of the Award, in cash or Shares as the Committee determines.

 

Section 10.05. Termination of Employment. The Committee shall determine the extent to which the Participant shall have the right to receive Cash-Based Awards or Other Stock-Based Awards following termination of the Participant’s employment with or provision of services to the Company, its Affiliates, and/or its Subsidiaries, as the case may be. Such provisions shall be determined in the sole discretion of the Committee. Such provisions may be included in the Award Agreement, but need not be uniform among all Awards of Cash-Based Awards or Other Stock-Based Awards granted pursuant to this Article 10, and may reflect distinctions based on the reasons for termination.

 

ARTICLE 11 - TRANSFERABILITY OF AWARDS

 

Except to the extent specifically provided by the terms of an Award Agreement, Awards shall be nontransferable. During the lifetime of a Participant, Awards shall be exercised only by such Participant or by his guardian or legal representative. Notwithstanding the foregoing, the Committee may provide in the terms of an Award Agreement that the Participant shall have the right to designate a beneficiary or beneficiaries who shall be entitled to any rights, payments or other benefits specified under an Award Agreement following the Participant’s death.

 

ARTICLE 12 - PERFORMANCE MEASURES

 

Section 12.01. Awards Under This Article 12. If an Award (other than an Option or SAR) is intended to qualify as Performance-Based Compensation, the Award shall be granted in accordance with the terms of this Article 12 and shall vest or be paid solely on account of the attainment of an objective performance goal based on one or more of the Performance Measures listed in Section 12.03.

 

Section 12.02. Performance Goals. The Committee shall establish the performance goal in writing not later than 90 days after the commencement of the Performance Period (or, if earlier, before 25% of the Performance Period has elapsed), and at a time when the outcome of the performance goal is still substantially uncertain. The performance goal shall state, in terms of an objective formula or standard, the method for determining the amount of compensation payable to the Participant if the performance goal is attained.

 

Section 12.03. Performance Measures. (a) The Performance Measures used to establish performance goals for Performance-Based Compensation shall be limited to the following business measures, which may be applied with respect to AEP, any Subsidiary or any business unit, and which may be measured on an absolute or relative-to-peer-group basis: earnings measures (including, for example, primary earnings per share, fully diluted earnings per share, operating earnings per share, net income, pre-tax income, operating income, earnings before interest, taxes, depreciation and amortization or any combination thereof, and net operating profits after taxes); expense control (including, for example, operations & maintenance expense, total expenditures, expense ratios, and expense reduction); customer measures (including, for example, customer satisfaction, service cost, service levels, responsiveness, bad debt collections or losses, and reliability—such as outage frequency, outage duration, and frequency of momentary outages); safety measures (including, for example, recordable case rate, severity rate, fatalities, and vehicle accident rate); diversity measures (including, for example, female and minority placement utilization rates); environmental measures (including, for example, emissions, project completion milestones, regulatory/legislative/cost recovery goals, and notices of violation), revenue measures

 

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(including, for example, revenue, direct margin and net margin); stakeholder return measures (including, for example, total shareholder return, economic value added, cumulative shareholder value added, return on equity, return on capital, return on assets, dividend payout ratio and cash flow(s) – such as operating cash flows, free cash flow, discounted cash flow return on investment and cash flow in excess of cost of capital or any combination thereof); valuation measures (including, for example, stock price increase, price to book value ratio, and price to earnings ratio); capital and risk measures (including, for example, debt to equity ratio, dividend payout as percentage of net income and diversification of business opportunities); employee satisfaction and engagement; project measures (including, for example, completion of key milestones); production measures (including, for example, generating capacity factor, performance against the INPO index, generating equivalent availability, heat rates, effective forced outage rates and production cost); and such other individual performance objective that is measured solely in terms of quantitative targets related to the Company, any Subsidiary or the Company’s or Subsidiary’s business.

 

(b) Any Performance Measure(s) may be used in a quantitative manner to measure the performance of the Company, Subsidiary, and/or Affiliate as a whole or any business unit of the Company, Subsidiary, and/or Affiliate or any combination thereof, as the Committee may deem appropriate. Any of the above Performance Measures may be used to measure performance relative to specified performance levels; a group of comparator companies; a published or special index that the Committee, in its sole discretion, deems appropriate; or various stock market indices. The Committee also has the authority to provide for accelerated vesting of any Award based on the achievement of a performance goal or goals pursuant to the Performance Measures specified in this Article 12.

 

Section 12.04. Evaluation of Performance. Any Performance Measure(s) may be made subject to pre-specified adjustments to remove the effects of restructurings, dispositions, changes in tax or accounting rules, or similar non-recurring or extraordinary events to the extent consistent with the requirements of Code Section 162(m) for Performance-Based Compensation.

 

Section 12.05. Certification of Performance. No vesting or payment shall occur under an Award that is intended to qualify as Performance-Based Compensation until the Committee certifies that the performance goal and any other material terms of the Award have been satisfied.

 

Section 12.06. Adjustment of Performance-Based Compensation. Awards that are intended to qualify as Performance-Based Compensation may not be adjusted upward. The Committee shall retain the discretion to adjust such Awards downward, either on a formula or discretionary basis or any combination, as the Committee determines.

 

Section 12.07. Committee Discretion. For the avoidance of doubt, in the event that the Committee determines that it is advisable to grant Awards that shall not qualify as Performance-Based Compensation, the Committee may make such grants without satisfying the requirements of Code Section 162(m) and the terms of this Article 12. In such event, among other things, the Committee may base the vesting or payment of such Awards on performance measures other than those set forth in Section 12.03.

 

ARTICLE 13 - DIRECTOR AWARDS

 

Subject to Section 4.01(d), the Board shall determine all Awards to Directors. The terms and conditions of any grant to any such Director shall be set forth in an Award Agreement.

 

ARTICLE 14 - DIVIDEND EQUIVALENTS

 

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dividend payment dates, during the period between the date on which the Full Value Award is granted and the date on which the Award vests or expires, as determined by the Committee. Such dividend equivalents shall be converted to cash or additional Shares by such formula and at such time and subject to such limitations as may be determined by the Committee; provided that such dividend equivalents shall be subject to any performance conditions that apply to the underlying Award. Participants shall not accrue, be granted or be paid any dividends or dividend equivalents with respect to Shares that are subject to any Option or Stock Appreciation Right.

 

ARTICLE 15 - BENEFICIARY DESIGNATION

 

In the absence of any applicable beneficiary designation, benefits remaining unpaid or rights remaining unexercised at the Participant’s death shall be paid to or exercised by the Participant’s executor, administrator, or legal representative on behalf of the Participant’s estate.

 

ARTICLE 16 - RIGHTS OF PARTICIPANTS

 

Section 16.01. Employment. (a) Nothing in this Plan or an Award Agreement shall interfere with or limit in any way the right of the Company, its Affiliates, and/or its Subsidiaries to terminate any Participant’s employment or service on the Board or to the Company at any time or for any reason not prohibited by law, nor confer upon any Participant any right to continue his employment or service as a Director for any specified period of time.

 

(b) Neither an Award nor any benefits arising under this Plan shall constitute an employment contract with the Company, its Affiliates, and/or its Subsidiaries.

 

Section 16.02. Participation. No individual shall have the right to be selected to receive an Award under this Plan, or, having been so selected, to be selected to receive a future Award.

 

Section 16.03. Rights as a Shareholder. Except as otherwise provided herein, a Participant shall have none of the rights of a shareholder with respect to Shares covered by any Award unless and until the Participant becomes the record holder of any Shares associated with such Award.

 

ARTICLE 17 - CHANGE OF CONTROL

 

17.01. Effect of Change in Control. The Committee may, in an Award Agreement, provide for the effect of a Change in Control on an Award. Such provisions may include any one or more of the following: (a) the acceleration or extension of time periods for purposes of exercising, vesting in, or realizing gain from any Award, (b) the waiver or modification of performance or other conditions related to the payment or other rights under an Award; (c) provision for the cash settlement of an Award for an equivalent cash value, as determined by the Committee, or (d) such other modification or adjustment to an Award as the Committee deems appropriate to maintain and protect the rights and interests of Participants upon or following a Change in Control.

 

17.02. Definition of Change in Control. For purposes hereof, a “Change in Control” shall be deemed to have occurred if:

 

(a) any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934 (“Exchange Act”)), other than any company owned, directly or indirectly, by the shareholders of AEP in substantially the same proportions as their ownership of shares Common Stock or a trustee or other fiduciary holding securities under an employee benefit plan of AEP, becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 33-1/3 percent of the then outstanding voting stock of AEP;

 

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(b) AEP consummates a merger or consolidation with any other entity, other than a merger or consolidation which would result in the voting securities of AEP outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 66-2/3% percent of the total voting power represented by the voting securities of AEP or such surviving entity outstanding immediately after such merger or consolidation; or

 

(c) the shareholders of AEP approve a plan of complete liquidation of AEP, or an agreement for the sale or disposition by AEP (in one transaction or a series of transactions) of all or substantially all of AEP’s assets.

 

ARTICLE 18 - AMENDMENT AND TERMINATION

 

18.01 Amendment and Termination of the Plan and Awards. (a) Subject to subparagraphs (b) and (c) of this Section 18.01 and Section 18.03 of the Plan, the Board or the Committee may at any time amend or terminate the Plan or amend or terminate any outstanding Award.

 

(b) Except as provided for in Section 4.04, the terms of an outstanding Award may not be amended, without prior shareholder approval, to: (i) reduce the Option Price of an outstanding Option or to reduce the Grant Price of an outstanding SAR, or (ii) cancel an outstanding Option or SAR in exchange for other Options or SARs with an Option Price or Grant Price, as applicable, that is less than the Option Price of the cancelled Option or the Grant Price of the cancelled SAR, as applicable, or (iii) cancel an outstanding Option with an Option Price that is less than the Fair Market Value of a Share on the date of cancellation or cancel an outstanding SAR with a Grant Price that is less than the Fair Market Value of a Share on the date of cancellation in exchange for cash or another Award.

 

(c) Notwithstanding the foregoing, no amendment of this Plan shall be made without shareholder approval if shareholder approval is required pursuant to rules promulgated by any stock exchange or quotation system on which Shares are listed or quoted or by applicable U.S. state corporate laws or regulations, applicable U.S. federal laws or regulations and the applicable laws of any foreign country or jurisdiction where Awards are, or will be, granted under the Plan.

 

18.02 Adjustment of Awards Upon the Occurrence of Certain Unusual or Nonrecurring Events. Subject to Section 12.05, the Committee may make adjustments in the terms and conditions of, and the criteria included in, Awards in recognition of unusual or nonrecurring events (including, without limitation, the events described in Section 4.04) affecting the Company or the financial statements of the Company or of changes in applicable laws, regulations, or accounting principles, whenever the Committee determines that such adjustments are appropriate in order to prevent unintended dilution or enlargement of the benefits or potential benefits intended to be made available under this Plan. The determination of the Committee as to the foregoing adjustments, if any, shall be conclusive and binding on Participants under this Plan. By accepting an Award under this Plan, a Participant agrees to any adjustment to the Award made pursuant to this Section 18.02 without further consideration or action.

 

18.03 Awards Previously Granted. Notwithstanding any other provision of this Plan to the contrary, other than Sections 18.02, 18.04 and 21.15, no termination or amendment of this Plan or an Award Agreement shall adversely affect in any material way any Award previously granted under this Plan, without the written consent of the Participant holding such Award.

 

18.04 Amendment to Conform to Law. Notwithstanding any other provision of this Plan to the contrary, the Board or Committee may amend the Plan or an Award Agreement, to take effect retroactively or otherwise, as deemed necessary or advisable for the purpose of conforming the

 

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Plan or an Award Agreement to any law relating to plans of this or similar nature, and to the administrative regulations and rulings promulgated thereunder. By accepting an Award under this Plan, a Participant agrees to any amendment made pursuant to this Section 18.04 to the Plan and any Award without further consideration or action.

 

ARTICLE 19 - WITHHOLDING

 

The Company shall have the power and the right to deduct or withhold, or require a Participant to remit to the Company, the minimum statutory amount to satisfy federal, state, and local taxes, domestic or foreign, required by law or regulation to be withheld with respect to any taxable event arising as a result of this Plan. Participants may elect to satisfy the withholding requirements, in whole or in part, by having the Company withhold shares having a Fair Market Value on the date the tax is to be determined equal to the minimum statutory total tax that could be imposed on the transaction. The Participant shall remain responsible at all times for paying any federal, state, and local income or employment tax due with respect to any Award, and the Company shall not be liable for any interest or penalty that a Participant incurs by failing to make timely payments of tax.

 

ARTICLE 20 - SUCCESSORS

 

All obligations of the Company under this Plan with respect to Awards granted hereunder shall be binding on any successor to the Company, whether the existence of such successor is the result of a direct or indirect purchase, merger, consolidation, or otherwise, of all or substantially all of the business and/or assets of the Company.

 

ARTICLE 21 - GENERAL PROVISIONS

 

Section 21.01. Forfeiture Events. (a) The Committee may specify in an Award Agreement that the Participant’s rights, payments, and benefits with respect to an Award shall be subject to reduction, cancellation, forfeiture, or recoupment upon the occurrence of certain specified events, in addition to any otherwise applicable vesting or performance conditions of an Award. Such events may include, but shall not be limited to, termination of employment for cause (as defined in the Award Agreement), termination of the Participant’s provision of services to the Company, Affiliate, and/or Subsidiary, violation of material Company, Affiliate, and/or Subsidiary policies, breach of noncompetition, confidentiality, or other restrictive covenants that may apply to the Participant, or other conduct by the Participant that is detrimental to the business or reputation of the Company, its Affiliates, and/or its Subsidiaries.

 

(b) All Awards shall be subject to the Company’s compensation recoupment policy as such policy may be in effect from time to time.

 

Section 21.02. Legend. The certificates or statements of holdings for Shares may include any legend which the Committee deems appropriate to reflect any restrictions on transfer of such Shares.

 

Section 21.03. Gender and Number. Except where otherwise indicated by the context, any masculine term used herein also shall include the feminine, the plural shall include the singular, and the singular shall include the plural.

 

Section 21.04. Severability. In the event any provision of this Plan shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of this Plan, and this Plan shall be construed and enforced as if the illegal or invalid provision had not been included.

 

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Section 21.05. Requirements of Law. The granting of Awards and the issuance of Shares under this Plan shall be subject to all applicable laws, rules, and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required.

 

Section 21.06. Delivery of Title. The Company shall have no obligation to issue or deliver evidence of title for Shares issued under this Plan prior to: (a) obtaining any approvals from governmental agencies that the Company determines are necessary or advisable; and (b) completion of any registration or other qualification of the Shares under any applicable national or foreign law or ruling of any governmental body that the Company determines to be necessary or advisable.

 

Section 21.07. Inability to Obtain Authority. The inability of the Company to obtain authority from any regulatory body having jurisdiction, which authority is deemed by the Company’s counsel to be necessary to the lawful issuance and sale of any Shares hereunder, shall relieve the Company of any liability in respect of the failure to issue or sell such Shares as to which such requisite authority shall not have been obtained.

 

Section 21.08. Investment Representations. The Committee may require any individual receiving Shares pursuant to an Award under this Plan to represent and warrant in writing that the individual is acquiring the Shares for investment and without any present intention to sell or distribute such Shares.

 

Section 21.09. Uncertificated Shares. To the extent that this Plan provides for issuance of certificates to reflect the transfer or issuance of Shares, the transfer or issuance of such Shares may be effected on a non-certificated basis, to the extent not prohibited by applicable law or the rules of any stock exchange upon which the Shares are listed.

 

Section 21.10. Unfunded Plan. Participants shall have no right, title, or interest whatsoever in or to any investments that the Company, and/or its Subsidiaries, and/or its Affiliates may make to aid it in meeting its obligations under this Plan. Nothing contained in this Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind, or a fiduciary relationship between the Company and any Participant, beneficiary, legal representative, or any other individual. To the extent that any individual acquires a right to receive payments from the Company, its Subsidiaries, and/or its Affiliates under this Plan, such right shall be no greater than the right of an unsecured general creditor of the Company, a Subsidiary, or an Affiliate, as the case may be. All payments to be made hereunder shall be paid from the general funds of the Company, a Subsidiary, or an Affiliate, as the case may be, and no special or separate fund shall be established and no segregation of assets shall be made to assure payment of such amounts.

 

Section 21.11. No Fractional Shares. No fractional Shares shall be issued or delivered pursuant to this Plan or any Award unless authorized by the Committee. If the Committee does not authorize the issuance or delivery of fraction shares, then the Committee shall determine whether cash, Awards, or other property shall be granted or paid in lieu of fractional Shares or whether such fractional Shares or any rights thereto shall be forfeited or otherwise eliminated.

 

Section 21.12. Retirement and Welfare Plans. Neither Awards made under this Plan nor Shares or cash paid pursuant to such Awards may be included as “compensation” for purposes of computing the benefits payable to any Participant under the Company’s or any Subsidiary’s or Affiliate’s retirement plans (both qualified and non-qualified) or welfare benefit plans unless such other plan expressly provides that such compensation shall be taken into account in computing a Participant’s benefit.

 

Section 21.13. Deferred Compensation. With respect to Awards subject to Code Section 409A, the Plan is intended to comply with the requirements of Code Section 409A, and the provisions of

 

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the Plan and any Award Agreement shall be interpreted in a manner that satisfies the requirements of Code Section 409A, and the Plan is intended to be operated accordingly. The Committee may make changes in the terms or operation of the Plan and/or Awards (including changes that may have retroactive effect) deemed necessary or desirable to comply with Code Section 409A. The Company, however, makes no representation or covenants that the Plan or Awards will comply with Section 409A.

 

Section 21.14. Non-exclusivity of this Plan. The adoption of this Plan shall not be construed as creating any limitations on the power of the Board or Committee to adopt such other compensation arrangements as it may deem desirable for any Participant.

 

Section 21.15. No Constraint on Corporate Action. Nothing in this Plan shall be construed to: (a) limit, impair, or otherwise affect the Company’s or a Subsidiary’s or an Affiliate’s right or power to make adjustments, reclassifications, reorganizations, or changes of its capital or business structure, or to merge or consolidate, or dissolve, liquidate, sell, or transfer all or any part of its business or assets; or (b) limit the right or power of the Company or a Subsidiary or an Affiliate to take any action which such entity deems to be necessary or appropriate.

 

Section 21.16. Governing Law. The Plan and each Award Agreement shall be governed by the laws of the state of Ohio, excluding any conflicts or choice of law rule or principle that might otherwise refer construction or interpretation of this Plan to the substantive law of another jurisdiction. Unless otherwise provided in the Award Agreement, recipients of an Award under this Plan are deemed to submit to the exclusive jurisdiction and venue of the federal or state courts of Ohio, to resolve any and all issues that may arise out of or relate to this Plan or any related Award Agreement.

 

Section 21.17. Indemnification. (a) Subject to requirements and limitations of applicable law, each individual who is or shall have been a member of the Board, or a Committee appointed by the Board, or an officer of the Company, a Subsidiary, or an Affiliate to whom authority was delegated in accordance with Article 3, shall be indemnified and held harmless by the Company against and from any loss, cost, liability, or expense that may be imposed upon or reasonably incurred by him in connection with or resulting from any claim, action, suit, or proceeding to which he may be a party or in which he may be involved by reason of any action taken or failure to act under this Plan and against and from any and all amounts paid by him in settlement thereof, with the Company’s approval, or paid by him in satisfaction of any judgment in any such action, suit, or proceeding against him, provided he shall give the Company an opportunity, at its own expense, to handle and defend the same before he undertakes to handle and defend it on his own behalf, unless such loss, cost, liability, or expense is a result of his own willful misconduct or except as expressly provided by statute.

 

(b) The foregoing right of indemnification shall not be exclusive of any other rights of indemnification to which such individuals may be entitled under the Company’s Articles of Incorporation or Bylaws, as a matter of law, or otherwise, or any power that the Company may have to indemnify them or hold them harmless.

 

Section 21.18. No Guarantee of Favorable Tax Treatment. Notwithstanding any provision of the Plan to the contrary or any action taken by the Company, Subsidiaries, or the Board with respect to any income tax, social insurance, payroll tax, or other tax, the acceptance of an Award under the Plan represents the Participant’s acknowledgement that the ultimate liability for any tax owed by the Participant is and remains the Participant’s responsibility, and that the Company makes no representations or warranties about the tax treatment of any Award, and does not commit to structure any aspect of the Award to reduce or eliminate a Participant’s tax liability, including without limitation, Code Section 409A.

 

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Exhibit C

 

Restated Certificate of Incorporation Article 7

 

7.1.(A) In addition to any affirmative vote required by law or this certificate of incorporation (any other provision of this certificate of incorporation notwithstanding), and except as otherwise expressly provided in paragraph 7.2:

 

(1) any merger or consolidation of the corporation or any Subsidiary (as hereinafter defined) with (i) any Interested Stockholder (as hereinafter defined) or (ii) any other corporation (whether or not itself an Interested Stockholder) which is, or after such merger or consolidation would be, an Affiliate (as hereinafter defined) of an Interested Stockholder; or

 

(2) any sale, lease, license, exchange, mortgage, pledge, transfer or other disposition (in one transaction or a series of transactions) to or with any Interested Stockholder or any Affiliate of any Interested Stockholder of any assets of the corporation or any Subsidiary having an aggregate Fair Market Value (as hereinafter defined) of $100,000,000 or more; or

 

(3) the issuance or transfer by the corporation or any Subsidiary (in one transaction or a series of transactions) of any securities of the corporation or any Subsidiary to any Interested Stockholder or any Affiliate of any Interested Stockholder having an aggregate Fair Market Value of $100,000,000 or more, other than the issuance of securities upon the conversion of convertible securities of the corporation or any Subsidiary which were not acquired by such Interested Stockholder (or such Affiliate) from the corporation or a Subsidiary; or

 

(4) the adoption of any plan or proposal for the liquidation or dissolution of the corporation proposed by or on behalf of any Interested Stockholder or any Affiliate of any Interested Stockholder; or

 

(5) any reclassification of securities (including any reverse stock split), or recapitalization or reorganization of the corporation, or any merger or consolidation of the corporation with any of its Subsidiaries, or any self tender offer for or repurchase of securities of the corporation by the corporation or any Subsidiary or any other transaction (whether or not with or into or otherwise involving any Interested Stockholder) which has the effect, directly or indirectly, of increasing the proportionate share of the outstanding shares of any class or series of equity or convertible securities of the corporation or any Subsidiary which is directly or indirectly owned by any Interested Stockholder or any Affiliate of any Interested Stockholder;

 

shall require the affirmative vote of the holders of at least (i) seventy-five per centum of the combined voting power of the then issued and outstanding capital stock of all classes and series of the corporation having voting powers (the “Voting Stock”), voting together as a single class, and (ii) a majority of the combined voting power of the then issued and outstanding Voting Stock beneficially owned by persons other than such Interested Stockholder, voting together as a single class, given at any annual meeting of stockholders or at any special meeting called for that purpose. Such affirmative vote shall be required notwithstanding the fact that no vote may be required, or that a lesser percentage may be specified, by law, by any other provision of this certificate of incorporation or in any agreement with any national securities exchange or otherwise.

 

(B) The term “Business Combination” as used herein shall mean any transaction which is referred to in any one or more of clauses (1) through (5) of sub-paragraph (A) of this paragraph 7.1.

 

7.2. The provisions of paragraph 7.1 shall not be applicable to any particular Business Combination, and such Business Combination shall require only such affirmative vote, if any, as is required by law, any other provision of this certificate of incorporation, and any agreement with any national securities exchange, if all of the conditions specified in either of the following sub-paragraphs (A) or (B) are met:

 

(A) The Business Combination shall have been approved by a majority of the Disinterested Directors (as hereinafter defined).

 

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(B) All of the following conditions shall have been met:

 

(1) The aggregate amount of the cash and the Fair Market Value as of the date of the consummation of the Business Combination (the “Consummation Date”) of consideration other than cash to be received per share by holders of Common Stock in such Business Combination shall be at least equal to the highest of the following (it being intended that the requirements of this clause (1) shall be required to be met with respect to every share of outstanding Common Stock, whether or not the Interested Stockholder has previously acquired any shares of Common Stock):

 

(i) (if applicable) the highest per share price (including any brokerage commissions, transfer taxes and soliciting dealers’ fees) paid by the Interested Stockholder for any shares of Common Stock acquired by it (x) within the five-year period immediately prior to the first public announcement of the terms of the proposed Business Combination (the “Announcement Date”) or (y) in the transaction in which it became an Interested Stockholder, whichever is higher;

 

(ii) the Fair Market Value per share of Common Stock on the Announcement Date or on the date on which the Interested Stockholder became an Interested Stockholder (such latter date is referred to herein as the “Determination Date”), whichever is higher; and

 

(iii) an amount which bears the same or greater percentage relationship to the Fair Market Value per share of Common Stock on the Announcement Date as the highest per share price determined in clause (B)(1)(i) above bears to the Fair Market Value per share of Common Stock on the date of the commencement of the acquisition of the Common Stock by such Interested Stockholder.

 

(2) The aggregate amount of cash and the Fair Market Value as of the Consummation Date of consideration other than cash to be received per share by holders of shares of any other class or series of outstanding Voting Stock shall be at least equal to the highest of the following (it being intended that the requirements of this clause (2) shall be required to be met with respect to every class or series of outstanding Voting Stock, whether or not the Interested Stockholder has previously acquired any shares of a particular class or series of Voting Stock):

 

(i) (if applicable) the highest per share price (including any brokerage commissions, transfer taxes and soliciting dealers’ fees) paid by the Interested Stockholder for any shares of such class or series of Voting Stock acquired by it (x) within the five-year period immediately prior to the Announcement Date or (y) in the transaction in which it became an Interested Stockholder, whichever is higher;

 

(ii) the Fair Market Value per share of such class or series of Voting Stock on the Announcement Date or on the Determination Date, whichever is higher;

 

(iii) (if applicable) the highest preferential amount per share to which the holders of shares of such class or series of Voting Stock are entitled in the event of any liquidation, dissolution or winding up of the corporation, whether voluntary or involuntary; and

 

(iv) an amount which bears the same or greater percentage relationship to the Fair Market Value per share of such class or series of Voting Stock on the Announcement Date as the highest per share price determined in clause (B)(2)(i) above bears to the Fair Market Value per share of such Voting Stock on the date of the commencement of the acquisition of such Voting Stock by such Interested Stockholder.

 

(3) The consideration to be received by holders of a particular class or series of outstanding Voting Stock (including Common Stock) shall be in cash or in the same form as the Interested Stockholder has previously paid for shares of such class or series of Voting Stock. If the Interested Stockholder has paid for shares of any class or series of Voting Stock with varying forms of consideration, the

 

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form of consideration to be received by each holder of such class or series of Voting Stock shall be, at the option of such holder, either cash or the form used by the Interested Stockholder to acquire the largest number of shares of such class or series of Voting Stock previously acquired by it prior to the Announcement Date. The price determined in accordance with clauses (1) and (2) of this sub-paragraph (B) shall be subject to appropriate adjustment in the event of any stock dividend, stock split, combination of shares or similar event.

 

(4) After the Determination Date and prior to the Consummation Date:

 

(i) except as approved by a majority of the Disinterested Directors, there shall have been no failure to declare and pay at the regular dates therefor the full amount of any dividends (whether or not cumulative) payable on any class or series of stock of the corporation having a preference over the Common Stock as to dividends or upon liquidation; and

 

(ii) there shall have been (x) no reduction in the quarterly rate of dividends paid on the Common Stock (except as necessary to reflect any subdivision of the Common Stock), except as approved by a majority of the Disinterested Directors, and (y) an increase in such quarterly rate of dividends paid on such Common Stock as necessary to reflect any reclassification (including any reverse stock split), recapitalization, reorganization, self tender offer for or repurchase of securities of the corporation by the corporation or any Subsidiary or any similar transaction which has the effect of reducing the number of outstanding shares of the Common Stock, unless the failure so to increase such quarterly rate is approved by a majority of the Disinterested Directors; and

 

(iii) such Interested Stockholder shall not have become the beneficial owner of any additional shares of Voting Stock except as part of the transaction which results in such Interested Stockholder becoming an Interested Stockholder or upon conversion of convertible securities acquired by it prior to becoming an Interested Stockholder or as a result of a pro rata stock dividend or stock split; and

 

(iv) such Interested Stockholder shall not have received the benefit, directly or indirectly (except proportionately as a stockholder), of any loans, advances, guarantees, pledges or other financial assistance or tax credits or other tax advantages provided by the corporation or any Subsidiary, whether in anticipation of or in connection with such Business Combination or otherwise; and

 

(v) such Interested Stockholder shall not have caused any material change in the corporation’s business or capital structure, including, without limitation, the issuance of shares of capital stock of the corporation to any third party.

 

(5) A proxy or information statement describing the proposed Business Combination and complying with the requirements of the Securities Exchange Act of 1934, as amended (the “Act”), and the rules and regulations thereunder (or any subsequent provisions replacing the Act, rules and regulations), shall be mailed by and at the expense of the Interested Stockholder to public stockholders of the corporation at least 30 days prior to the Consummation Date (whether or not such proxy or information statement is required to be mailed pursuant to the Act). The proxy or information statement shall contain at the front thereof in a prominent place (i) any recommendation as to the advisability (or inadvisability) of the Business Combination which a majority of the Disinterested Directors may choose to state, and (ii) if a majority of the Disinterested Directors so requests, the opinion of a reputable national investment banking firm as to the fairness (or not) of such Business Combination from the point of view of the remaining public stockholders of the corporation (such investment banking firm to be engaged solely on behalf of the remaining public stockholders, to be paid a reasonable fee for their services by the corporation upon receipt of such opinion, to be unaffiliated with such Interested Stockholder, and, to be selected by a majority of the Disinterested Directors).

 

(6) The holders of all outstanding shares of Voting Stock not beneficially owned by the Interested Stockholder prior to the consummation of any Business Combination shall be entitled to receive in such Business Combination cash or other consideration for their shares of such Voting Stock in

 

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compliance with clauses (1), (2) and (3) of sub-paragraph (B) of this paragraph 7.2 (provided, however, that the failure of any such holders who are exercising their statutory rights to dissent from such Business Combination and receive payment of the fair value of their shares to exchange their shares in such Business Combination shall not be deemed to have prevented the condition set forth in this clause (6) from being satisfied).

 

7.3. The following terms shall be deemed to have the meanings specified below:

 

(A) The term “person” shall mean any individual, firm, corporation, group (as such term is used in Regulation 13D-G of the rules and regulations under the Act, as in effect on January 1, 1988) or other entity.

 

(B) The term “Interested Stockholder” shall mean any person (other than the corporation, any Subsidiary or any pension, profit sharing, employee stock ownership, employee savings or other employee benefit plan, or any dividend reinvestment plan, of the corporation or any Subsidiary or any trustee of or fiduciary with respect to any such plan acting in such capacity) who or which:

 

(1) is the beneficial owner, directly or indirectly, of more than five per centum of the combined voting power of the then outstanding Voting Stock; or

 

(2) is an Affiliate of the corporation and at any time within the five-year period immediately prior to the date in question was the beneficial owner, directly or indirectly, of more than five per centum of the combined voting power of the then outstanding Voting Stock; or

 

(3) is an assignee of or has otherwise succeeded to any shares of Voting Stock which were at any time within the five-year period immediately prior to the date in question beneficially owned by an Interested Stockholder, if such assignment or succession shall have occurred in the course of a transaction or series of transactions not involving a public offering within the meaning of the Securities Act of 1933, as amended (or any subsequent provisions replacing such).

 

(C) A person shall be deemed a “beneficial owner” of any Voting Stock:

 

(1) which such person or any of its Affiliates or Associates (as hereinafter defined) beneficially owns, directly or indirectly; or

 

(2) which such person or any of its Affiliates or Associates has (i) the right to acquire (whether such right is exercisable immediately or only after the passage of time), pursuant to any agreement, arrangement or understanding or upon the exercise of conversion rights, exchange rights, warrants or options, or otherwise, or (ii) the right to vote pursuant to any agreement, arrangement or understanding; or

 

(3) which is beneficially owned, directly or indirectly, by any other person with which such person or any of its Affiliates or Associates has any agreement, arrangement or understanding for the purpose of acquiring, holding, voting or disposing of any shares of Voting Stock.

 

(D) For the purpose of determining whether a person is an Interested Stockholder pursuant to sub-paragraph (B) of this paragraph 7.3, the number of shares of Voting Stock deemed to be outstanding shall include shares deemed owned through application of sub-paragraph (C) of this paragraph 7.3, but shall not include any other shares of Voting Stock which may be issuable pursuant to any agreement, arrangement or understanding, or upon exercise of conversion rights, exchange rights, warrants or options, or otherwise.

 

(E) The term “Affiliate” of, or a person “affiliated” with, a specified person shall mean a person that directly, or indirectly through one or more intermediaries, controls, or is controlled by, or is under common control with, the person specified.

 

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(F) The term “Associate” as used to indicate a relationship with any person shall mean (1) any corporation or organization (other than the corporation or a Subsidiary) of which such person is an officer or partner or is, directly or indirectly, the beneficial owner of ten per centum or more of any class or series of equity securities, (2) any trust or other estate in which such person has a substantial beneficial interest or as to which such person serves as trustee or in a similar fiduciary capacity, and (3) any relative or spouse of such person, or any relative of such spouse, who has the same home as such person.

 

(G) The term “Subsidiary” shall mean any corporation of which a majority of any class or series of equity security is owned, directly or indirectly, by the corporation or by a Subsidiary or by the corporation and one or more Subsidiaries; provided, however, that for the purposes of the definition of Interested Stockholder set forth in sub-paragraph (B) of this paragraph 7.3, the term “Subsidiary” shall mean only a corporation of which a majority of each class or series of equity security is owned, directly or indirectly, by the corporation.

 

(H) The term “Fair Market Value” shall mean: (1) in the case of stock, the highest closing sale price during the 30-day period immediately preceding the date in question of a share of such stock on the Composite Tape for New York Stock Exchange-Listed Stocks, or, if such stock is not quoted on the Composite Tape, on the New York Stock Exchange, or if such stock is not listed on such Exchange, on the principal United States securities exchange registered under the Act on which such stock is listed or, if such stock is not listed on any such exchange, the highest closing bid quotation with respect to a share of such stock during the 30-day period preceding the date in question on the National Association of Securities Dealers, Inc. Automated Quotations System or any similar system then in use, or if no such quotations are available, the fair market value on the date in question of a share of such stock as determined by a majority of the Disinterested Directors in good faith, in each case with respect to any class or series of such stock, appropriately adjusted for any dividend or distribution in shares of such stock or any subdivision or reclassification of outstanding shares of such stock into a greater number of shares of such stock or any combination or reclassification of outstanding shares of such stock into a smaller number of shares of such stock; and (2) in the case of property other than cash or stock, the fair market value of such property on the date in question as determined by a majority of the Disinterested Directors in good faith.

 

(I) In the event of any Business Combination in which the corporation is the survivor, the phrase “consideration other than cash to be received” as used in clauses (1) and (2) of sub-paragraph (B) of paragraph 7.2 shall include the shares of Common Stock and/or the shares of any other class or series of outstanding Voting Stock retained by the holders of such shares.

 

(J) The term “Disinterested Director” shall mean any member of the Board of Directors of the corporation who is unaffiliated with, and not a nominee of, the Interested Stockholder and who was a member of the Board of Directors prior to the Determination Date, and any successor of a Disinterested Director who is unaffiliated with, and not a nominee of, the Interested Stockholder and is recommended to succeed a Disinterested Director by a majority of the total number of Disinterested Directors then on the Board of Directors.

 

(K) References to “highest per share price” shall in each case with respect to any class or series of stock reflect an appropriate adjustment for any dividend or distribution in shares of such stock or any subdivision or reclassification of outstanding shares of such stock into a greater number of shares of such stock or any combination or reclassification of outstanding shares of such stock into a smaller number of shares of such stock.

 

7.4. A majority of the Board of Directors of the corporation shall have the power and duty to determine for the purpose of these paragraphs 7.1 through 7.6, on the basis of information known to them after reasonable inquiry, whether a person is an Interested Stockholder. Once the Board of Directors has made a determination, pursuant to the preceding sentence, that a person is an Interested Stockholder, a majority of the total number of directors of the corporation who would qualify

 

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as Disinterested Directors shall have the power and duty to interpret all of the terms and provisions of these paragraphs 7.1 through 7.6, and to determine on the basis of information known to them after reasonable inquiry all facts necessary to ascertain compliance therewith, including, without limitation, (A) the number of shares of Voting Stock beneficially owned by any person, (B) whether a person is an Affiliate or Associate of another, (C) whether the assets which are the subject of any Business Combination have, or the consideration to be received for the issuance or transfer of securities by the corporation or any Subsidiary in any Business Combination has, an aggregate Fair Market Value of $100,000,000 or more and (D) whether all of the applicable conditions set forth in sub-paragraph (B) of paragraph 7.2 have been met with respect to any Business Combination. Any determination pursuant to this paragraph 7.4 made in good faith shall be binding and conclusive on all parties.

 

7.5. Nothing contained in these paragraphs 7.1 through 7.6 shall be construed to relieve any Interested Stockholder from any fiduciary obligation imposed by law.

 

7.6. Notwithstanding any other provisions of this certificate of incorporation or the by-laws of the corporation (and notwithstanding the fact that a lesser percentage may be specified by law, this certificate of incorporation or the by-laws of the corporation), the affirmative vote of the holders of at least (A) seventy-five per centum of the combined voting power of the then issued and outstanding Voting Stock, voting together as a single class, and (B) a majority of the combined voting power of the then issued and outstanding Voting Stock beneficially owned by persons other than an Interested Stockholder, voting together as a single class, given at any annual meeting of stockholders or at any special meeting called for that purpose, shall be required to amend, alter, change or repeal, or adopt any provisions inconsistent with, these paragraphs 7.1 through 7.6; provided, however, that the foregoing provisions of this paragraph 7.6 shall not apply to, and such vote shall not be required for, any such amendment, alteration, change, repeal or adoption approved by a majority of the disinterested Directors, and any such amendment, alteration, change, repeal or adoption so approved shall require only such vote, if any, as is required by law, any other provision of this certificate of incorporation or the by-laws of the corporation.

 

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Exhibit D

 

Proposed Amendment to Section 16 of the Bylaws

 

Section 16. These By-Laws may be amended or added to at any meeting of the Board of Directors by affirmative vote of a majority of all of the directors, if notice of the proposed change has been delivered or mailed to the directors five days before the meeting, or if all the directors are present, or if all not present assent in writing to such change; provided, however, that the provisions of Section 7 relating to the number of directors constituting the Board of Directors may be amended only by the affirmative vote, in person or by proxy, of the holders of a majority of the outstanding shares of capital stock entitled to vote at any meeting of the stockholders of the Company; and provided further that the provisions of Section 7 other than those relating to the number of directors constituting the Board of Directors, and the provisions of this Section 16 may be amended or added to only by the affirmative vote, in person or by proxy, of the holders of two-thirds of the outstanding shares of capital stock entitled to vote at any meeting of the stockholders of the Company; and provided further, in the event of any such amendment or addition pursuant to vote by the stockholders of the Company, that such amendment or addition, or a summary thereof, shall have been set forth or referred to in the notice of such meeting.

 

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LOGO

 

LOGO   LOGO

 


Table of Contents
         LOGO
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Electronic Voting Instructions

 

Available 24 hours a day, 7 days a week!

 

Instead of mailing your proxy, you may choose one of the voting methods outlined below to vote your proxy.

   

 

VALIDATION DETAILS ARE LOCATED BELOW IN THE TITLE BAR.

        

 

Proxies submitted by the Internet or telephone must be received by 1:00 a.m., Eastern Time, on April 21, 2015.

         LOGO   Vote by Internet
          

  • Go to www.envisionreports.com/AEP

          

  • Or scan the QR code with your smartphone

          

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Vote by telephone

          

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Using a black ink pen, mark your votes with an X as shown in this example.
Please do not write outside the designated areas.
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  • Follow the instructions provided by the recorded message

 

 

Annual Meeting Proxy Card

  

 

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q IF YOU HAVE NOT VOTED VIA THE INTERNET OR TELEPHONE, FOLD ALONG THE PERFORATION, DETACH AND RETURN THE BOTTOM PORTION IN THE ENCLOSED ENVELOPE. q

 

 

 

 A 

  Proposals — The Board of Directors recommends a vote FOR all the nominees listed and FOR Proposals 2, 3, 4, 5 and 6.      

 

1.    Election of Directors:   For    Against    Abstain     For    Against    Abstain     For    Against    Abstain       

 

+

  
01 - Nicholas K. Akins  

 

¨

  

 

¨

  

 

¨

  02 - David J. Anderson  

 

¨

  

 

¨

  

 

¨

  03 - J. Barnie Beasley, Jr.  

 

¨

  

 

¨

  

 

¨

         
04 - Ralph D. Crosby, Jr.   ¨    ¨    ¨   05 - Linda A. Goodspeed   ¨    ¨    ¨   06 - Thomas E. Hoaglin   ¨    ¨    ¨          
07 - Sandra Beach Lin   ¨    ¨    ¨   08 - Richard C. Notebaert   ¨    ¨    ¨   09 - Lionel L. Nowell III   ¨    ¨    ¨          
10 - Stephen S. Rasmussen   ¨    ¨    ¨   11 - Oliver G. Richard III   ¨    ¨    ¨   12 - Sara Martinez Tucker   ¨    ¨    ¨          
           For    Against    Abstain                  For    Against    Abstain
2.   Ratification of the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2015.       ¨    ¨    ¨       6.   Amendment to the By-Laws to eliminate the supermajority provisions.    ¨    ¨    ¨
3.   Advisory approval of the Company’s executive compensation.       ¨    ¨    ¨       The Board of Directors recommends that you vote AGAINST Proposal 7.
                         For    Against    Abstain
4.   Approve the American Electric Power System 2015 Long-Term Incentive Plan.       ¨    ¨    ¨       7.   Shareholder proposal for proxy access.    ¨    ¨    ¨
5.   Amendment to the Restated Certificate of Incorporation to eliminate Article 7.       ¨    ¨    ¨                 

 

 B    Authorized Signatures — This section must be completed for your vote to be counted. — Date and Sign Below    

Please sign exactly as name(s) appears hereon. Joint owners should each sign. When signing as attorney, executor, administrator, corporate officer, trustee, guardian, or custodian, please give full title.

Date (mm/dd/yyyy) — Please print date below.       Signature 1 — Please keep signature within the box.       Signature 2 — Please keep signature within the box.

 

                    /            /

 

               

IF VOTING BY MAIL, YOU MUST COMPLETE SECTIONS A AND B.

 

 

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Table of Contents

American Electric Power Company, Inc.

2015 Annual Meeting of Shareholders and Admission Ticket

Tuesday April 21, 2015, at 9:00 a.m. Eastern Time

The Ohio State University Fawcett Center

2400 Olentangy River Road

Columbus, Ohio

If you wish to attend and vote at the meeting, please bring this admission ticket and identification with you.

 

 

AGENDA

             

Ÿ

 

Introduction and Welcome

             Ÿ    Advisory approval of the Company’s executive compensation    Ÿ    Shareholder Proposal

Ÿ

 

Election of Directors

             Ÿ    Adoption of the 2015 Long-Term Incentive Plan    Ÿ    Chief Executive Officer’s Report

Ÿ

 

Ratification of Auditors

             Ÿ    Amendment to the Restated Certificate of Incorporation    Ÿ    Comments and Questions from Shareholders
               Ÿ    Amendment to the By-Laws      

 

LOGO   

q  IF YOU HAVE NOT VOTED VIA THE INTERNET OR TELEPHONE, FOLD ALONG THE PERFORATION, DETACH AND RETURN THE BOTTOM PORTION IN THE ENCLOSED ENVELOPE.  q

 

 

 

LOGO   +

 

 

Proxy — American Electric Power Company, Inc.

 

 

Proxy Solicited on behalf of the Board of Directors for the Annual Meeting to be held April 21, 2015

The shareholder signing on the reverse of this proxy card appoints Nicholas K. Akins and Brian X. Tierney, and each of them, acting by a majority if more than one be present, attorneys and proxies to the undersigned, with power of substitution, to represent the undersigned at the annual meeting of shareholders of American Electric Power Company, Inc. to be held on April 21, 2015, and at any adjournment thereof, and to vote all shares of Common Stock of the Company which the undersigned is entitled to vote on all matters coming before said meeting. If no direction is given, such shares will be voted in accordance with the recommendations of the Board of Directors and at the discretion of the proxy holders as to any other matters coming before the meeting.

Trustee’s Authorization. The undersigned authorizes JP Morgan Chase Bank, National Association to vote all shares of Common Stock of the Company credited to the undersigned’s account under the American Electric Power System retirement savings plan at the annual meeting in accordance with instructions on the reverse side.

You are encouraged to specify your choices by marking the appropriate boxes (SEE REVERSE SIDE), but you need not mark any boxes if you wish to vote in accordance with the Board of Directors’ recommendations.

 

Nominees for:            
01 - Nicholas K. Akins    02 - David J. Anderson    03 - J. Barnie Beasley, Jr.    04 - Ralph D. Crosby, Jr.    05 - Linda A. Goodspeed    06 - Thomas E. Hoaglin
07 - Sandra Beach Lin    08 - Richard C. Notebaert    09 - Lionel L. Nowell III    10 - Stephen S. Rasmussen    11 - Oliver G. Richard III    12 - Sara Martinez Tucker

 

 C    Non-Voting Items            

Change of Address — Please print new address below.

      Comments — Please print your comments below.      
       
       
       

 

    IF VOTING BY MAIL, YOU MUST COMPLETE SECTIONS A AND B ON THE OTHER SIDE OF THIS CARD.    +
        

 






Appendix A to the
Proxy Statement


American Electric Power



2014 Annual Report




Audited Consolidated Financial Statements and
Management’s Discussion and Analysis of Financial Condition and Results of Operations







 
CONTENTS
AMERICAN ELECTRIC POWER
1 Riverside Plaza
Columbus, Ohio 43215-2373
 
 
Glossary of Terms
i
 
 
Forward-Looking Information
v
 
 
AEP Common Stock and Dividend Information
vii
 
 
Selected Consolidated Financial Data
1
 
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
2
 
 
Reports of Independent Registered Public Accounting Firm
56-57
 
 
Management’s Report on Internal Control Over Financial Reporting
58
 
 
Consolidated Statements of Income
59
 
 
Consolidated Statements of Comprehensive Income (Loss)
60
 
 
Consolidated Statements of Changes in Equity
61
 
 
Consolidated Balance Sheets
62-63
 
 
Consolidated Statements of Cash Flows
64
 
 
Index of Notes to Consolidated Financial Statements
65
 
 
Corporate and Shareholder Information
167
 
 
Executive Leadership Team
168





GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
Term
 
Meaning
 
 
 
AEGCo
 
AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent
 
American Electric Power Company, Inc., an electric utility holding company.
AEP Consolidated
 
AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit
 
AEP Credit, Inc., a consolidated variable interest entity of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East Companies
 
APCo, I&M, KPCo and OPCo.
AEP Energy
 
AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.
AEP System
 
American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP Transmission Holdco
 
AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEPEP
 
AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, asset management and commercial and industrial sales in the deregulated Texas market.
AEPES
 
AEP Energy Services, Inc., a subsidiary of AEP Resources, Inc.
AEPSC
 
American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC
 
Allowance for Funds Used During Construction.
AGR
 
AEP Generation Resources Inc., a nonregulated AEP subsidiary in the Generation & Marketing segment.
AOCI
 
Accumulated Other Comprehensive Income.
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
APSC
 
Arkansas Public Service Commission.
Appalachian Consumer Rate Relief Funding
 
Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
ASU
 
Accounting Standards Update.
BlueStar
 
BlueStar Energy Holdings, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.  BlueStar began doing business as AEP Energy, Inc. in June 2012.
CAA
 
Clean Air Act.
CLECO
 
Central Louisiana Electric Company, a nonaffiliated utility company.
CO2
 
Carbon dioxide and other greenhouse gases.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CRES provider
 
Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service.
CSPCo
 
Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
CWIP
 
Construction Work in Progress.
DCC Fuel
 
DCC Fuel IV LLC, DCC Fuel V LLC, DCC Fuel VI LLC and DCC Fuel VII, consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC
 
Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
EIS
 
Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entity of AEP.
ENEC
 
Expanded Net Energy Charge.

i



Term
 
Meaning
 
 
 
Energy Supply
 
AEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
ERCOT
 
Electric Reliability Council of Texas regional transmission organization.
ESP
 
Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETT
 
Electric Transmission Texas, LLC, an equity interest joint venture between AEP and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
FAC
 
Fuel Adjustment Clause.
FASB
 
Financial Accounting Standards Board.
Federal EPA
 
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
FGD
 
Flue Gas Desulfurization or scrubbers.
FTR
 
Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP
 
Accounting Principles Generally Accepted in the United States of America.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IEU
 
Industrial Energy Users-Ohio.
IGCC
 
Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement
 
An agreement by and among APCo, I&M, KPCo and OPCo, which defined the sharing of costs and benefits associated with their respective generation plants.  This agreement was terminated January 1, 2014.
IRS
 
Internal Revenue Service.
IURC
 
Indiana Utility Regulatory Commission.
KGPCo
 
Kingsport Power Company, an AEP electric utility subsidiary.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
 
Kentucky Public Service Commission.
kV
 
Kilovolt.
KWh
 
Kilowatthour.
LPSC
 
Louisiana Public Service Commission.
MISO
 
Midwest Independent Transmission System Operator.
MLR
 
Member load ratio, the method used to allocate transactions among members of the Interconnection Agreement.
MMBtu
 
Million British Thermal Units.
MPSC
 
Michigan Public Service Commission.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWh
 
Megawatthour.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NSR
 
New Source Review.
OATT
 
Open Access Transmission Tariff.
OCC
 
Corporation Commission of the State of Oklahoma.
Ohio Phase-in-Recovery Funding
 
Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OPEB
 
Other Postretirement Benefit Plans.

ii



Term
 
Meaning
 
 
 
Operating Agreement
 
Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third party sales.  AEPSC acts as the agent.
OTC
 
Over the counter.
OVEC
 
Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PCA
 
Power Coordination Agreement among APCo, I&M and KPCo.
PIRR
 
Phase-In Recovery Rider.
PJM
 
Pennsylvania – New Jersey – Maryland regional transmission organization.
PM
 
Particulate Matter.
POLR
 
Provider of Last Resort revenues.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants; APCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
 
A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.  AEGCo and I&M jointly-own Unit 1.  In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
RPM
 
Reliability Pricing Model.
RSR
 
Retail Stability Rider.
RTO
 
Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine
 
Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC
 
U.S. Securities and Exchange Commission.
SEET
 
Significantly Excessive Earnings Test.
SIA
 
System Integration Agreement, effective June 15, 2000, as amended, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF
 
Spent Nuclear Fuel.
SO2
 
Sulfur dioxide.
SPP
 
Southwest Power Pool regional transmission organization.
SSO
 
Standard service offer.
Stall Unit
 
J. Lamar Stall Unit at Arsenal Hill Plant, a 534 MW natural gas unit owned by SWEPCo.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC
 
AEP Texas Central Company, an AEP electric utility subsidiary.
Texas Restructuring Legislation
 
Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC
 
AEP Texas North Company, an AEP electric utility subsidiary.
Transition Funding
 
AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.
Transource Energy
 
Transource Energy, LLC, a consolidated variable interest entity formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.
Transource Missouri
 
A 100% wholly-owned subsidiary of Transource Energy.
Turk Plant
 
John W. Turk, Jr. Plant, a 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.

iii



Term
 
Meaning
 
 
 
Utility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE
 
Variable Interest Entity.
Virginia SCC
 
Virginia State Corporation Commission.
WPCo
 
Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC
 
Public Service Commission of West Virginia.

iv



FORWARD-LOOKING INFORMATION

This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations,” but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:
Ÿ
The economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory.
Ÿ
Inflationary or deflationary interest rate trends.
Ÿ
Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
Ÿ
The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
Ÿ
Electric load, customer growth and the impact of competition, including competition for retail customers.
Ÿ
Weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs.
Ÿ
Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
Ÿ
Availability of necessary generation capacity and the performance of our generation plants.
Ÿ
Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
Ÿ
Our ability to build or acquire generation capacity and transmission lines and facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs.
Ÿ
New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation, cost recovery and/or profitability of our generation plants and related assets.
Ÿ
Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
Ÿ
A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
Ÿ
Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
Ÿ
Resolution of litigation.
Ÿ
Our ability to constrain operation and maintenance costs.
Ÿ
Our ability to develop and execute a strategy based on a view regarding prices of electricity and other energy-related commodities.
Ÿ
Prices and demand for power that we generate and sell at wholesale.
Ÿ
Changes in technology, particularly with respect to new, developing, alternative or distributed sources of generation.
Ÿ
Our ability to recover through rates or market prices any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
Ÿ
Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas and capacity auction returns.
Ÿ
Changes in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP.

v



Ÿ
The transition to market for generation in Ohio, including the implementation of ESPs and our ability to recover investments in our Ohio generation assets.
Ÿ
Our ability to successfully and profitably manage our separate competitive generation assets.
Ÿ
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
Ÿ
Actions of rating agencies, including changes in the ratings of our debt.
Ÿ
The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.
Ÿ
Accounting pronouncements periodically issued by accounting standard-setting bodies.
Ÿ
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.
The forward looking statements of AEP and its Registrant Subsidiaries speak only as of the date of this report or as of the date they are made.  AEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of this report.

vi



AEP COMMON STOCK AND DIVIDEND INFORMATION

The AEP common stock quarterly high and low sales prices, quarter-end closing price and the cash dividends paid per share are shown in the following table:
Quarter Ended
 
High
 
Low
 
Quarter-End
Closing Price
 
Dividend
December 31, 2014
 
$
63.22

 
$
51.97

 
$
60.72

 
$
0.53

September 30, 2014
 
55.91

 
49.06

 
52.21

 
0.50

June 30, 2014
 
55.94

 
49.99

 
55.77

 
0.50

March 31, 2014
 
50.95

 
45.80

 
50.66

 
0.50

 
 
 
 
 
 
 
 
 
December 31, 2013
 
$
48.40

 
$
43.01

 
$
46.74

 
$
0.50

September 30, 2013
 
47.59

 
41.83

 
43.35

 
0.49

June 30, 2013
 
51.60

 
42.83

 
44.78

 
0.49

March 31, 2013
 
48.68

 
42.92

 
48.63

 
0.47


AEP common stock is traded principally on the New York Stock Exchange.  As of December 31, 2014, AEP had approximately 74,000 registered shareholders.


vii




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
 
(dollars in millions, except per share amounts)
STATEMENTS OF INCOME DATA
 
 
 
 
 
 
 
 
 
 
Total Revenues
 
$
17,020

 
$
15,357

 
$
14,945

 
$
15,116

 
$
14,427

 
 


 
 
 
 
 
 
 
 
Operating Income
 
$
3,232

 
$
2,855

 
$
2,656

 
$
2,782

 
$
2,663

 
 


 
 
 
 
 
 
 
 
Income Before Extraordinary Items
 
$
1,638

 
$
1,484

 
$
1,262

 
$
1,576

 
$
1,218

Extraordinary Items, Net of Tax
 

 

 

 
373

 

Net Income
 
1,638

 
1,484

 
1,262

 
1,949

 
1,218

 
 
 
 
 
 
 
 
 
 
 
Net Income Attributable to Noncontrolling Interests
 
4

 
4

 
3

 
3

 
4

 
 
 
 
 
 
 
 
 
 
 
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS
 
1,634

 
1,480

 
1,259

 
1,946

 
1,214

 
 
 
 
 
 
 
 
 
 
 
Preferred Stock Dividend Requirements of Subsidiaries Including Capital Stock Expense
 

 

 

 
5

 
3

 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
1,634

 
$
1,480

 
$
1,259

 
$
1,941

 
$
1,211

 
 
 
 
 
 
 
 
 
 
 
BALANCE SHEETS DATA
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
 
$
64,305

 
$
60,285

 
$
57,454

 
$
55,670

 
$
53,740

Accumulated Depreciation and Amortization
 
20,188

 
19,288

 
18,691

 
18,699

 
18,066

Total Property, Plant and Equipment – Net
 
$
44,117

 
$
40,997

 
$
38,763

 
$
36,971

 
$
35,674

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
59,633

 
$
56,414

 
$
54,367

 
$
52,223

 
$
50,455

 
 


 
 
 
 
 
 
 
 
Total AEP Common Shareholders’ Equity
 
$
16,820

 
$
16,085

 
$
15,237

 
$
14,664

 
$
13,622

 
 


 
 
 
 
 
 
 
 
Noncontrolling Interests
 
$
4

 
$
1

 
$

 
$
1

 
$

 
 


 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
 
$

 
$

 
$

 
$

 
$
60

 
 


 
 
 
 
 
 
 
 
Long-term Debt (a)
 
$
18,684

 
$
18,377

 
$
17,757

 
$
16,516

 
$
16,811

 
 


 
 
 
 
 
 
 
 
Obligations Under Capital Leases (a)
 
$
552

 
$
538

 
$
449

 
$
458

 
$
474

 
 


 
 
 
 
 
 
 
 
AEP COMMON STOCK DATA
 


 
 
 
 
 
 
 
 
Basic Earnings per Share Attributable to AEP Common Shareholders:
 


 
 
 
 
 
 
 
 
 
 


 
 
 
 
 
 
 
 
Income Before Extraordinary Items
 
$
3.34

 
$
3.04

 
$
2.60

 
$
3.25

 
$
2.53

Extraordinary Items, Net of Tax
 

 

 

 
0.77

 

 
 


 
 
 
 
 
 
 
 
Total Basic Earnings per Share Attributable to AEP Common Shareholders
 
$
3.34

 
$
3.04

 
$
2.60

 
$
4.02

 
$
2.53

 
 


 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares Outstanding (in millions)
 
489

 
487

 
485

 
482

 
479

 
 

 
 
 
 
 
 
 
 
Market Price Range:
 

 
 
 
 
 
 
 
 
High
 
$
63.22

 
$
51.60

 
$
45.41

 
$
41.71

 
$
37.94

Low
 
$
45.80

 
$
41.83

 
$
36.97

 
$
33.09

 
$
28.17

 
 


 
 
 
 
 
 
 
 
Year-end Market Price
 
$
60.72

 
$
46.74

 
$
42.68

 
$
41.31

 
$
35.98

 
 


 
 
 
 
 
 
 
 
Cash Dividends Declared per AEP Common Share
 
$
2.03

 
$
1.95

 
$
1.88

 
$
1.85

 
$
1.71

 
 


 
 
 
 
 
 
 
 
Dividend Payout Ratio
 
60.78
%
 
64.14
%
 
72.31
%
 
46.02
%
 
67.59
%
 
 


 
 
 
 
 
 
 
 
Book Value per AEP Common Share
 
$
34.37

 
$
32.98

 
$
31.35

 
$
30.36

 
$
28.32


(a)
Includes portion due within one year.

1



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

American Electric Power Company, Inc. (AEP) is one of the largest investor-owned electric public utility holding companies in the United States.  Our electric utility operating companies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia.

Our subsidiaries operate an extensive portfolio of assets including:

Approximately 37,600 megawatts of generating capacity, one of the largest complements of generation in the United States.
Approximately 40,000 miles of transmission lines, including 2,110 miles of 765 kV lines, the backbone of the electric interconnection grid in the Eastern United States.
Approximately 222,000 miles of distribution lines that deliver electricity to 5.3 million customers.
Substantial commodity transportation assets (approximately 4,990 railcars, approximately 2,800 barges, 47 towboats, 20 harbor boats and a coal handling terminal with approximately 18 million tons of annual capacity).  Our commercial barging operations annually transport approximately 48 million tons of coal and dry bulk commodities.  Approximately 35% of the barging is for transportation of agricultural products, 34% for coal, 17% for steel and 14% for other commodities.

Customer Demand

In comparison to 2013, our weather-normalized retail sales increased 1% for the year ended December 31, 2014. Our 2014 industrial sales increased 0.4% compared to 2013, despite the closure of Ormet, a large aluminum company in October 2013. Excluding Ormet, our industrial sales volumes increased by 3.9%. Our 2014 residential and commercial sales increased 1.1% and 1.7%, respectively, compared to 2013.
In 2015, we anticipate weather-normalized retail sales will increase by 0.6%. The industrial class is expected to grow by 2% in 2015, primarily related to a number of new oil and natural gas expansions, especially around the major shale gas areas within AEP’s footprint. Weather-normalized residential sales are projected to increase by 0.2%, primarily related to projected customer growth. Commercial class energy sales are projected to decrease by 0.4%.

Corporate Separation

Background

On December 31, 2013, as approved by the FERC and the PUCO, OPCo transferred its generation assets and related generation liabilities at net book value to AGR.  In accordance with Ohio law, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers.  Effective January 1, 2014, OPCo began purchasing power from both affiliated and nonaffiliated entities, subject to PUCO approval, to meet the energy and capacity needs of customers. On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value its ownership (867 MW) in Amos Plant, Unit 3 to APCo and one-half of its interest (780 MW) in the Mitchell Plant to KPCo.  


2



Other Impacts of Corporate Separation

The Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.

Effective January 1, 2014, the FERC approved the following:

A PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.
A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent to address open commitments related to the termination of the Interconnection Agreement and responsibilities to PJM.
A Power Supply Agreement between AGR and OPCo for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014.
 
For a further discussion of corporate separation, see the “Corporate Separation” section of Note 1.

Merchant Fleet Alternatives

AEP is evaluating strategic alternatives for its merchant generation fleet, which primarily includes AGR’s generation fleet and AEG's Lawrenceburg unit which operates in PJM as well as a 54.7% interest in the Oklaunion Plant which operates in ERCOT.  Potential alternatives may include, but are not limited to, continued ownership of the merchant generation fleet, executing a purchased power agreement with a regulated affiliate for certain merchant generation units in Ohio, a spin-off of the merchant generation fleet or a sale of the merchant generation fleet.  Management has not made a decision regarding the potential alternatives, nor has management set a specific time frame for a decision.  Certain of these alternatives could result in a loss which could reduce future net income and cash flow and impact financial condition.

Merchant Portion of Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. Approximately 80% of the Turk plant is recovered under cost-based rate recovery in Texas, Louisiana, and through SWEPCo’s wholesale customers.

If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.


3



Ohio Electric Security Plan Filings

2009 - 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. Oral arguments at the Supreme Court of Ohio were held in February 2015. OPCo presented arguments to reinstate a weighted average cost of capital carrying charge and to defend against an intervenor argument that the carrying charges should be reduced due to an accumulated deferred income tax credit. 
 
June 2012 - May 2015 Ohio ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015. This ruling was generally upheld in PUCO rehearing orders in January and March 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and is $150/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50/MWh through May 2014 and is currently collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR. As of December 31, 2014, OPCo’s incurred deferred capacity costs balance was $422 million, including debt carrying costs.

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. As ordered, in 2014, OPCo conducted multiple energy-only auctions for a total of 100% of the SSO load with delivery beginning April 2014 through May 2015. For delivery starting in June 2015, OPCo will conduct energy and capacity auctions for its entire SSO load. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit.

In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88 capacity charge, the independent auditor recommends a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and intends to oppose the findings in the audit report.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.


4



Proposed June 2015 - May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018. The proposal included a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM capacity and energy auction-based generation through OPCo. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based purchase power agreement. In May 2014, intervenors and the PUCO staff filed testimony that provided various recommendations including the rejection and/or modification of various riders, including the Distribution Investment Rider and the proposed PPA. Hearings at the PUCO in the ESP case were held in June 2014.

In July 2014, OPCo submitted a separate application to continue the RSR established in the June 2012 - May 2015 ESP to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00/MWh, until the balance of the capacity deferrals has been collected.

In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA for inclusion in the PPA rider, discussed above. The new PPA would include an additional 2,671 MW to be purchased from AGR over the life of the respective generating units.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filings” section of Note 4.

2012 Texas Base Rate Case

Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap.  As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances.  The resulting annual base rate increase is approximately $52 million.  In May 2014, intervenors filed appeals of the order with the Texas District Court.  In June 2014, SWEPCo intervened in those appeals and filed initial responses.  If certain parts of the PUCT order are overturned it could reduce future net income and cash flows and impact financial condition.  See the “2012 Texas Base Rate Case” section of Note 4.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant. In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013. The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million, primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. See the “2012 Louisiana Formula Rate Filing” section of Note 4.

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase included a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years.

5



In June 2014, a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors was filed with the OCC. The parties to the stipulation recommended no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider would provide $24 million of revenues over 14 months beginning in November 2014 and increase to $27 million in 2016. New depreciation rates are recommended for advanced metering investments and existing meters, also to be effective November 2014. Additionally, the stipulation recommends recovery of regulatory assets for 2013 storms and regulatory case expenses. In July 2014, the Attorney General joined in the stipulation agreement. In October 2014, the Administrative Law Judge (ALJ) recommended approval of the stipulation agreement and interim rates were implemented in November 2014, subject to refund. In November 2014, intervenors filed exceptions to the ALJ's report. An order is anticipated in the first quarter of 2015. If the OCC were to disallow any portion of this settlement agreement, it could reduce future net income and cash flows and impact financial condition. See the “2014 Oklahoma Base Rate Case” section of Note 4.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a biennial generation and distribution base rate case with the Virginia SCC. In accordance with a Virginia statute, APCo did not request an increase in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 was within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to the change in the expected service life of certain plants. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to IGCC and other deferred costs. APCo also requested approval to amortize $38 million related to an accumulated deferred Virginia state income tax (ADVSIT) liability over 20 years, beginning February 2015.

In November 2014, the Virginia SCC issued an order concluding that APCo's adjusted earned rate of return on common equity for 2012 and 2013, reflecting their ordered adjustments, was above the allowed threshold. The order included (a) a $6 million refund to customers for the years 2012 through 2013, (b) the write-off of $10 million of IGCC pre-construction costs, (c) approval to amortize a $38 million ADVSIT liability over 20 years, beginning February 2015 and (d) no change to generation depreciation rates with rates to be reviewed again in the next biennial rate case. The order also approved a new return on common equity of 9.7% effective for 2014 and 2015. The Virginia SCC did not rule on a Virginia SCC staff recommendation to write-down certain costs, for ratemaking purposes, for the biennial period based on APCo’s earnings within the statutory equity range. In January 2015, the Virginia SCC initiated a separate proceeding to address the proper treatment of APCo’s authorized regulatory assets. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 Virginia Biennial Base Rate Case” section of Note 4.

Potential New Virginia Legislation Affecting Biennial Reviews

In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were approved by the Virginia General Assembly and have been sent to the Governor. If these amendments are enacted, APCo’s existing generation and distribution base rates would freeze until after the Virginia SCC rules on APCo’s next biennial review, which APCo would file in March 2020 for the 2018 and 2019 test years. These amendments would also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. Management continues to monitor this potential new legislation in Virginia.

2014 West Virginia Base Rate Case

In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $181 million, based upon a 10.62% return on common equity, to be effective in the second quarter of 2015.  The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units.  The filing also requested recovery of $89 million over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs.  In addition to the base rate request, the filing also included a request to implement a rider of approximately $45 million annually to recover vegetation management costs, including

6



a return on capital investment.  In December 2014 and January 2015, intervenors filed testimony which proposed total annual revenue increases ranging from $35 million to $59 million based upon returns on common equity ranging from 9% to 10% and regulatory asset disallowances ranging from $7 million to $9 million.  Additionally, other intervenors proposed that the revenue requirement be based on a return on common equity of 8.7% and that $89 million of regulatory assets be disallowed.  Intervenors also recommended a disallowance of approximately $44 million related to the December 2013 transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo.  Hearings at the WVPSC were held in January 2015.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 West Virginia Base Rate Case” section of Note 4.

Plant Transfer

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a cost-of-service basis, to their respective customers. West Virginia generally allows for timely recovery of fuel costs through an expanded net energy cost which trues-up to actual expenses. In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo. In June 2014, the FERC issued an order approving a request by AGR and WPCo to transfer AGR’s one-half interest in the Mitchell Plant to WPCo.

In October 2014, a stipulation agreement between APCo, WPCo, the WVPSC staff and intervenors in the case was filed with the WVPSC. The stipulation agreement recommended approval for WPCo to acquire, at net book value, the one-half interest in the Mitchell Plant, excluding certain assets, and to pay AGR $20 million upon transfer, which WPCo will record as a regulatory asset, include in rate base and recover over the life of the plant. Additionally, the agreement stated that 82.5% of the costs associated with the acquired interest will be reflected in rates effective from the date of the transfer via a surcharge with an offset in ENEC revenues of $93 million. The remaining 17.5% of the costs associated with the acquired interest is to be included in rates by January 2020. The agreement also proposed that WPCo share the energy margins for 82.5% of the plant’s output with ratepayers and that WPCo retain all of the energy margins from sales into the wholesale market on the remaining 17.5%, to offset fixed costs associated with this portion, until the remaining portion is included in rates. In December 2014, the WVPSC issued an order that approved the settlement agreement, subject to certain modifications related to 82.5% of the energy and capacity margin sharing. The WVPSC determined that the sharing mechanism that was proposed is reasonable and will be adopted provided the result of the sharing mechanism will be adjusted, if necessary, so that the sharing mechanism does not result in a net cost to ratepayers that exceeds the actual variable cost of generation. In January 2015, the transfer of the one-half interest in the Mitchell Plant to WPCo was completed. See the “Plant Transfer” section of APCo Rate Matters in Note 4.

Kentucky Fuel Adjustment Clause Review

In August 2014, the KPSC issued an order initiating a review of KPCo's FAC from November 2013 through April 2014. In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owns and operates both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. Additionally, the KPSC directed KPCo to refund to customers $13 million of fuel costs, by the end of the second quarter of 2015, collected during the FAC review period of January 2014 through April 2014. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court.


7



2014 Kentucky Base Rate Case

In December 2014, KPCo filed a request with the KPSC for an increase in rates of $70 million, which consists of a $75 million increase in rider rates, offset by a $5 million decrease in annual base rates, to be effective July 2015. The net increase reflects KPCo's ownership interest in the Mitchell Plant, riders to recover the Big Sandy Plant retirement and operational costs and the inclusion of an environmental compliance plan related to the Mitchell Plant FGD. Additionally, the filing included a request to recover deferred storm costs. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

PJM Capacity Auction

AGR is required to offer all of its available generation capacity in the PJM RPM auction, which is conducted three years in advance of the actual delivery year.

Through May 2015, AGR will provide generation capacity to OPCo for both switched and non-switched OPCo generation customers.  For switched customers, OPCo pays AGR $188.88/MW day for capacity.  For non-switched OPCo generation customers, OPCo pays AGR its blended tariff rate for capacity consisting of $188.88/MW day for auctioned load and the non-fuel generation portion of its base rate for non-auctioned load.  AGR’s excess capacity is subject to the PJM RPM auction. After May 2015, AGR's generation assets will be subject to PJM capacity prices.  Shown below are the current auction prices for capacity, as announced/settled by PJM:
 
 
PJM Base
PJM Auction Period
 
Auction Price
 
 
(per MW day)
June 2013 through May 2014
 
$
27.73

June 2014 through May 2015
 
125.99

June 2015 through May 2016
 
136.00

June 2016 through May 2017

59.37

June 2017 through May 2018
 
120.00


We expect a significant decline in AGR capacity revenues after May 2015 when the Power Supply Agreement between AGR and OPCo ends. We expect a further decline in AGR capacity revenues from June 2016 through May 2017 based upon the decrease in the PJM base auction price.

In conjunction with other utility companies, we continue to address mutual concerns related to the PJM capacity auction process. Through this advocacy effort, the FERC has accepted PJM recommendations which should have the impact of reducing capacity price volatility beginning in the June 2018 time period.

In December 2014, PJM filed with FERC for approval of a new type of capacity product, the Capacity Performance Product. The intent of the filing is to raise the level of capacity performance and reliability during emergency events by: (a) assessing higher penalties for non-performance during these events, (b) allowing higher price offers into the auction and (c) requiring generating units to provide fuel and operational assurances that they can perform reliably during emergency events.

In this same filing, PJM proposed with FERC supplemental capacity auctions for the June 2016 through May 2017 and June 2017 through May 2018 auction periods. These supplemental auctions would address capacity performance and reliability issues in these interim years, and if accepted, would allow AGR to re-offer at least part of the capacity already cleared for these years at a higher price. A FERC order is expected in the first half of 2015.


8



Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC. As of December 31, 2014, SWEPCo has incurred costs of $164 million and has remaining contractual construction obligations of $108 million related to these projects.  SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. See "Climate Change, CO2 Regulation and Energy Policy" section of “Environmental Issues” below.  As of December 31, 2014, the net book value of Welsh Plant, Units 1 and 3 was $388 million, before cost of removal, including materials and supplies inventory and CWIP.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.   

LITIGATION

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  We assess the probability of loss for each contingency and accrue a liability for cases that have a probable likelihood of loss if the loss can be estimated.  For details on our regulatory proceedings and pending litigation see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.  The New York court has granted our motion to transfer this case to the U.S. District Court for the Southern District of Ohio.  In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing.  We will continue to defend against the remaining claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with environmental control requirements.  We will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, proposals governing the beneficial use and disposal of coal combustion products, proposed clean water rules and renewal permits for certain water discharges that are currently under appeal.

We are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of our nuclear units.  We, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court.  We are also engaged in the development of future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change.  We believe that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

9



We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If we are unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.
 
Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of December 31, 2014, the AEP System had a total generating capacity of nearly 37,600 MWs, of which over 23,700 MWs are coal-fired.  We continue to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on our coal-fired generating facilities.  Based upon our estimates, additional investment to meet these proposed requirements ranges from approximately $2.8 billion to $3.3 billion through 2020.  These amounts include investments to convert some of our coal generation to natural gas.  If natural gas conversion is not completed, these units could be retired sooner than planned.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules.  The cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans (SIPs) or federal implementation plans (FIPs) that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on our units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.  In addition, we are continuing to evaluate the economic feasibility of environmental investments on nonregulated plants.

Subject to the factors listed above and based upon our continuing evaluation, we intend to retire the following plants or units of plants before or during 2016:
Company
 
Plant Name and Unit
 
Generating
Capacity
 
 
 
 
(in MWs)
AGR
 
Kammer Plant
 
630

AGR
 
Muskingum River Plant
 
1,440

AGR
 
Picway Plant
 
100

APCo
 
Clinch River Plant, Unit 3
 
235

APCo
 
Glen Lyn Plant
 
335

APCo
 
Kanawha River Plant
 
400

APCo/AGR
 
Sporn Plant
 
600

I&M
 
Tanners Creek Plant
 
995

KPCo
 
Big Sandy Plant, Unit 2
 
800

PSO
 
Northeastern Station, Unit 4
 
470

SWEPCo
 
Welsh Plant, Unit 2
 
528

Total
 
 
 
6,533


As of December 31, 2014, the net book value of the AGR units listed above was zero.  The net book value, before cost of removal, including related material and supplies inventory and CWIP balances, of the regulated plants in the table above was $980 million.  See Note 5 for further discussion.

In addition, we are in the process of obtaining permits following the KPSC's approval for the conversion of KPCo's 278 MW Big Sandy Plant, Unit 1 to natural gas. As of December 31, 2014, the net book value, before cost of removal, including related material and supplies inventory and CWIP balances of Big Sandy Plant, Unit 1 was $114 million.


10



Volatility in fuel prices, pending environmental rules and other market factors could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of coal-fired units.  For regulated plants that we may close early, we are seeking regulatory recovery of remaining net book values.  To the extent the book value of existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows and impact financial condition.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions.  The states implement and administer many of these programs and could impose additional or more stringent requirements.
 
The Federal EPA issued the Clean Air Interstate Rule (CAIR) in 2005 requiring specific reductions in SO2 and NOx emissions from power plants.  The Federal EPA issued the Cross-State Air Pollution Rule (CSAPR) in August 2011 to replace CAIR.  The CSAPR was challenged in the courts.  In 2012, a panel of the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing CAIR until a replacement rule is finalized.  That decision was appealed to the U.S. Supreme Court, which reversed the decision and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit.  All of the states in which our power plants are located are covered by CSAPR. See "Cross-State Air Pollution Rule (CSAPR)" section below.

The Federal EPA issued the final maximum achievable control technology (MACT) standards for coal and oil-fired power plants in 2012. See “Mercury and Other Hazardous Air Pollutants (HAPs) Regulation” section below.

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas.  BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.  CAVR will be implemented through SIPs or, if SIPs are not adequate or are not developed on schedule, through FIPs.  The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas.  Arkansas is developing a revised submittal.  In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the CSAPR trading programs to use those programs in place of source-specific BART for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states.  This rule is being challenged in the U.S. Court of Appeals for the District of Columbia Circuit.

In 2009, the Federal EPA issued a final mandatory reporting rule for CO2 and other greenhouse gases covering a broad range of facilities emitting in excess of 25,000 tons of CO2 emissions per year.   The Federal EPA issued a final endangerment finding for greenhouse gas emissions from new motor vehicles in 2009.  The Federal EPA determined that greenhouse gas emissions from stationary sources will be subject to regulation under the CAA beginning January 2011 and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, SIP calls and FIPs.  The Federal EPA has proposed to include CO2 emissions in standards that apply to new and existing electric utility units. See "Climate Change, CO2 Regulation and Energy Policy" section below.

The Federal EPA has also issued final, more stringent national ambient air quality standards (NAAQS) for PM, SO2 and proposed a more stringent NAAQS for ozone.  States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for our facilities as a result of those evaluations.  We cannot currently predict the nature, stringency or timing of those requirements.

Notable developments in significant CAA regulatory requirements affecting our operations are discussed in the following sections.

11



Cross-State Air Pollution Rule (CSAPR)

In 2011, the Federal EPA issued CSAPR.  Certain revisions to the rule were finalized in 2012.  CSAPR relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states.  Interstate trading of allowances is allowed on a restricted sub-regional basis.  Arkansas and Louisiana are subject only to the seasonal NOx program in the rule.  Texas is subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program.  The annual SO2 allowance budgets in Indiana, Ohio and West Virginia were reduced significantly in the rule.  A supplemental rule includes Oklahoma in the seasonal NOx program.  The supplemental rule was finalized in December 2011 with an increased NOx emission budget for the 2012 compliance year.  The Federal EPA issued a final Error Corrections Rule and further CSAPR revisions in 2012 to make corrections to state budgets and unit allocations and to remove the restrictions on interstate trading in the first phase of CSAPR.
 
Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit.  In 2012, the court issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the CAIR until a replacement rule is finalized.  The majority determined that the CAA does not allow the Federal EPA to “overcontrol” emissions in an upwind state and that the Federal EPA exceeded its statutory authority by failing to allow states an opportunity to develop their own implementation plans before issuing a FIP.  The petition for review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013. In April 2014, the U.S. Supreme Court issued a decision reversing in part the decision of the U.S. Court of Appeals for the District of Columbia Circuit and remanding the case for further proceedings consistent with the opinion. The Federal EPA filed a motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. The court granted the Federal EPA's motion, established a briefing schedule and scheduled oral argument for March 2015 on the remaining issues. Separate appeals of the Error Corrections Rule and the further revisions have been filed but no briefing schedules have been established. We cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metals) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  The effective date of the final rule was April 16, 2012 and compliance is required within three years.  Petitions for administrative reconsideration and judicial review were filed.  In 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards.  The Federal EPA issued revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions in March 2013.  The Federal EPA is still considering additional changes to the start-up and shut down provisions. In April 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the April 2012 final rule. Industry trade groups and several states filed petitions for further review in the U.S. Supreme Court and the court granted those petitions in November 2014.

The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and allows operators to exclude periods of start-up and shut down from the emissions averaging periods.  We have obtained a one-year administrative extension at several units to facilitate the installation of controls or to avoid a serious reliability problem.  In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades.  We remain concerned about the availability of compliance extensions, the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines and the lack of coordination among the Mercury and Air Toxics Standards schedule and other environmental requirements.


12



Climate Change, CO2 Regulation and Energy Policy

National public policy makers and regulators in the 11 states we serve have diverse views on climate change, carbon regulation and energy policy.  We are currently focused on responding to these emerging views with prudent actions across a range of plausible scenarios and outcomes.  We are active participants in both state and federal policy development to assure that any proposed new requirements are feasible and the economies of the states we serve are not placed at a competitive disadvantage.

Several states have adopted programs that directly regulate CO2 emissions from power plants.  The majority of the states where we have generating facilities have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions.  We are taking steps to comply with these requirements, including increasing our wind power purchases and broadening our portfolio of energy efficiency programs.

We estimate that our 2014 emissions were approximately 120 million metric tons.  This represents a reduction of 18% compared to our 2005 CO2 emissions of approximately 146 million metric tons.

In the absence of comprehensive federal climate change or energy policy legislation, President Obama issued a memorandum to the Administrator of the Federal EPA directing the agency to develop and issue a new proposal regulating carbon emissions from new electric generating units under the CAA.  The new proposal was issued in September 2013 and requires new large natural gas units to meet a limit of 1,000 pounds of CO2 per MWh of electricity generated and small natural gas units to meet a limit of 1,100 pounds of CO2 per MWh.  New coal-fired units are required to meet a limit of 1,100 pounds of CO2 per MWh, with the option to meet a 1,000 pound per MWh limit if they choose to average emissions over multiple years.  This proposal was published in the Federal Register in January 2014 and the comment period has closed.

The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from modified and reconstructed electric generating units (EGUs) and to issue guidelines for existing EGUs before June 2014, to finalize those standards by June 2015 and to require states to submit revisions to their implementation plans including such standards no later than June 2016. The Federal EPA issued guidelines for the development of standards for existing sources in June 2014. The guidelines use a “portfolio” approach to reducing emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units, expanding renewable generation resources and increasing customer energy efficiency. Comments were due in December 2014. The Federal EPA also issued proposed regulations governing emissions of CO2 from modified and reconstructed EGUs in June 2014 and comments were due in October 2014. The standards for modified and reconstructed units include several options, including use of historic baselines or energy efficiency audits to establish source-specific CO2 emission rates or to limit CO2 emission rates which could be no less than 1,900 pounds per MWh at larger coal units and 2,100 pounds per MWh at smaller coal units. The Federal EPA announced in January 2015 that the schedule for finalizing its action on all of these standards will extend into the summer of 2015 and that it will develop and propose for public comment a model FIP that will be finalized for individual states that fail to submit a timely state plan to implement the existing source standards. We cannot currently predict the impact these programs may have on future resource plans or our existing generating fleet, but the costs may be substantial.

In 2012, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO2 emissions from new motor vehicles and its plan to phase in regulation of CO2 emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. In June 2014, the U.S. Supreme Court determined that the Federal EPA was not compelled to regulate CO2 emissions from stationary sources under the Title V or PSD programs as a result of its adoption of the motor vehicle standards, but that sources otherwise required to obtain a PSD permit may be required to perform a Best Available Control Technology analysis for CO2 emissions if they exceed a reasonable level. The Federal EPA must undertake additional rulemaking to implement the court’s decision and establish an appropriate level.


13



Federal and state legislation or regulations that mandate limits on the emission of CO2 could result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force our utility subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets.  Public perception may ultimately have a significant impact on future legislation and regulation.

To the extent climate change affects a region’s economic health, it could also affect our revenues.  Our financial performance is tied to the health of the regional economies we serve.  The price of energy, as a factor in a region's cost of living as well as an important input into the cost of goods, has an impact on the economic health of our communities.  The cost of additional regulatory requirements would normally be borne by consumers through higher prices for energy and purchased goods.

Coal Combustion Residual Rule

In 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants.  The proposed rule contained two alternative proposals.  One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management.  Both proposals would impose stringent requirements for the construction of new coal ash landfills and existing unlined surface impoundments.

Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule.  To comply with a court-ordered deadline, the Federal EPA issued a prepublication copy of its final rule in December 2014. The rule is expected to be published in the Federal Register during the first quarter of 2015 and become effective six months following publication.

In the final rule, the Federal EPA elected to regulate CCR as a non-hazardous solid waste and issued new minimum federal solid waste management standards. On the effective date, the rule applies to new and existing active CCR landfills and CCR surface impoundments at operating electric utility or independent power production facilities. The rule imposes new and additional construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements. The rule does not apply to inactive CCR landfills and inactive surface impoundments at retired generating stations or the beneficial use of CCR. The rule is self-implementing so state action is not required. Because of this self-implementing feature, the rule contains extensive record keeping, notice and internet posting requirements. Because we currently use surface impoundments and landfills to manage CCR materials at our generating facilities, we will incur significant costs to upgrade or close and replace these existing facilities at some point in the future as the new rule is implemented. We continue to review the new rule and evaluate its costs and impacts to our operations, including ongoing monitoring requirements.

In February 2014, the Federal EPA completed a risk evaluation of the beneficial uses of coal fly ash in concrete and FGD gypsum in wallboard and concluded that the Federal EPA supports these beneficial uses.  Currently, approximately 40% of the coal ash and other residual products from our generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses.  Encapsulated beneficial uses are not materially impacted by the new rule but additional demonstrations may be required to continue land applications in significant amounts except in road construction projects.


14



Clean Water Act (CWA) Regulations

In 2014, the Federal EPA issued a final rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The final rule affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to comply with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures at facilities withdrawing more than 125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, are not expected to require any technology changes. Facilities subject to both the impingement standard and site-specific entrainment studies will typically be given at least three years to conduct and submit the results of those studies to the permit agency. Compliance timeframes will then be established by the permit agency through each facility’s National Pollutant Discharge Elimination System (NPDES) permit for installation of any required technology changes, as those permits are renewed over the next five to eight years. Petitions for review of the final rule have been filed by industry and environmental groups and are currently pending in the U.S. Court of Appeals for the Second Circuit.

In addition, the Federal EPA issued an information collection request and is developing revised effluent limitation guidelines for electricity generating facilities.  A proposed rule was signed in April 2013 with a final rule expected in September 2015.  The Federal EPA proposed eight options of increasing stringency and cost for fly ash and bottom ash transport water, scrubber wastewater, leachate from coal combustion byproduct landfills and impoundments and other wastewaters associated with coal-fired generating units, with four labeled preferred options.  Certain of the Federal EPA's preferred options have already been implemented or are part of our long-term plans.  We continue to review the proposal in detail to evaluate whether our plants are currently meeting the proposed limitations, what technologies have been incorporated into our long-range plans and what additional costs might be incurred if the Federal EPA's most stringent options were adopted.  We submitted detailed comments to the Federal EPA in September 2013 and participated in comments filed by various organizations of which we are members.

In April 2014, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a proposed rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases and published the proposed rule in the Federal Register. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This proposed jurisdictional definition will apply to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are: permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. We agree that clarity and efficiency in the permitting process is needed. We are concerned that the proposed rule introduces new concepts and could subject more of our operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. We submitted detailed comments to the Federal EPA in November 2014 and also participated in comments filed by various organizations of which we are members.

15



RESULTS OF OPERATIONS

SEGMENTS

Our primary business is the generation, transmission and distribution of electricity.  Within our Vertically Integrated Utilities segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

Our reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
OPCo purchases energy to serve SSO customers, and provides capacity for all connected load.

AEP Transmission Holdco

Development, construction and operation of transmission facilities through investments in our wholly-owned transmission subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.

Generation & Marketing

Nonregulated generation in ERCOT and PJM.
Marketing, risk management and retail activities in ERCOT, PJM and MISO.

AEP River Operations

Commercial barging operations that transports liquids, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.


16



The table below presents Earnings Attributable to AEP Common Shareholders by segment for the years ended December 31, 2014, 2013 and 2012.
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(in millions)
Vertically Integrated Utilities
 
$
708

 
$
677

 
$
800

Transmission and Distribution Utilities
 
355

 
358

 
389

AEP Transmission Holdco
 
151

 
80

 
43

Generation & Marketing
 
367

 
228

 
100

AEP River Operations
 
49

 
12

 
15

Corporate and Other (a)
 
4

 
125

 
(88
)
Earnings Attributable to AEP Common Shareholders
 
$
1,634

 
$
1,480

 
$
1,259


(a)
While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

AEP CONSOLIDATED

2014 Compared to 2013

Earnings Attributable to AEP Common Shareholders increased from $1,480 million in 2013 to $1,634 million in 2014 primarily due to:

Impairments during 2013 for the following:
Muskingum River Plant, Unit 5.
A decision from the KPSC disallowing scrubber costs on KPCo's Big Sandy Plant.
A net increase in weather-related usage.
Higher market prices and increased sales volumes.
An increase in transmission investment which resulted in higher revenues and income.
Successful rate proceedings during 2014 in our various jurisdictions.

These increases were partially offset by:

A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in 2013.
An increase in depreciation expense due to increased investments.
An increase in regulatory provisions in 2014.
An increase in fuel expense due to the termination of a long-term coal contract.
An increase in plant maintenance.
An increase in vegetation management expenses.


17



2013 Compared to 2012

Earnings Attributable to AEP Common Shareholders increased from $1,259 million in 2012 to $1,480 million in 2013 primarily due to:

Successful rate proceedings in our various jurisdictions.
2012 impairments of certain Ohio generation plants.
A decrease in Ohio depreciation expense due to impairments of certain Ohio generation plants.
A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in 2013.

These increases were partially offset by:

Impairments during 2013 for the following:
Muskingum River Plant, Unit 5.
A write-off from a disallowance of a portion of Amos Plant, Unit 3 pursuant to a Virginia SCC order.
A decision from the KPSC disallowing scrubber costs on KPCo's Big Sandy Plant.
The loss of retail generation customers in Ohio to various CRES providers.
2012 reversal of a 2011 recorded obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of OPCo's modified stipulation.

Our results of operations by operating segment are discussed below.

VERTICALLY INTEGRATED UTILITIES
 
 
Years Ended December 31,
Vertically Integrated Utilities
 
2014
 
2013
 
2012
 
 
(in millions)
Revenues
 
$
9,484

 
$
9,992

 
$
9,418

Fuel and Purchased Electricity
 
3,953

 
4,770

 
4,408

Gross Margin
 
5,531

 
5,222

 
5,010

Other Operation and Maintenance
 
2,515

 
2,276

 
2,219

Asset Impairments and Other Related Charges
 

 
72

 
13

Depreciation and Amortization
 
1,033

 
941

 
873

Taxes Other Than Income Taxes
 
370

 
372

 
344

Operating Income
 
1,613

 
1,561

 
1,561

Interest and Investment Income
 
4

 
7

 
5

Carrying Costs Income
 
6

 
14

 
28

Allowance for Equity Funds Used During Construction
 
47

 
35

 
72

Interest Expense
 
(526
)
 
(540
)
 
(520
)
Income Before Income Tax Expense and Equity Earnings
 
1,144

 
1,077

 
1,146

Income Tax Expense
 
434

 
398

 
345

Equity Earnings of Unconsolidated Subsidiaries
 
2

 
2

 
2

Net Income
 
712

 
681

 
803

Net Income Attributable to Noncontrolling Interests
 
4

 
4

 
3

Earnings Attributable to AEP Common Shareholders
 
$
708

 
$
677

 
$
800


18



Summary of KWh Energy Sales for Vertically Integrated Utilities
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2014
 
2013
 
2012
 
 
 
(in millions of KWhs)
 
Retail:
 
 
 
 
 
 
 
Residential
 
34,073

 
33,851

 
33,199

 
Commercial
 
25,048

 
25,037

 
25,278

 
Industrial
 
35,281

 
34,216

 
34,692

 
Miscellaneous
 
2,311

 
2,284

 
2,356

 
Total Retail
 
96,713

 
95,388

 
95,525

 
 
 
 
 
 
 
 
 
Wholesale (a)
 
34,241

 
NM

(b)
NM

(b)
 
 
 
 
 
 
 
 
Total KWhs
 
130,954

 
95,388

 
95,525

 

(a)
Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers.
(b)
2014 is not comparable to 2013 or 2012 due to the 2013 asset transfers related to corporate separation in Ohio on December 31, 2013 and the termination of the Interconnection Agreement effective January 1, 2014.
NM    Not meaningful.

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.  In general, degree day changes in our eastern region have a larger effect on net income than changes in our western region due to the relative size of the two regions and the number of customers within each region.
Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(in degree days)
Eastern Region
 
 
 
 
 
 
Actual – Heating (a)
 
3,313

 
2,949

 
2,216

Normal – Heating (b)
 
2,740

 
2,734

 
2,774

 
 
 
 
 
 
 
Actual – Cooling (c)
 
932

 
1,040

 
1,253

Normal – Cooling (b)
 
1,080

 
1,080

 
1,079

 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
Actual – Heating (a)
 
1,840

 
1,772

 
1,070

Normal – Heating (b)
 
1,510

 
1,501

 
1,537

 
 
 
 
 
 
 
Actual – Cooling (c)
 
2,049

 
2,163

 
2,635

Normal – Cooling (b)
 
2,203

 
2,202

 
2,186


(a)
Eastern Region and Western Region heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern Region and Western Region cooling degree days are calculated on a 65 degree temperature base.

19



2014 Compared to 2013
 
Reconciliation of Year Ended December 31, 2013 to Year Ended December 31, 2014
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Year Ended December 31, 2013
 
$
677

 
 
 
Changes in Gross Margin:
 
 
Retail Margins
 
212

Off-system Sales
 
123

Transmission Revenues
 
22

Other Revenues
 
(48
)
Total Change in Gross Margin
 
309

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(239
)
Asset Impairments and Other Related Charges
 
72

Depreciation and Amortization
 
(92
)
Taxes Other Than Income Taxes
 
2

Interest and Investment Income
 
(3
)
Carrying Costs Income
 
(8
)
Allowance for Equity Funds Used During Construction
 
12

Interest Expense
 
14

Total Change in Expenses and Other
 
(242
)
 
 
 
Income Tax Expense
 
(36
)
 
 
 
Year Ended December 31, 2014
 
$
708


The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
Retail Margins increased $212 million primarily due to the following:

The effect of successful rate proceedings in our service territories, which include:
 
 
A $129 million rate increase for APCo.
 
 
A $55 million rate increase for KPCo.
 
 
A $45 million rate increase for I&M.
 
 
A $22 million rate increase for SWEPCo.
 
 
A $12 million rate increase for PSO.
 
 
A $9 million rate increase for WPCo.
 
For the rate increases described above, $153 million relates to riders/trackers which have corresponding increases in other expense items below.
 
A $14 million increase due to favorable weather conditions.
 
These increases were partially offset by:
 
A $43 million increase in PJM expenses net of recovery or offsets.
 
A $36 million decrease due to a fuel proceeding disallowance.
Margins from Off-system Sales increased $123 million primarily due to higher market prices and changes in margin sharing.
Transmission Revenues increased $22 million primarily due to increased investment in the PJM region.
Other Revenues decreased $48 million primarily due to a decrease in barging because River Transportation Division (RTD) is no longer serving plants transferred from OPCo to AGR as of December 31, 2013 as a result of corporate separation in Ohio. This decrease in RTD revenue has a corresponding decrease in Other Operation and Maintenance expenses for barging as discussed below.


20



Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $239 million primarily due to the following:
 
A $56 million increase in recoverable expenses, primarily including PJM expenses, currently fully recovered in rate recovery riders/trackers, partially offset by RTD expenses for barging activities.
 
A $46 million increase in employee related expenses.
 
A $45 million increase in transmission services related to PJM and SPP services.
 
A $43 million increase in plant outage and maintenance expense primarily due to higher planned and advanced spending.
 
A $26 million increase in distribution and transmission vegetation management expenses primarily due to higher advanced spending.
 
A $25 million increase due to a favorable settlement of an insurance claim in the first quarter of 2013.
 
A $10 million increase due to the write-off of IGCC costs in Virginia.
 
An $8 million increase due to an accrual for future environmental remediation costs.
 
These increases were partially offset by:
 
A $30 million write-off in the first quarter of 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.
 
A $23 million decrease in storm expense primarily in the APCo service territory.
Asset Impairments and Other Related Charges decreased $72 million primarily due to the following:
 
A $39 million decrease due to APCo's 2013 write-off from a regulatory disallowance of a portion of Amos Plant, Unit 3 pursuant to a Virginia SCC order approving the transfer of Amos Plant, Unit 3.
 
A $33 million decrease due to KPCo's 2013 write-off of scrubber costs on the Big Sandy Plant and other generation costs in accordance with the KPSC's October 2013 order.
Depreciation and Amortization expenses increased $92 million primarily due to higher depreciable base.
Carrying Cost Income decreased $8 million primarily due to the November 2013 securitization of the West Virginia ENEC deferral balance.
Allowance for Equity Funds Used During Construction increased $12 million primarily due to increases in environmental construction and transmission projects.
Interest Expense decreased $14 million primarily due to the following:
 
A $6 million decrease due to the retirement of KPCo Senior Unsecured Notes in the third quarter of 2013.
 
A $4 million decrease due to the redemption of I&M Senior Unsecured Notes in the fourth quarter of 2013.
 
A $4 million decrease due to rate approvals in Louisiana and Texas as well as an increase in the debt component of AFUDC due to increased transmission and environmental projects.
Income Tax Expense increased $36 million primarily due to an increase in pretax book income, the recording of state income tax adjustments and other book/tax differences which are accounted for on a flow-through basis, partially offset by the recording of federal income tax adjustments.


21



2013 Compared to 2012
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Year Ended December 31, 2012
 
$
800

 
 
 
Changes in Gross Margin:
 
 
Retail Margins
 
196

Off-system Sales
 
(26
)
Transmission Revenues
 
41

Other Revenues
 
1

Total Change in Gross Margin
 
212

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(57
)
Asset Impairments and Other Related Charges
 
(59
)
Depreciation and Amortization
 
(68
)
Taxes Other Than Income Taxes
 
(28
)
Interest and Investment Income
 
2

Carrying Costs Income
 
(14
)
Allowance for Equity Funds Used During Construction
 
(37
)
Interest Expense
 
(20
)
Total Change in Expenses and Other
 
(281
)
 
 
 
Income Tax Expense
 
(53
)
Net Income Attributable to Noncontrolling Interests
 
(1
)
 
 
 
Year Ended December 31, 2013
 
$
677


The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
Retail Margins increased $196 million primarily due to the following:
 
Successful rate proceedings in our service territories, which include:
 
 
A $153 million rate increase for SWEPCo.
 
 
A $112 million rate increase for I&M.
 
 
A $9 million rate increase for APCo.
 
 
 
For the rate increases described above, $42 million relates to riders/trackers which have corresponding increases in other expense items below.
 
A $29 million increase in weather-related usage in our eastern and western regions primarily due to increases of 33% and 66%, respectively, in heating degree days, partially offset by decreases in our eastern and western regions of 17% and 18%, respectively, in cooling degree days.
 
These increases were partially offset by:
 
A $15 million decrease in SWEPCo's municipal and cooperative revenues primarily due to lower realizations from changes in sales volume mix.
 
A $23 million decrease due to lower weather normalized retail sales.
 
A $12 million increase in other variable electric generation expenses.
 
A $9 million deferral of APCo's additional wind purchase costs in 2012 as a result of the June 2012 Virginia SCC fuel factor order.
 
A $9 million decrease due to adjustments for previously disallowed environmental costs by the November 2011 Virginia SCC order subsequently determined in 2012 to be appropriate for recovery by the Supreme Court of Virginia.

22



Margins from Off-system Sales decreased $26 million primarily due to lower PJM capacity revenue, reduced trading and marketing margins, partially offset by higher prices and volumes.
Transmission Revenues increased $41 million primarily due to increased investment in the PJM and SPP regions.  These increased revenues are partially offset by Other Operation and Maintenance expenses below.

Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $57 million primarily due to the following:
 
A $33 million increase in recoverable PJM and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers.
 
A $30 million write-off in 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.
 
A $22 million increase in storm-related expenses primarily in APCo's service territory.
 
A $21 million increase in plant outage expenses.
 
These increases were partially offset by:
 
A $26 million decrease due to expenses related to the 2012 sustainable cost reductions.
 
A $25 million decrease due to an agreement reached to settle an insurance claim in 2013.
Asset Impairments and Other Related Charges increased $59 million primarily due to the following:
 
A $39 million increase due to APCo's 2013 write-off from a regulatory disallowance of a portion of Amos Plant, Unit 3 pursuant to a Virginia SCC order approving the transfer of Amos Plant, Unit 3.
 
A $33 million increase due to KPCo's 2013 write-off of scrubber costs on the Big Sandy Plant and other generation costs in accordance with the KPSC's October 2013 order.
 
These increases were partially offset by:
 
A 2012 write-off of an additional $13 million related to SWEPCo's expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap.
Depreciation and Amortization expenses increased $68 million primarily due to the following:
 
A $40 million increase due to the Turk Plant being placed in service in December 2012.
 
A $26 million increase due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant's estimated life approved by the MPSC effective April 2012 and by the IURC effective March 2013.  The majority of the increase in depreciation for Tanners Creek Plant's life is offset within Gross Margin.
 
Overall higher depreciable property balances.
 
These increases were partially offset by:
 
A $13 million decrease in amortization as a result of the cessation of the Virginia Environmental and Reliability surcharge and the Virginia Environmental Rate Adjustment Clause in January 2013 and March 2013, respectively.
Taxes Other Than Income Taxes increased $28 million primarily due to increased property taxes as a result of increased capital investments.
Carrying Costs Income decreased $14 million primarily due to an increased recovery of Virginia environmental costs in new base rates as approved by the Virginia SCC in late January 2012 and decreased carrying charges related to the Dresden Plant.
Allowance for Equity Funds Used During Construction decreased $37 million primarily due to completed construction of the Turk Plant in December 2012.
Interest Expense increased $20 million primarily due to a decrease in the debt component of AFUDC due to completed construction of the Turk Plant in December 2012, partially offset by lower average outstanding long-term debt balances and an increase in the debt component of AFUDC related to projects at the Cook Plant.
Income Tax Expense increased $53 million primarily due to the recording of federal and state income tax adjustments and other book/tax differences which are accounted for on a flow-through basis, partially offset by a decrease in pretax book income.


23



TRANSMISSION AND DISTRIBUTION UTILITIES
 
 
Years Ended December 31,
Transmission and Distribution Utilities
 
2014
 
2013
 
2012
 
 
(in millions)
Revenues
 
$
4,814

 
$
4,478

 
$
4,818

Purchased Electricity
 
1,520

 
1,627

 
2,071

Amortization of Generation Deferrals
 
111

 

 

Gross Margin
 
3,183

 
2,851

 
2,747

Other Operation and Maintenance
 
1,276

 
1,003

 
911

Depreciation and Amortization
 
658

 
591

 
561

Taxes Other Than Income Taxes
 
453

 
435

 
428

Operating Income
 
796

 
822

 
847

Interest and Investment Income
 
11

 
2

 
4

Carrying Costs Income
 
27

 
16

 
24

Allowance for Equity Funds Used During Construction
 
12

 
8

 
6

Interest Expense
 
(280
)
 
(292
)
 
(291
)
Income Before Income Tax Expense
 
566

 
556

 
590

Income Tax Expense
 
211

 
198

 
201

Net Income
 
355

 
358

 
389

Net Income Attributable to Noncontrolling Interests
 

 

 

Earnings Attributable to AEP Common Shareholders
 
$
355

 
$
358

 
$
389

Summary of KWh Energy Sales for Transmission and Distribution Utilities
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2014
 
2013
 
2012
 
 
 
(in millions of KWhs)
 
Retail:
 
 
 
 
 
 
 
Residential
 
26,209

 
25,531

 
25,581

 
Commercial
 
25,307

 
24,631

 
24,746

 
Industrial
 
21,830

 
22,668

 
24,902

 
Miscellaneous
 
713

 
710

 
716

 
Total Retail (a)
 
74,059

 
73,540

 
75,945

 
 
 
 
 
 
 
 
 
Wholesale (b)
 
2,198

 
NM

(c)
NM

(c)
 
 
 
 
 
 
 
 
Total KWhs
 
76,257

 
73,540

 
75,945

 

(a)
Represents energy delivered to distribution customers.
(b)
Ohio's contractually obligated purchases of OVEC power sold into PJM.
(c)
2014 is not comparable to 2013 or 2012 due to the 2013 asset transfers related to corporate separation in Ohio on December 31, 2013 and the termination of the Interconnection Agreement effective January 1, 2014.
NM    Not meaningful.


24



Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.  In general, degree day changes in our eastern region have a larger effect on net income than changes in our western region due to the relative size of the two regions and the number of customers within each region.
Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(in degree days)
Eastern Region
 
 
 
 
 
 
Actual – Heating (a)
 
3,734

 
3,383

 
2,610

Normal – Heating (b)
 
3,230

 
3,229

 
3,276

 
 
 
 
 
 
 
Actual – Cooling (c)
 
949

 
1,029

 
1,248

Normal – Cooling (b)
 
960

 
954

 
948

 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
Actual – Heating (a)
 
428

 
368

 
177

Normal – Heating (b)
 
337

 
337

 
352

 
 
 
 
 
 
 
Actual – Cooling (d)
 
2,553

 
2,737

 
3,100

Normal – Cooling (b)
 
2,618

 
2,608

 
2,584


(a)
Heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.
(d)
Western Region cooling degree days are calculated on a 70 degree temperature base.

25



2014 Compared to 2013
 
Reconciliation of Year Ended December 31, 2013 to Year Ended December 31, 2014
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
Year Ended December 31, 2013
 
$
358

 
 
 
Changes in Gross Margin:
 
 
Retail Margins
 
236

Off-System Sales
 
3

Transmission Revenues
 
71

Other Revenues
 
22

Total Change in Gross Margin
 
332

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(273
)
Depreciation and Amortization
 
(67
)
Taxes Other Than Income Taxes
 
(18
)
Interest and Investment Income
 
9

Carrying Costs Income
 
11

Allowance for Equity Funds Used During Construction
 
4

Interest Expense
 
12

Total Change in Expenses and Other
 
(322
)
 
 
 
Income Tax Expense
 
(13
)
 
 
 
Year Ended December 31, 2014
 
$
355


The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
Retail Margins increased $236 million primarily due to the following:
 
A $106 million increase in revenues primarily associated with Ohio rate riders/trackers and PJM revenues, partially offset by regulatory provisions.  These increases have corresponding increases in expense items discussed below.
 
A $96 million increase in TCC and TNC revenues primarily due to the recovery of ERCOT transmission expenses which is offset in Other Operation and Maintenance below.
Transmission Revenues increased $71 million primarily due to:

A $58 million increase primarily due to increased transmission revenues from customers who have switched to alternative CRES providers, rate increases for customers in the PJM region and increased transmission investment. This increase in transmission revenues related to CRES providers primarily offsets lost revenues included in Retail Margins above.
 
A $14 million increase primarily due to increased transmission investment in ERCOT.
Other Revenues increased $22 million primarily due to an increase in Texas securitization revenues which is offset in Depreciation and Amortization and Interest Expense below.


26



Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $273 million primarily due to the following:

A $213 million increase in recoverable expenses, including PJM expenses, ERCOT expenses and the Ohio storm amortization, currently fully recovered in rate recovery riders/trackers.
 
A $19 million increase in expenses related to various distribution services as a result of advanced spending.

An $18 million increase in remitted Universal Service Fund (USF) surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase is offset by an increase in Retail Margins above.
 
A $9 million increase in vegetation management expenses primarily due to advanced spending.
Depreciation and Amortization expenses increased $67 million primarily due to the following:
 
A $39 million increase in amortization related to OPCo and TCC securitizations, which are partially offset in Retail Margins and Other Revenues above.
 
A $28 million increase due to an increase in the depreciable base of transmission and distribution assets.
Taxes Other Than Income Taxes increased $18 million primarily due to increased property taxes.
Interest and Investment Income increased $9 million primarily due to interest on affiliated notes resulting from corporate separation.
Carrying Costs Income increased $11 million primarily due to increased capacity deferral carrying charges.
Interest Expense decreased $12 million primarily due to reduced TCC securitization long-term debt outstanding, which is partially offset in Other Revenues above.
Income Tax Expense increased $13 million primarily due to an increase in pretax book income and by the recording of federal and state income tax adjustments.

27



2013 Compared to 2012
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
Year Ended December 31, 2012
 
$
389

 
 
 
Changes in Gross Margin:
 
 
Retail Margins
 
55

Off-System Sales
 
1

Transmission Revenues
 
46

Other Revenues
 
2

Total Change in Gross Margin
 
104

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(92
)
Depreciation and Amortization
 
(30
)
Taxes Other Than Income Taxes
 
(7
)
Interest and Investment Income
 
(2
)
Carrying Costs Income
 
(8
)
Allowance for Equity Funds Used During Construction
 
2

Interest Expense
 
(1
)
Total Change in Expenses and Other
 
(138
)
 
 
 
Income Tax Expense
 
3

 
 
 
Year Ended December 31, 2013
 
$
358


The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:
Retail Margins increased $55 million primarily due to the following:
 
A $123 million increase in revenues associated with OPCo's USF surcharge and Distribution Investment Recovery Rider.  A portion of these increases have corresponding increases in other expense items below.
 
A $17 million increase related to favorable regulatory proceedings for OPCo.
 
These increases were partially offset by:
 
A $40 million decrease related to Ohio customers switching to alternative CRES providers.  This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
 
A $35 million decrease due to OPCo's partial reversal in 2012 of a 2011 fuel provision related to CRES providers.
Transmission Revenues increased $46 million primarily due to increased transmission revenues from Ohio customers who switched to alternative CRES providers.


28



Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $92 million primarily due to the following:
 
An $86 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase was offset by a corresponding increase in Retail Margins above.
 
A $30 million net increase related to the reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of the Ohio modified stipulation and the PUCO's August 2012 approval of the June 2012-May 2015 ESP.
 
These increases were partially offset by:
 
A $14 million decrease in expenses related to the 2012 sustainable cost reductions.
 
A $13 million decrease in Ohio's gridSMART® expenses primarily due to a reduction in the operation and maintenance component of the gridSMART® rider for prior years' over collections.  This decrease was partially offset by a corresponding increase in Depreciation and Amortization.
Depreciation and Amortization expenses increased $30 million primarily due to the following:
 
An $8 million increase due to OPCo's and TCC's issuance of securitization bonds in August 2013 and March 2012, respectively.  This increase in OPCo's and TCC's securitization related amortizations are offset within Gross Margin.
 
A $7 million increase due to increased investment in distribution and transmission plant.
 
A $4 million increase in Ohio's gridSMART® expenses primarily due to an increase in the depreciation component of the gridSMART® rider to recover prior years' under collections.  This increase was offset by a corresponding decrease in Operation and Maintenance expenses above.
Taxes Other Than Income Taxes increased $7 million primarily due to increased property taxes.
Carrying Costs Income decreased $8 million primarily due to the first quarter 2012 recording of debt carrying costs prior to TCC's issuance of securitization bonds in March 2012.
Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income, partially offset by the recording of state income tax adjustments.
 

29



AEP TRANSMISSION HOLDCO


Years Ended December 31,
AEP Transmission Holdco

2014

2013

2012


(in millions)
Transmission Revenues

$
192


$
78


$
24

Gross Margin

192


78


24

Other Operation and Maintenance

29


12


9

Depreciation and Amortization

24


10


3

Taxes Other Than Income Taxes

32


20


5

Operating Income

107


36


7

Carrying Costs Income
 

 

 
1

Allowance for Equity Funds Used During Construction

45


30


14

Interest Expense

(23
)

(10
)

(3
)
Income Before Income Tax Expense

129


56


19

Income Tax Expense

63


29


17

Equity Earnings of Unconsolidated Subsidiaries

85


53


41

Net Income

151


80


43

Net Income Attributable to Noncontrolling Interests






Earnings Attributable to AEP Common Shareholders

$
151


$
80


$
43


Summary of Net Plant In Service and CWIP for Transmission Holdco

 
 
As of December 31,
 
 
2014
 
2013
 
2012
 
 
(in millions)
Net Plant In Service
 
$
1,801

 
$
982

 
$
374

CWIP
 
889

 
645

 
370



30



2014 Compared to 2013
 
Reconciliation of Year Ended December 31, 2013 to Year Ended December 31, 2014
Earnings Attributable to AEP Common Shareholders from Transmission Holdco
(in millions)
Year Ended December 31, 2013
 
$
80

 
 
 
Changes in Transmission Revenues:
 
 
Transmission Revenues
 
114

Total Change in Transmission Revenues
 
114

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(17
)
Depreciation and Amortization
 
(14
)
Taxes Other Than Income Taxes
 
(12
)
Allowance for Equity Funds Used During Construction
 
15

Interest Expense
 
(13
)
Total Change in Expenses and Other
 
(41
)
 
 
 
Income Tax Expense
 
(34
)
Equity Earnings
 
32

 
 
 
Year Ended December 31, 2014
 
$
151


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 $114 million primarily due to an increase in projects placed in-service by our wholly-owned transmission subsidiaries.

Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $17 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $14 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $12 million primarily due to increased property taxes.
Allowance for Equity Funds Used During Construction increased $15 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 $34 million primarily due to an increase in pretax book income.
Equity Earnings increased $32 million primarily due to an increase in transmission investment by ETT.


31



2013 Compared to 2012

Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
Earnings Attributable to AEP Common Shareholders from Transmission Holdco
(in millions)
Year Ended December 31, 2012
 
$
43

 
 
 
Changes in Transmission Revenues:
 
 
Transmission Revenues
 
54

Total Change in Transmission Revenues
 
54

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(3
)
Depreciation and Amortization
 
(7
)
Taxes Other Than Income Taxes
 
(15
)
Carrying Costs Income
 
(1
)
Allowance for Equity Funds Used During Construction
 
16

Interest Expense
 
(7
)
Total Change in Expenses and Other
 
(17
)
 
 
 
Income Tax Expense
 
(12
)
Equity Earnings
 
12

 
 
 
Year Ended December 31, 2013
 
$
80


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 $54 million primarily due to an increase in projects placed in-service by our wholly-owned transmission subsidiaries.

Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $3 million primarily due increased transmission investment.
Depreciation and Amortization expenses increased $7 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $15 million primarily due to increased property taxes.
Allowance for Equity Funds Used During Construction increased $16 million primarily due to increased transmission investment.
Interest Expense increased $7 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $12 million primarily due to an increase in pretax book income, partially offset by other book/tax differences which are accounted for on a flow-through basis.
Equity Earnings increased $12 million primarily due to an increase in transmission investment by ETT.

32



GENERATION & MARKETING
 
 
Years Ended December 31,
Generation & Marketing
 
2014
 
2013
 
2012
 
 
(in millions)
Revenues
 
$
3,850

 
$
3,665

 
$
3,467

Fuel, Purchased Electricity and Other
 
2,436

 
2,305

 
2,065

Gross Margin
 
1,414

 
1,360

 
1,402

Other Operation and Maintenance
 
550

 
523

 
507

Asset Impairments and Other Related Charges
 

 
154

 
287

Depreciation and Amortization
 
227

 
236

 
349

Taxes Other Than Income Taxes
 
50

 
54

 
62

Operating Income
 
587

 
393

 
197

Interest and Investment Income
 
5

 
2

 
1

Interest Expense
 
(46
)
 
(55
)
 
(83
)
Income Before Income Tax Expense
 
546

 
340

 
115

Income Tax Expense
 
179

 
112

 
15

Net Income
 
367

 
228

 
100

Net Income Attributable to Noncontrolling Interests
 

 

 

Earnings Attributable to AEP Common Shareholders
 
$
367

 
$
228

 
$
100

Summary of MWhs Generated for Generation & Marketing
 
 
 
 
 
 
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(in millions of MWhs)
Fuel Type:
 
 
 
 
 
Coal
38
 
38
 
37
Natural Gas
7
 
6
 
11
Wind
1
 
1
 
1
Total MWhs
46
 
45
 
49


33



2014 Compared to 2013
 
Reconciliation of Year Ended December 31, 2013 to Year Ended December 31, 2014
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
Year Ended December 31, 2013
 
$
228

 
 
 
Changes in Gross Margin:
 
 
Generation
 
57

Retail, Trading and Marketing
 
(4
)
Other
 
1

Total Change in Gross Margin
 
54

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(27
)
Asset Impairments and Other Related Charges
 
154

Depreciation and Amortization
 
9

Taxes Other Than Income Taxes
 
4

Interest and Investment Income
 
3

Interest Expense
 
9

Total Change in Expenses and Other
 
152

 
 
 
Income Tax Expense
 
(67
)
 
 
 
Year Ended December 31, 2014
 
$
367


The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain cost of service for retail operations were as follows:
Generation increased $57 million primarily due to $111 million of increased demand and market prices driven by cold temperatures in the first quarter of 2014, partially offset by $54 million due to the termination of a long-term coal contract.

Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $27 million primarily due to increased ARO costs related to planned retirements.
Asset Impairments and Other Related Charges decreased by $154 million primarily due to the 2013 impairment of Muskingum River Plant, Unit 5.
Depreciation and Amortization expenses decreased $9 million primarily due to the 2013 impairment of Muskingum River Plant, Unit 5.
Interest Expense decreased $9 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
Income Tax Expense increased $67 million primarily due to an increase in pretax book income.

34



2013 Compared to 2012
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
Year Ended December 31, 2012
 
$
100

 
 
 
Changes in Gross Margin:
 
 
Generation
 
(44
)
Retail, Trading and Marketing
 
4

Other
 
(2
)
Total Change in Gross Margin
 
(42
)
 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(16
)
Asset Impairments and Other Related Charges
 
133

Depreciation and Amortization
 
113

Taxes Other Than Income Taxes
 
8

Interest and Investment Income
 
1

Interest Expense
 
28

Total Change in Expenses and Other
 
267

 
 
 
Income Tax Expense
 
(97
)
 
 
 
Year Ended December 31, 2013
 
$
228


The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain cost of service for retail operations were as follows:
Generation decreased $44 million primarily due to the following:
 
A $336 million decrease in affiliated sales to OPCo primarily due to customers switching to alternative CRES providers as well as a reduction in industrial usage.
 
This decrease was partially offset by the following:
 
A $221 million net increase in sales to AEP affiliates under the Interconnection Agreement.
 
A $63 million decrease in fuel expenses due to a reduction in generation at the Lawrenceburg Plant.

Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $16 million primarily due to a 2013 adjustment of $14 million to impaired plant investment as a result of changes to asset retirement obligations for asbestos removal and retirement of ash disposal facilities at impaired plants.
Asset Impairments and Other Related Charges decreased $133 million due to the following:
 
A 2012 impairment of $287 million for certain Ohio generation plants, which includes $13 million of related materials and supplies inventory.
 
This decrease was partially offset by:
 
A 2013 impairment of $154 million for Muskingum River Plant, Unit 5.
Depreciation and Amortization expenses decreased $113 million primarily due to depreciation ceasing on certain Ohio generation plants that were impaired in November 2012 and June 2013.
Interest Expense decreased $28 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
Income Tax Expense increased $97 million primarily due to an increase in pretax book income and by the recording of state income tax adjustments.


35



AEP RIVER OPERATIONS

2014 Compared to 2013

Earnings attributable to AEP Common Shareholders from our AEP River Operations segment increased from $12 million in 2013 to $49 million in 2014 due to a 28% increase in barge freight revenue for 2014 compared to 2013. The increase in 2014 freight revenue over 2013 was driven by strong barge freight demand particularly for export grain, strong northbound imports of fertilizer, salt and steel and increased shipments of domestic coal.

2013 Compared to 2012

Earnings attributable to AEP Common Shareholders from our AEP River Operations segment decreased from $15 million in 2012 to $12 million in 2013 primarily due to significant reductions in export grain and coal demand.  In addition, low water levels in the first and fourth quarters of 2013 limited barge loads and tow sizes.

CORPORATE AND OTHER

2014 Compared to 2013

Earnings attributable to AEP Common Shareholders from Corporate and Other decreased from $125 million in 2013 to $4 million in 2014 primarily due to a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in 2013.

2013 Compared to 2012

Earnings attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $88 million in 2012 to income of $125 million in 2013 primarily due to a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in 2013 as well as a reduction in interest expense associated with the early retirement of debt in 2012.

AEP SYSTEM INCOME TAXES

2014 Compared to 2013

Income Tax Expense increased $258 million primarily due to an increase in pretax book income and the recording of state income tax adjustments and by a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in 2013.

2013 Compared to 2012

Income Tax Expense increased $80 million primarily due to an increase in pretax book income and the recording of state income tax adjustments, partially offset by a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in 2013.


36



FINANCIAL CONDITION

We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization
 
 
December 31,
 
 
2014
 
2013
 
 
(dollars in millions)
Long-term Debt, including amounts due within one year
 
$
18,684

 
50.7
%
 
$
18,377

 
52.2
%
Short-term Debt
 
1,346

 
3.6

 
757

 
2.1

Total Debt
 
20,030

 
54.3

 
19,134

 
54.3

AEP Common Equity
 
16,820

 
45.7

 
16,085

 
45.7

Noncontrolling Interests
 
4

 

 
1

 

Total Debt and Equity Capitalization
 
$
36,854

 
100.0
%
 
$
35,220

 
100.0
%

Our ratio of debt-to-total capital remained unchanged at 54.3% as of December 31, 2014 and 2013.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability.  We believe we have adequate liquidity under our existing credit facilities.  As of December 31, 2014, we had $3.5 billion in aggregate credit facility commitments to support our operations.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  We are committed to maintaining adequate liquidity.  We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, sale-leaseback or leasing agreements or common stock.

Commercial Paper Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  As of December 31, 2014, our available liquidity was approximately $3 billion as illustrated in the table below:
 
 
Amount
 
Maturity
 
 
(in millions)
 
 
Commercial Paper Backup:
 
 
 
 
Revolving Credit Facility
 
$
1,750

 
June 2017
Revolving Credit Facility
 
1,750

 
July 2018
Total
 
3,500

 
 
Cash and Cash Equivalents
 
163

 
 
Total Liquidity Sources
 
3,663

 
 
Less: AEP Commercial Paper Outstanding
 
602

 
 
Letters of Credit Issued
 
63

 
 
 
 
 
 
 
Net Available Liquidity
 
$
2,998

 
 

We have credit facilities totaling $3.5 billion to support our commercial paper program.  The credit facilities allow us to issue letters of credit in an amount up to $1.2 billion.


37



We use our commercial paper program to meet the short-term borrowing needs of our subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  The maximum amount of commercial paper outstanding during 2014 was $877 million.  The weighted-average interest rate for our commercial paper during 2014 was 0.29%.

Other Credit Facilities

In January 2014, we issued letters of credit utilizing the entire amount available under an $85 million uncommitted facility. In October 2014, we renewed the uncommitted facility through October 2015 and increased the size of the facility to $100 million.  As of December 31, 2014, the maximum future payments issued under the uncommitted facility was $81 million with a maturity date of July 2015. An uncommitted facility gives the issuer of the facility the right to accept or decline each request we make under the facility.

Financing Plan

As of December 31, 2014, we have $2.5 billion of long-term debt due within one year which includes $785 million of Pollution Control Bonds with mandatory tender dates and credit support for variable interest rates that requires the debt be classified as current.  Also included in our long-term debt due within one year is $427 million of securitization bonds and DCC Fuel notes which will be repaid.  We plan to refinance the majority of our other maturities due within one year.

Securitized Accounts Receivables

Our receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables.  The agreement expires in June 2016.  

Debt Covenants and Borrowing Limitations

Our credit agreements contain certain covenants and require us to maintain our 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 our credit agreements.  Debt as defined in the credit agreements excludes securitization bonds and debt of AEP Credit.  As of December 31, 2014, this contractually-defined percentage was 51%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  As of December 31, 2014, we complied with all of the covenants contained in these credit agreements.  In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, 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.  This condition also applies in a majority of our non-exchange traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable.  However, a default under our non-exchange traded commodity contracts would not cause an event of default under our credit agreements.

The revolving 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 we manage our borrowings to stay within those authorized limits.


38



Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.53 per share in January 2015.  Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time.  Our income derives from our common stock equity in the earnings of our utility subsidiaries.  Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.  However, we do not believe these restrictions will have any significant impact on Parent’s ability to access cash to meet the payment of dividends on its common stock.

Credit Ratings

We do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but our access to the commercial paper market may depend on our credit ratings.  In addition, downgrades in our credit ratings by one of the rating agencies could increase our borrowing costs.  Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject us to additional collateral demands under adequate assurance clauses under our derivative and non-derivative energy contracts.

CASH FLOW

Managing our cash flows is a major factor in maintaining our liquidity strength.
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(in millions)
Cash and Cash Equivalents at Beginning of Period
 
$
118

 
$
279

 
$
221

Net Cash Flows from Operating Activities
 
4,613

 
4,106

 
3,804

Net Cash Flows Used for Investing Activities
 
(4,406
)
 
(3,818
)
 
(3,391
)
Net Cash Flows Used for Financing Activities
 
(162
)
 
(449
)
 
(355
)
Net Increase (Decrease) in Cash and Cash Equivalents
 
45

 
(161
)
 
58

Cash and Cash Equivalents at End of Period
 
$
163

 
$
118

 
$
279


Cash from operations and short-term borrowings provides working capital and allows us to meet other short-term cash needs.
 
Operating Activities
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(in millions)
Net Income
 
$
1,638

 
$
1,484

 
$
1,262

Depreciation and Amortization
 
1,929

 
1,743

 
1,782

Other
 
1,046

 
879

 
760

Net Cash Flows from Operating Activities
 
$
4,613

 
$
4,106

 
$
3,804


Net Cash Flows from Operating Activities were $4.6 billion in 2014 consisting primarily of Net Income of $1.6 billion, and $1.9 billion of noncash Depreciation and Amortization.  Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Deferred Income Taxes increased primarily due to provisions in the Tax Increase Prevention Act of 2014 and an increase in tax versus book temporary differences from operations.  The reduction in Fuel, Material and Supplies balance reflect a decrease in fuel inventory due to cold winter weather and increased generation.  


39



Net Cash Flows from Operating Activities were $4.1 billion in 2013 consisting primarily of Net Income of $1.5 billion, $1.7 billion of noncash Depreciation and Amortization and $226 million of Asset Impairments related to Muskingum River Plant, Unit 5, Big Sandy and Amos Plants, partially offset by $214 million of Ohio capacity deferrals as a result of a 2012 PUCO order.  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 and liabilities.  Deferred Income Taxes increased primarily due to provisions in the Taxpayer Relief Act of 2012 and an increase in tax versus book temporary differences from operations.  Significant changes in other items include the favorable impact of a decrease in fuel inventory and net cash flows for Accrued Taxes as a result of the recognition of the tax benefit related to the U.K. Windfall Tax.

Net Cash Flows from Operating Activities were $3.8 billion in 2012 consisting primarily of Net Income of $1.3 billion, $1.8 billion of noncash Depreciation and Amortization and $287 million in Asset Impairments related to certain Ohio generation assets.  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 and liabilities.  A significant change in other items includes the unfavorable impact of an increase in fuel inventory due to the mild winter weather.  Deferred Income Taxes increased primarily due to provisions in the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Jobs Creation Act and an increase in tax versus book temporary differences from operations.  During 2012, we also contributed $200 million to our qualified pension trust.
 
Investing Activities
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(in millions)
Construction Expenditures
 
$
(4,134
)
 
$
(3,624
)
 
$
(3,025
)
Acquisitions of Nuclear Fuel
 
(116
)
 
(154
)
 
(107
)
Acquisitions of Assets/Businesses
 
(65
)
 
(32
)
 
(94
)
Proceeds from Sales of Assets
 
6

 
21

 
18

Other
 
(97
)
 
(29
)
 
(183
)
Net Cash Flows Used for Investing Activities
 
$
(4,406
)
 
$
(3,818
)
 
$
(3,391
)
 
Net Cash Flows Used for Investing Activities were $4.4 billion in 2014 primarily due to Construction Expenditures for environmental, distribution and transmission investments. We also purchased transmission assets for $38 million.

Net Cash Flows Used for Investing Activities were $3.8 billion in 2013 primarily due to Construction Expenditures for environmental, distribution and transmission investments.

Net Cash Flows Used for Investing Activities were $3.4 billion in 2012 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments.  Acquisitions of Assets/Businesses include our March 2012 purchase of BlueStar for $70 million.
 
Financing Activities
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(in millions)
Issuance of Common Stock, Net
 
$
73

 
$
84

 
$
83

Issuance/Retirement of Debt, Net
 
876

 
385

 
544

Proceeds from Nuclear Fuel Sale/Leaseback
 

 
110

 

Dividends Paid on Common Stock
 
(998
)
 
(954
)
 
(916
)
Other
 
(113
)
 
(74
)
 
(66
)
Net Cash Flows Used for Financing Activities
 
$
(162
)
 
$
(449
)
 
$
(355
)


40



Net Cash Flows Used for Financing Activities in 2014 were $162 million.  Our net debt issuances were $876 million.  The net issuances included issuances of $1.6 billion of senior unsecured notes and other debt notes, $444 million of pollution control bonds and an increase in short-term borrowing of $589 million offset by retirements of $1.1 billion of notes, $412 million of pollution control bonds and $306 million of securitization bonds.  We paid common stock dividends of $998 million.  See Note 14 – Financing Activities.

Net Cash Flows Used for Financing Activities in 2013 were $449 million.  Our net debt issuances were $385 million.  The net issuances included issuances of $745 million of senior unsecured notes, $1 billion draws on a $1 billion term credit facility, $647 million of securitization bonds, $328 million of notes payable and other debt and $305 million of pollution control bonds offset by retirements of $1.8 billion of senior unsecured and other debt notes, $331 million of pollution control bonds, $243 million of securitization bonds and a decrease in short-term borrowing of $224 million.  We paid common stock dividends of $954 million.

Net Cash Flows Used for Financing Activities in 2012 were $355 million.  Our net debt issuances were $544 million. The net issuances included issuances of $1.7 billion of senior unsecured notes, $800 million of securitization bonds, $287 million of notes payable and other debt and $65 million of pollution control bonds offset by retirements of $902 million of senior unsecured and other debt notes, $315 million of junior subordinate debentures, $220 million of pollution control bonds, $206 million of securitization bonds and a decrease in short-term borrowing of $669 million.  We paid common stock dividends of $916 million.

The following financing activities occurred during 2014:

AEP Common Stock:

During 2014, we issued 1.6 million shares of common stock under our incentive compensation, employee saving and dividend reinvestment plans and received net proceeds of $73 million.

Debt:

During 2014, we issued approximately $2.1 billion of long-term debt, including $1.3 billion of senior notes at interest rates ranging from 2.61% to 5.52% and $200 million of pollution control revenue bonds at interest rates ranging from 1.625% to 1.75%, $244 million of pollution control revenue bonds at variable interest rates and $359 million of other debt at variable interest rates.  The proceeds from these issuances were used to fund long-term debt maturities and our construction programs.
During 2014, we entered no interest rate derivatives and settled $4.7 million of such transactions.  The settlements resulted in net cash received of $3 million.  As of December 31, 2014, we had in place $815 million of notional interest rate derivatives designated as cash flow and fair value hedges.

In 2015:

In January 2015, TCC retired $120 million of Securitization Bonds.
In January 2015, OPCo retired $22 million of Securitization Bonds.
In January 2015, SWEPCo remarketed $54 million of 1.6% Pollution Control Bonds due in 2019.
In January 2015, PSO issued $87.5 million of 3.17% and $87.5 million of 4.09% Senior Unsecured Notes due in 2025 and 2045, respectively.
In January and February 2015, I&M retired $23 million of Notes Payable related to DCC Fuel.
In February 2015, APCo retired $11 million of Securitization Bonds.



41



BUDGETED CONSTRUCTION EXPENDITURES

We forecast approximately $4.5 billion of construction expenditures including debt AFUDC for 2015.  For 2016 and 2017, we forecast construction expenditures of $3.8 billion and $3.9 billion, respectively.  The expenditures are generally for transmission, generation, distribution and required environmental investment to comply with Federal EPA rules.  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.  We expect to fund these construction expenditures through cash flows from operations and financing activities.  Generally, the subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged.  The 2015 estimated construction expenditures include generation, transmission and distribution related investments, as well as expenditures for compliance with environmental regulations as follows:
 
 
2015 Budgeted Construction Expenditures
Segment
 
Environmental
 
Generation
 
Transmission
 
Distribution
 
Other
 
Total
 
 
(in millions)
Vertically Integrated Utilities
 
$
594

 
$
496

 
$
472

 
$
654

 
$
110

 
$
2,326

Transmission and Distribution Utilities
 
2

 
2

 
359

 
545

 
64

 
972

AEP Transmission Holdco
 

 

 
988

 

 
7

 
995

Generation & Marketing
 
65

 
70

 

 

 
10

 
145

AEP River Operations
 

 
9

 

 

 

 
9

Corporate and Other
 

 

 

 

 
12

 
12

Total
 
$
661

 
$
577

 
$
1,819

 
$
1,199

 
$
203

 
$
4,459


OFF-BALANCE SHEET ARRANGEMENTS

Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that we enter in the normal course of business.  The following identifies significant off-balance sheet arrangements.

Rockport Plant, Unit 2

AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated unconsolidated trustee for Rockport Plant, Unit 2 (the Plant).  The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and certain institutional investors.  The future minimum lease payments for AEGCo and I&M are $592 million each as of December 31, 2014.

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022.  The Owner Trustee owns the Plant and leases it to AEGCo and I&M.  Our subsidiaries account for the lease as an operating lease with the future payment obligations included in Note 13.  The lease term is for 33 years with potential renewal options.  At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant.  We, as well as our subsidiaries, have no ownership interest in the Owner Trustee and do not guarantee its debt.

Railcars

In June 2003, we entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  We intend to maintain the lease for the full lease term of twenty years via the renewal options.  The lease is accounted for as an operating lease.  The future minimum lease obligation is $24 million for the remaining railcars as of December 31, 2014.  Under a return-and-sale option, the lessor is guaranteed that the sale proceeds will equal at least a specified lessee obligation amount which declines with each five-year renewal.  As of

42



December 31, 2014, the maximum potential loss was approximately $19 million assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, we believe that the fair value would produce a sufficient sales price to avoid any loss.   We have other railcar lease arrangements that do not utilize this type of financing structure.

CONTRACTUAL OBLIGATION INFORMATION

Our contractual cash obligations include amounts reported on the balance sheets and other obligations disclosed in our footnotes.  The following table summarizes our contractual cash obligations as of December 31, 2014:
Payments Due by Period
 
 
 
 
 
 
 
 
 
 
 
Contractual Cash Obligations
 
Less Than
1 Year
 
2-3 Years
 
4-5 Years
 
After
5 Years
 
Total
 
 
(in millions)
Short-term Debt (a)
 
$
1,346

 
$

 
$

 
$

 
$
1,346

Interest on Fixed Rate Portion of Long-term Debt (b)
 
819

 
1,530

 
1,285

 
7,079

 
10,713

Fixed Rate Portion of Long-term Debt (c)
 
1,180

 
2,629

 
3,057

 
9,938

 
16,804

Variable Rate Portion of Long-term Debt (d)
 
1,323

 
548

 
33

 

 
1,904

Capital Lease Obligations (e)
 
134

 
218

 
109

 
239

 
700

Noncancelable Operating Leases (e)
 
293

 
520

 
462

 
693

 
1,968

Fuel Purchase Contracts (f)
 
2,154

 
2,815

 
1,931

 
2,501

 
9,401

Energy and Capacity Purchase Contracts
 
363

 
405

 
426

 
2,087

 
3,281

Construction Contracts for Capital Assets (g)
 
1,332

 
1,604

 
814

 
1,571

 
5,321

Total
 
$
8,944

 
$
10,269

 
$
8,117

 
$
24,108

 
$
51,438


(a)
Represents principal only excluding interest.
(b)
Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2014 and do not reflect anticipated future refinancing, early redemptions or debt issuances.
(c)
See “Long-term Debt” section of Note 14.  Represents principal only, excluding interest.
(d)
See “Long-term Debt” section of Note 14.  Represents principal only, excluding interest.  Variable rate debt had interest rates that ranged between 0.04% and 1.89% as of December 31, 2014.
(e)
See Note 13.
(f)
Represents contractual obligations to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.
(g)
Represents only capital assets for which we have 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.

Our $124 million liability related to uncertainty in Income Taxes is not included above because we cannot reasonably estimate the cash flows by period.

Our pension funding requirements are not included in the above table.  As of December 31, 2014, we expect to make contributions to our pension plans totaling $93 million in 2015.  Estimated contributions of $93 million in 2016 and $97 million in 2017 may vary significantly based on market returns, changes in actuarial assumptions and other factors.  Based upon the projected benefit obligation and fair value of assets available to pay pension benefits, our pension plans were 95.1% funded as of December 31, 2014.


43



In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business.  These commitments include standby letters of credit, guarantees for the payment of obligation performance bonds and other commitments.  As of December 31, 2014, our commitments outstanding under these agreements are summarized in the table below:
Amount of Commitment Expiration Per Period
 
 
 
 
 
 
 
 
 
 
 
Other Commercial Commitments
 
Less Than
1 Year
 
2-3 Years
 
4-5 Years
 
After
5 Years
 
Total
 
 
(in millions)
Standby Letters of Credit (a)
 
$
63

 
$

 
$

 
$

 
$
63

Guarantees of the Performance of Outside Parties (b)
 

 

 

 
115

 
115

Guarantees of Our Performance (c)
 
991

 
12

 

 
59

 
1,062

Total Commercial Commitments
 
$
1,054

 
$
12

 
$

 
$
174

 
$
1,240


(a)
We enter into standby letters of credit (LOCs) with third parties.  These LOCs cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.  AEP, on behalf of our subsidiaries, and/or the subsidiaries issued all of these LOCs in the ordinary course of business.  There is no collateral held in relation to any guarantees in excess of our ownership percentages.  In the event any LOC is drawn, there is no recourse to third parties.  The maximum future payments of these LOCs are $63 million with maturities ranging from February 2015 to March 2016.  See “Letters of Credit” section of Note 6.
(b)
See “Guarantees of Third-Party Obligations” section of Note 6.
(c)
We issued performance guarantees and indemnifications for energy trading and various sale agreements.

SIGNIFICANT TAX LEGISLATION

The Small Business Jobs Act extended the time for claiming bonus depreciation and increased the deduction to 100% for 2011 and decreased the deduction to 50% for 2012.  The American Taxpayer Relief Act of 2012 provided for the extension of several business and energy industry tax deductions and credits, including the one-year extension of the 50% bonus depreciation to 2013.  The Tax Increase Prevention Act of 2014 also included a one-year extension of the 50% bonus depreciation and provided for the extension of research and development, employment and several energy tax credits for 2014. These enacted provisions had no material impact on net income or financial condition but did have a favorable impact on cash flows in 2013 and 2014 and are expected to have a favorable impact on cash flows in 2015.

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 our system are potentially disruptive to people, property and commerce and create risk for our business, investors and customers.  In February 2013, President Obama signed an executive order that addresses how government agencies will operate and support the functions in cyber security as well as redefines how the government interfaces with critical infrastructure, such as the electric grid.  We already operate under regulatory cyber security standards to protect critical infrastructure.  The cyber security framework that is being developed through this executive order will be reviewed by FERC and the U.S. Department of Energy (DOE).  In 2014, the DOE developed an Energy Sector Cyber Security Framework Implementation Guide for utilities to use in adopting and implementing the National Institute of Standards and Technology framework. We are actively engaged in the framework adoption 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 approve mandatory cyber security reliability standards. North American Electric Reliability Corporation (NERC), which FERC certified as the nation's Electric Reliability Organization,

44



developed critical infrastructure protection cyber security reliability standards. In 2013, as part of our industry’s continuing program to advance threat sharing and coordination, we participated in the NERC GridEx II exercise.  This effort, led by NERC, tested and developed the coordination and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.

We protect our critical cyber assets, such as our data centers, power plants, transmission operations centers and business network, using multiple layers of cyber security and authentication.  We constantly scan the system 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, we continually assess our own cyber security tools and processes to determine where we might need to strengthen our defenses. We continually review our business continuity plan to develop an effective recovery effort that decreases our 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 and Information Technology 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.

We continue to take steps to enhance our capabilities for identifying risks or threats and have shared that knowledge with our utility peers, industry and federal agencies.  We operate our own Cyber Security Operations Center.  Funding for this included a grant from the American Recovery and Reinvestment Act – U.S. Department of Energy Smart Grid Demonstration Program.  This facility was initially designed as a pilot cyber threat and information-sharing center specifically for the electric sector and is fully operational.

We have partnered 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.  We work with a consortium of other utilities across the country, learning how best to share information about potential threats and collaborating with each other.  We continue to work with a nonaffiliated entity to conduct several seminars each year about recognizing and investigating cyber vulnerabilities.  Through these types of efforts, we are working to protect ourselves while helping our 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 us to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies.  We consider 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.

We discuss 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.

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

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


45



Regulatory Accounting

Nature of Estimates Required

Our 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.

We recognize 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, we match the timing of expense and income recognition with regulated revenues.  We also record liabilities for refunds, or probable refunds, to customers that have not been made.

Assumptions and Approach Used

When incurred costs are probable of recovery through regulated rates, we record them as regulatory assets on the balance sheet.  We review the probability of recovery at each balance sheet date and whenever new events occur.  Similarly, we record regulatory liabilities 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, we write off that regulatory asset 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 our net income.  Refer to Note 5 for further detail related to regulatory assets and regulatory liabilities.

Revenue Recognition – Unbilled Revenues

Nature of Estimates Required

We record revenues when energy is delivered to the customer.  The determination of sales to individual customers is based on the reading of their meters, which we perform on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded.  This estimate is reversed in the following month and actual revenue is recorded based on meter readings.  In accordance with the applicable state commission regulatory treatment in Arkansas, Louisiana, Oklahoma and Texas, PSO and SWEPCo do not record the fuel portion of unbilled revenue.

The changes in unbilled electric utility revenues for our Vertically Integrated Utilities segment were $(29) million, $(9) million and $13 million for the years ended December 31, 2014, 2013 and 2012, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather and rate increases.  Accrued unbilled revenues for the Vertically Integrated Utilities segment were $254 million and $283 million as of December 31, 2014 and 2013, respectively.

The changes in unbilled electric utility revenues for our Transmission and Distribution Utilities segment were $16 million, $(22) million and $(12) million for the years ended December 31, 2014, 2013 and 2012, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather and rate increases.  Accrued unbilled revenues for the Transmission and Distribution Utilities segment were $181 million and $165 million as of December 31, 2014 and 2013, respectively.


46



In March 2012, our Generation & Marketing segment acquired an independent retail electric supplier.  The change in unbilled electric utility revenues for our Generation & Marketing segment was $9 million, $10 million and $34 million for the years ended December 31, 2014, 2013 and 2012, respectively.  Accrued unbilled revenues for the Generation & Marketing segment were $50 million and $41 million as of December 31, 2014 and 2013, respectively.

Assumptions and Approach Used

For each operating company, we compute the monthly estimate for unbilled revenues as net generation (generation plus purchases less sales) less the current month’s billed KWh plus the prior month’s unbilled KWh.  However, due to meter reading issues, meter drift and other anomalies, a separate monthly calculation limits the unbilled estimate within a range of values.  This limiter calculation is derived from an allocation of billed KWh to the current month and previous month, on a cycle-by-cycle basis, and by dividing the current month aggregated result by the billed KWh.  The limits are statistically set at one standard deviation from this percentage to determine the upper and lower limits of the range.  The unbilled estimate is compared to the limiter calculation and adjusted for variances exceeding the upper and lower limits.

For certain contracts, we calculate unbilled revenues by contract using the most recent historic daily activity adjusted for significant known changes in usage.

Effect if Different Assumptions Used

Significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate.  A 1% change in the limiter calculation when it is outside the range would increase or decrease unbilled revenues by 1% of the accrued unbilled revenues.

Accounting for Derivative Instruments

Nature of Estimates Required

We consider fair value techniques, valuation adjustments related to credit and liquidity and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates.  These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors.

Assumptions and Approach Used

We measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based primarily on exchange prices and broker quotes.  If a quoted market price is not available, we estimate the fair value based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and other assumptions.  Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment.  These uncertainties include projections of macroeconomic trends and future commodity prices, including supply and demand levels and future price volatility.

We reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality.  We calculate liquidity adjustments by utilizing bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time.  We calculate credit adjustments on our risk management contracts using estimated default probabilities and recovery rates relative to our counterparties or counterparties with similar credit profiles and contractual netting agreements.

With respect to hedge accounting, we assess hedge effectiveness and evaluate a forecasted transaction’s probability of occurrence within the specified time period as provided in the original hedge documentation.


47



Effect if Different Assumptions Used

There is inherent risk in valuation modeling given the complexity and volatility of energy markets.  Therefore, it is possible that results in future periods may be materially different as contracts settle.

The probability that hedged forecasted transactions will not occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified into operating income.

For additional information regarding derivatives, hedging and fair value measurements, see Notes 10 and 11.  See “Fair Value Measurements of Assets and Liabilities” section of Note 1 for fair value calculation policy.

Long-Lived Assets

Nature of Estimates Required

In accordance with the requirements of “Property, Plant and Equipment” accounting guidance, we evaluate 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.  We utilize 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, we record 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-based value, in some instances) associated with the asset.  For assets held for sale, an impairment is recognized if the expected net sales price is less than its book value.  For regulated assets, the earnings impact of an impairment charge could be offset by the establishment of a regulatory asset if rate recovery is probable.  For nonregulated assets, any impairment charge is recorded against earnings.

Assumptions and Approach Used

The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, we estimate fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals.  Cash flow estimates are based on relevant information available at the time the estimates are made.  Estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.  Also, when measuring fair value, management evaluates the characteristics of the asset or liability to determine if market participants would take those characteristics into account when pricing the asset or liability at the measurement date.  Such characteristics include, for example, the condition and location of the asset or restrictions of the use of the asset.  We perform 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.


48



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 an asset can vary if different estimates and assumptions would have been used in our 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, we made our best estimate of fair value 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 our analysis of the benefits of the transaction.

Pension and Other Postretirement Benefits

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

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1.  See Note 8 for information regarding costs and assumptions for employee retirement and postretirement benefits.

The following table shows the net periodic cost (credit) of the Plans:
 
 
Years Ended December 31,
Net Periodic Benefit Cost (Credit)
 
2014
 
2013
 
2012
 
 
(in millions)
Pension Plans
 
$
158

 
$
180

 
$
134

Postretirement Plans
 
(77
)
 
(17
)
 
89


The net periodic benefit cost is calculated based upon a number of actuarial assumptions, including expected long-term rates of return on the Plans’ assets.  In developing the expected long-term rate of return assumption for 2015, we evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions.  We also considered historical returns of the investment markets and changes in tax rates which affect a portion of the Postretirement Plans’ assets.  We anticipate that the investment managers we employ for the Plans will invest the assets to generate future returns averaging 6% for the Qualified Plan and 6.75% for the Postretirement Plans.


49



The expected long-term rate of return on the Plans’ assets is based on our targeted asset allocation and our expected investment returns for each investment category.  Our assumptions are summarized in the following table:
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
 
 
Assumed/
 



 
Assumed/
 
2015
 
Expected
 
2015
 
Expected
 
Target
 
Long-Term
 
Target
 
Long-Term
 
Asset
 
Rate of
 
Asset
 
Rate of
 
Allocation
 
Return
 
Allocation
 
Return
Equity
30
%
 
8.50
%
 
65
%
 
8.50
%
Fixed Income
55
%
 
4.10
%
 
33
%
 
4.10
%
Other Investments
15
%
 
7.30
%
 
%
 
%
Cash and Cash Equivalents
%
 
%
 
2
%
 
2.80
%
Total
100
%
 
 
 
100
%
 
 

We regularly review the actual asset allocation and periodically rebalance the investments to our targeted allocation.  We believe that 6% and 6.75% are reasonable estimates of the long-term rate of return on the Plans’ assets.  The Pension Plans’ assets had an actual gain of 10.6% and 8.1% for the years ended December 31, 2014 and 2013, respectively.  The Postretirement Plans’ assets had an actual gain of 7.2% and 14.3% for the years ended December 31, 2014 and 2013, respectively.  We will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary.

We base our determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets.  Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.  As of December 31, 2014, we had cumulative gains of approximately $270 million that remain to be recognized in the calculation of the market-related value of assets.  These unrecognized net actuarial gains may result in decreases in the future pension costs depending on several factors, including whether such gains at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance.

The method used to determine the discount rate that we utilize for determining future obligations is a duration-based method in which a hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.  The discount rate as of December 31, 2014 under this method was 4% for the Qualified Plan, 3.9% for the Nonqualified Plans and 4% for the Postretirement Plans.  Due to the effect of the unrecognized actuarial gains and based on an expected rate of return on the Pension Plans’ assets of 6%, discount rates of 4% and 3.9% and various other assumptions including adoption of updated mortality tables that the Society of Actuaries issued in October 2014, we estimate that the pension costs for the Pension Plans will approximate $129 million, $96 million and $66 million in 2015, 2016 and 2017, respectively.  Based on an expected rate of return on the Postretirement Plans’ assets of 6.75%, a discount rate of 4% and various other assumptions including adoption of updated mortality tables that the Society of Actuaries issued in October 2014, we estimate credits will approximate $94 million, $98 million and $103 million in 2015, 2016 and 2017, respectively.  Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans.  The actuarial assumptions used may differ materially from actual results.  The effects of a 50 basis point change to selective actuarial assumptions are included in the “Effect if Different Assumptions Used” section below.


50



The value of the Pension Plans’ assets increased to $5 billion as of December 31, 2014 from $4.7 billion as of December 31, 2013 primarily due to investment returns and company contributions in excess of benefit payments.  During 2014, the Qualified Plan paid $289 million and the Nonqualified Plans paid $7 million in benefits to plan participants.  The value of the Postretirement Plans’ assets remained unchanged at $1.7 billion as of December 31, 2014 and 2013 primarily due to investment returns and contributions by the company and the participants offsetting benefit payments.  The Postretirement Plans paid $134 million in benefits to plan participants during 2014.

Nature of Estimates Required

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

Assumptions and Approach Used

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

Discount rate
Compensation increase rate
Cash balance crediting rate
Health care cost trend rate
Expected return on plan assets

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

Effect if Different Assumptions Used

The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants.  These differences may result in a significant impact to the amount of pension and postretirement benefit expense recorded.  If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:
 
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
(in millions)
Effect on December 31, 2014 Benefit Obligations
 
 
 
 
 
 
 
 
Discount Rate
 
$
(282
)
 
$
311

 
$
(78
)
 
$
86

Compensation Increase Rate
 
20

 
(19
)
 
NA

 
NA

Cash Balance Crediting Rate
 
70

 
(63
)
 
NA

 
NA

Health Care Cost Trend Rate
 
NA

 
NA

 
34

 
(30
)
 
 
 
 
 
 
 
 
 
Effect on 2014 Periodic Cost
 
 
 
 
 
 
 
 
Discount Rate
 
(17
)
 
19

 
(5
)
 
5

Compensation Increase Rate
 
5

 
(4
)
 
NA

 
NA

Cash Balance Crediting Rate
 
14

 
(13
)
 
NA

 
NA

Health Care Cost Trend Rate
 
NA

 
NA

 
5

 
(4
)
Expected Return on Plan Assets
 
(22
)
 
22

 
(8
)
 
8

 
 
 
 
 
 
 
 
 
NA   Not applicable.
 
 
 
 
 
 
 
 


51



ACCOUNTING PRONOUNCEMENTS

Pronouncements Adopted in 2015

The FASB issued ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. We adopted ASU 2014-08 effective January 1, 2015. We expect no impact on the financial statements in the first quarter of 2015.

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, 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 new accounting guidance is effective for interim and annual periods beginning after December 15, 2016. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. We plan to adopt ASU 2014-09 effective January 1, 2017.

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 income statement. 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. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. We plan to adopt ASU 2015-01 effective January 1, 2016.

Future Accounting Changes

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

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

Our Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through its transactions in power, coal, natural gas and marketing contracts.  These risks include commodity price risk, interest rate risk and credit risk.  In addition, we are exposed to foreign currency exchange risk as we occasionally procure various services and materials used in our energy business from foreign suppliers.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

Our Transmission and Distribution Utilities segment is exposed to FTR price risk as it relates to RTO congestion during the June 2012 – May 2015 Ohio ESP period.  Additional risks include energy procurement risk and interest rate risk.
Our Generation & Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM and MISO.  This segment is exposed to certain market risks as a marketer of wholesale and retail electricity.  These risks

52



include commodity price risk, interest rate risk and credit risk.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.  In addition, our Generation & Marketing segment is also exposed to certain market risks as a major power producer and through its transactions in wholesale electricity, natural gas and coal trading and marketing contracts.

We employ risk management contracts including physical forward purchase-and-sale contracts and financial forward purchase-and-sale contracts.  We engage in risk management of power, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with our energy business.  As a result, we are subject to price risk.  The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.  Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.  The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President.  When commercial activities exceed predetermined limits, we modify the positions to reduce the risk to be within the limits unless specifically approved by the respective committee.

The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2013:
MTM Risk Management Contract Net Assets (Liabilities)
Year Ended December 31, 2014
 
 
 
 
 
 
 
 
 
Vertically
Integrated
Utilities
 
Transmission
and
Distribution
Utilities
 
Generation
&
Marketing
 
Total
 
(in millions)
Total MTM Risk Management Contract Net Assets as of December 31, 2013
$
32

 
$
3

 
$
157

 
$
192

Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period
(17
)
 
(3
)
 
(39
)
 
(59
)
Fair Value of New Contracts at Inception When Entered During the Period (a)

 

 
12

 
12

Changes in Fair Value Due to Market Fluctuations During the Period (b)

 

 
10

 
10

Changes in Fair Value Allocated to Regulated Jurisdictions (c)
21

 
46

 

 
67

Total MTM Risk Management Contract Net Assets as of December 31, 2014
$
36

 
$
46

 
$
140

 
222

Commodity Cash Flow Hedge Contracts
 
 
 
 
 
 
2

Interest Rate and Foreign Currency Cash Flow Hedge Contracts
 
 
 
 
 
 
(1
)
Fair Value Hedge Contracts
 
 
 
 
 
 
(6
)
Collateral Deposits
 
 
 
 
 
 
32

Total MTM Derivative Contract Net Assets as of December 31, 2014
 
 
 
 
 
 
$
249


(a)
Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  The contract prices are valued against market curves associated with the delivery location and delivery term.  A significant portion of the total volumetric position has been economically hedged.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)
Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets.

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See Note 10 – Derivatives and Hedging and Note 11 – Fair Value Measurements for additional information related to our risk management contracts.  The following tables and discussion provide information on our credit risk and market volatility risk.

Credit Risk

We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  We use Moody’s Investors Service, Standard & Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

We have risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily.  As of December 31, 2014, our credit exposure net of collateral to sub investment grade counterparties was approximately 8.4%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).  As of December 31, 2014, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:
Counterparty Credit Quality
 
Exposure
Before
Credit
Collateral
 
Credit
Collateral
 
Net
Exposure
 
Number of
Counterparties
>10% of
Net Exposure
 
Net Exposure
of
Counterparties
>10%
 
 
(in millions, except number of counterparties)
Investment Grade
 
$
628

 
$
3

 
$
625

 
2

 
$
249

Split Rating
 
21

 

 
21

 
1

 
21

Noninvestment Grade
 
2

 
2

 

 

 

No External Ratings:
 
 
 
 
 


 
 
 
 
Internal Investment Grade
 
83

 

 
83

 
3

 
41

Internal Noninvestment Grade
 
83

 
16

 
67

 
2

 
36

Total as of December 31, 2014
 
$
817

 
$
21

 
$
796

 
8

 
$
347

 
 
 
 
 
 
 
 
 
 
 
Total as of December 31, 2013
 
$
787

 
$
18

 
$
769

 
9

 
$
381


In addition, we are exposed to credit risk related to our participation in RTOs.  For each of the RTOs in which we participate, this risk is generally determined based on our proportionate share of member gross activity over a specified period of time.

Value at Risk (VaR) Associated with Risk Management Contracts

We use a risk measurement model, which calculates VaR, to measure our commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, as of December 31, 2014, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.


54



The following tables show the end, high, average and low market risk as measured by VaR for the periods indicated:

VaR Model
Trading Portfolio
Twelve Months Ended
 
Twelve Months Ended
December 31, 2014
 
December 31, 2013
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
(in millions)
 
(in millions)
$

 
$
3

 
$
1

 
$

 
$

 
$
1

 
$

 
$


VaR Model
Non-Trading Portfolio
Twelve Months Ended
December 31, 2014
End
 
High
 
Average
 
Low
(in millions)
$
2

 
$
3

 
$
1

 
$


We back-test our VaR results against performance due to actual price movements.  Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

As our VaR calculation captures recent price movements, we also perform regular stress testing of the trading portfolio to understand our exposure to extreme price movements.  We employ a historical-based method whereby the current trading portfolio is subjected to actual, observed price movements from the last several years in order to ascertain which historical price movements translated into the largest potential MTM loss.  We then research the underlying positions, price movements and market events that created the most significant exposure and report the findings to the Risk Executive Committee, Regulated Risk Committee, or Competitive Risk Committee as appropriate.

Interest Rate Risk

We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which our interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on debt outstanding as of December 31, 2014 and 2013, the estimated EaR on our debt portfolio for the following twelve months was $33 million and $32 million, respectively.

55



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
American Electric Power Company, Inc.:

We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and subsidiary companies (the "Company") as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and subsidiary companies as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 20, 2015 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ Deloitte & Touche LLP

Columbus, Ohio
February 20, 2015


56



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
American Electric Power Company, Inc.:

We have audited the internal control over financial reporting of American Electric Power Company, Inc. and subsidiary companies (the "Company") as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014 of the Company and our report dated February 20, 2015 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Columbus, Ohio
February 20, 2015


57



MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of American Electric Power Company, Inc. and subsidiary companies (AEP) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  AEP’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of AEP’s internal control over financial reporting as of December 31, 2014.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 2013) in Internal Control – Integrated Framework.  Based on management’s assessment, AEP’s internal control over financial reporting was effective as of December 31, 2014.

AEP’s independent registered public accounting firm has issued an attestation report on AEP’s internal control over financial reporting.  The Report of Independent Registered Public Accounting Firm appears on the previous page.

58




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2014, 2013 and 2012
 (in millions, except per-share and share amounts)
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
REVENUES
 
 
 
 
 
 
Vertically Integrated Utilities
 
$
9,397

 
$
9,347

 
$
8,785

Transmission and Distribution Utilities
 
4,553

 
4,279

 
4,659

Generation & Marketing
 
2,384

 
1,208

 
882

Other Revenues
 
686

 
523

 
619

TOTAL REVENUES
 
17,020

 
15,357

 
14,945

EXPENSES
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
4,272

 
4,068

 
4,111

Purchased Electricity for Resale
 
2,086

 
1,491

 
1,169

Other Operation
 
3,225

 
2,904

 
2,962

Maintenance
 
1,361

 
1,179

 
1,115

Asset Impairments and Other Related Charges
 

 
226

 
300

Depreciation and Amortization
 
1,929

 
1,743

 
1,782

Taxes Other Than Income Taxes
 
915

 
891

 
850

TOTAL EXPENSES
 
13,788

 
12,502

 
12,289

 
 
 
 
 
 
 
OPERATING INCOME
 
3,232

 
2,855

 
2,656

 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
Interest and Investment Income
 
7

 
58

 
8

Carrying Costs Income
 
33

 
30

 
53

Allowance for Equity Funds Used During Construction
 
103

 
73

 
93

Interest Expense
 
(885
)
 
(906
)
 
(988
)
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
 
2,490

 
2,110

 
1,822

 
 
 
 
 
 
 
Income Tax Expense
 
942

 
684

 
604

Equity Earnings of Unconsolidated Subsidiaries
 
90

 
58

 
44

 
 
 
 
 
 
 
NET INCOME
 
1,638

 
1,484

 
1,262

 
 
 
 
 
 
 
Net Income Attributable to Noncontrolling Interests
 
4

 
4

 
3

 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
1,634

 
$
1,480

 
$
1,259

 
 
 
 
 
 
 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
 
488,592,997

 
486,619,555

 
484,682,469

 
 
 
 
 
 
 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
3.34

 
$
3.04

 
$
2.60

 
 
 
 
 
 
 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
 
488,899,840

 
487,040,956

 
485,084,694

 
 
 
 
 
 
 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
3.34

 
$
3.04

 
$
2.60

See Notes to Consolidated Financial Statements beginning on page 65.

59



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2014, 2013 and 2012
(in millions)
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
Net Income
 
$
1,638

 
$
1,484

 
$
1,262

 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $3, $8 and $8 in 2014, 2013 and 2012, Respectively
 
5

 
15

 
(15
)
Securities Available for Sale, Net of Tax of $0, $1 and $1 in 2014, 2013 and 2012, Respectively
 
1

 
3

 
2

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $3, $12 and $16 in 2014, 2013 and 2012, Respectively
 
5

 
22

 
31

Pension and OPEB Funded Status, Net of Tax of $1, $95 and $62 in 2014, 2013 and 2012, Respectively
 
1

 
177

 
115

 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE INCOME
 
12

 
217

 
133

 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
1,650

 
1,701

 
1,395

 
 
 
 
 
 
 
Total Comprehensive Income Attributable to Noncontrolling Interests
 
4

 
4

 
3

 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
COMMON SHAREHOLDERS
 
$
1,646

 
$
1,697

 
$
1,392

See Notes to Consolidated Financial Statements beginning on page 65.

60



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2014, 2013 and 2012
(in millions)
 
AEP Common Shareholders
 
 
 
 
 
Common Stock
 
 
 
 
 
 
 
 
 
 
 
Shares
 
Amount
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interests
 
Total
TOTAL EQUITY – DECEMBER 31, 2011
504

 
$
3,274

 
$
5,970

 
$
5,890

 
$
(470
)
 
$
1

 
$
14,665

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Common Stock
2

 
15

 
68

 
 
 
 
 
 
 
83

Common Stock Dividends ($1.88/share)
 
 
 
 
 
 
(913
)
 
 
 
(3
)
 
(916
)
Other Changes in Equity
 
 
 
 
11

 
 
 
 
 
(1
)
 
10

Net Income
 
 
 
 
 
 
1,259

 
 
 
3

 
1,262

Other Comprehensive Income
 
 
 
 
 
 
 
 
133

 
 
 
133

TOTAL EQUITY – DECEMBER 31, 2012
506

 
3,289

 
6,049

 
6,236

 
(337
)
 

 
15,237

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Common Stock
2

 
14

 
70

 
 
 
 
 
 
 
84

Common Stock Dividends ($1.95/share)
 
 
 
 
 
 
(950
)
 
 
 
(4
)
 
(954
)
Other Changes in Equity
 
 
 
 
12

 
 
 
 
 
1

 
13

Net Income
 
 
 
 
 
 
1,480

 
 
 
4

 
1,484

Other Comprehensive Income
 
 
 
 
 
 
 
 
217

 
 
 
217

Pension and OPEB Adjustment Related to Mitchell Plant
 
 
 
 
 
 
 
 
5

 
 
 
5

TOTAL EQUITY – DECEMBER 31, 2013
508

 
3,303

 
6,131

 
6,766

 
(115
)
 
1

 
16,086

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Common Stock
2

 
10

 
63

 
 
 
 
 
 
 
73

Common Stock Dividends ($2.03/share)
 
 
 
 
 
 
(994
)
 
 
 
(4
)
 
(998
)
Other Changes in Equity
 
 
 
 
10

 
 
 
 
 
3

 
13

Net Income
 
 
 
 
 
 
1,634

 
 
 
4

 
1,638

Other Comprehensive Income
 
 
 
 
 
 
 
 
12

 
 
 
12

TOTAL EQUITY – DECEMBER 31, 2014
510

 
$
3,313

 
$
6,204

 
$
7,406

 
$
(103
)
 
$
4

 
$
16,824

See Notes to Consolidated Financial Statements beginning on page 65.

61



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2014 and 2013
(in millions)
 
 
December 31,
 
 
2014
 
2013
CURRENT ASSETS
 
 
 
 
Cash and Cash Equivalents
 
$
163

 
$
118

Other Temporary Investments
    (December 31, 2014 and 2013 Amounts Include $371 and $335, Respectively, Related to Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and EIS)
 
386

 
353

Accounts Receivable:
 
 
 
 
Customers
 
727

 
746

Accrued Unbilled Revenues
 
146

 
157

Pledged Accounts Receivable – AEP Credit
 
987

 
945

Miscellaneous
 
87

 
72

Allowance for Uncollectible Accounts
 
(21
)
 
(60
)
Total Accounts Receivable
 
1,926

 
1,860

Fuel
 
587

 
701

Materials and Supplies
 
738

 
722

Risk Management Assets
 
178

 
160

Regulatory Asset for Under-Recovered Fuel Costs
 
127

 
80

Margin Deposits
 
95

 
70

Prepayments and Other Current Assets
 
278

 
246

TOTAL CURRENT ASSETS
 
4,478

 
4,310

 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
Electric:
 
 
 
 
Generation
 
25,727

 
25,074

Transmission
 
12,433

 
10,893

Distribution
 
17,157

 
16,377

Other Property, Plant and Equipment (Including Plant to be Retired, Coal Mining and Nuclear Fuel)
 
5,770

 
5,470

Construction Work in Progress
 
3,218

 
2,471

Total Property, Plant and Equipment
 
64,305

 
60,285

Accumulated Depreciation and Amortization
 
20,188

 
19,288

TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 
44,117

 
40,997

 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
Regulatory Assets
 
4,264

 
4,376

Securitized Assets
 
2,072

 
2,373

Spent Nuclear Fuel and Decommissioning Trusts
 
2,096

 
1,932

Goodwill
 
91

 
91

Long-term Risk Management Assets
 
294

 
297

Deferred Charges and Other Noncurrent Assets
 
2,221

 
2,038

TOTAL OTHER NONCURRENT ASSETS
 
11,038

 
11,107

 
 
 
 
 
TOTAL ASSETS
 
$
59,633

 
$
56,414

See Notes to Consolidated Financial Statements beginning on page 65.

62



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2014 and 2013
(dollars in millions)
 
 
 
 
 
 
 
December 31,
 
 
 
 
 
 
 
2014
 
2013
CURRENT LIABILITIES
 
 
 
 
Accounts Payable
 
 
 
 
 
 
$
1,287

 
$
1,266

Short-term Debt:
 
 
 
 
 
 
 
 
 
Securitized Debt for Receivables – AEP Credit
 
 
 
 
 
 
744

 
700

Other Short-term Debt
 
 
 
 
 
 
602

 
57

Total Short-term Debt
 
 
 
 
 
 
1,346

 
757

Long-term Debt Due Within One Year
(December 31, 2014 and 2013 Amounts Include $431 and $416, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine)
 
 
2,503

 
1,549

Risk Management Liabilities
 
 
 
 
 
 
92

 
90

Customer Deposits
 
 
 
 
 
 
324

 
299

Accrued Taxes
 
 
 
 
 
 
871

 
822

Accrued Interest
 
 
 
 
 
 
239

 
245

Regulatory Liability for Over-Recovered Fuel Costs
 
 
 
 
 
 
55

 
119

Other Current Liabilities
 
 
 
 
 
 
1,250

 
965

TOTAL CURRENT LIABILITIES
 
 
 
 
 
 
7,967

 
6,112

 
 
 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
Long-term Debt
(December 31, 2014 and 2013 Amounts Include $2,260 and $2,532, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy and Sabine)
 
 
16,181

 
16,828

Long-term Risk Management Liabilities
 
 
 
 
 
 
131

 
177

Deferred Income Taxes
 
 
 
 
 
 
10,986

 
10,300

Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 
 
3,892

 
3,694

Asset Retirement Obligations
 
 
 
 
 
 
1,951

 
1,835

Employee Benefits and Pension Obligations
 
 
 
 
 
 
630

 
415

Deferred Credits and Other Noncurrent Liabilities
 
 
 
 
 
 
1,071

 
967

TOTAL NONCURRENT LIABILITIES
 
 
 
 
 
 
34,842

 
34,216

 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 
 
 
 
42,809

 
40,328

 
 
 
 
 
 
 
 
 
 
Rate Matters (Note 4)
 
 
 
 
 
 

 

Commitments and Contingencies (Note 6)
 
 
 
 
 
 

 

 
 
 
 
 
 
 
 
 
 
EQUITY
 
 
 
 
Common Stock – Par Value – $6.50 Per Share:
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
 
 
 
 
Shares Authorized
 
600,000,000
 
600,000,000
 
 
 
 
 
Shares Issued
 
509,739,159
 
508,113,964
 
 
 
 
 
(20,336,592 Shares were Held in Treasury as of December 31, 2014 and 2013)
 
 
3,313

 
3,303

Paid-in Capital
 
 
 
 
 
 
6,204

 
6,131

Retained Earnings
 
 
 
 
 
 
7,406

 
6,766

Accumulated Other Comprehensive Income (Loss)
 
 
 
 
 
 
(103
)
 
(115
)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY
 
 
16,820

 
16,085

 
 
 
 
 
 
 
 
 
 
Noncontrolling Interests
 
 
 
 
 
 
4

 
1

 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY
 
 
 
 
 
 
16,824

 
16,086

 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 
 
 
 
 
 
$
59,633

 
$
56,414

See Notes to Consolidated Financial Statements beginning on page 65.


63



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2014, 2013 and 2012
(in millions)
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
OPERATING ACTIVITIES
 
 
 
 
 
 
Net Income
 
$
1,638

 
$
1,484

 
$
1,262

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
 
 
 
Depreciation and Amortization
 
1,929

 
1,743

 
1,782

Deferred Income Taxes
 
878

 
709

 
636

Asset Impairments and Other Related Charges
 

 
226

 
300

Carrying Costs Income
 
(33
)
 
(30
)
 
(53
)
Allowance for Equity Funds Used During Construction
 
(103
)
 
(73
)
 
(93
)
Mark-to-Market of Risk Management Contracts
 
(53
)
 
38

 
57

Amortization of Nuclear Fuel
 
144

 
131

 
136

Pension and Postemployment Benefit Reserves
 
80

 
172

 
120

Pension Contributions to Qualified Plan Trust
 
(71
)
 

 
(200
)
Property Taxes
 
(42
)
 
(35
)
 
(19
)
Fuel Over/Under-Recovery, Net
 
(36
)
 
62

 
157

Deferral of Ohio Capacity Costs, Net
 
(114
)
 
(214
)
 
(65
)
Change in Other Noncurrent Assets
 
26

 
(184
)
 
(171
)
Change in Other Noncurrent Liabilities
 
242

 
(169
)
 
7

Changes in Certain Components of Working Capital:
 
 
 
 
 
 
Accounts Receivable, Net
 
(72
)
 
5

 
(16
)
Fuel, Materials and Supplies
 
102

 
122

 
(224
)
Accounts Payable
 
(80
)
 
95

 
(60
)
Accrued Taxes, Net
 
4

 
85

 
174

Other Current Assets
 
(36
)
 
5

 
(3
)
Other Current Liabilities
 
210

 
(66
)
 
77

Net Cash Flows from Operating Activities
 
4,613

 
4,106

 
3,804

 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
Construction Expenditures
 
(4,134
)
 
(3,624
)
 
(3,025
)
Change in Other Temporary Investments, Net
 
(31
)
 
(11
)
 
(27
)
Purchases of Investment Securities
 
(1,088
)
 
(927
)
 
(1,047
)
Sales of Investment Securities
 
1,032

 
858

 
988

Acquisitions of Nuclear Fuel
 
(116
)
 
(154
)
 
(107
)
Acquisitions of Assets/Businesses
 
(65
)
 
(32
)
 
(94
)
Insurance Proceeds Related to Cook Plant Fire
 

 
72

 

Proceeds from Sales of Assets
 
6

 
21

 
18

Other Investing Activities
 
(10
)
 
(21
)
 
(97
)
Net Cash Flows Used for Investing Activities
 
(4,406
)
 
(3,818
)
 
(3,391
)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Issuance of Common Stock, Net
 
73

 
84

 
83

Issuance of Long-term Debt
 
2,067

 
3,207

 
2,856

Commercial Paper and Credit Facility Borrowings
 

 
17

 
25

Change in Short-term Debt, Net
 
589

 
(221
)
 
(654
)
Retirement of Long-term Debt
 
(1,780
)
 
(2,598
)
 
(1,643
)
Commercial Paper and Credit Facility Repayments
 

 
(20
)
 
(40
)
Proceeds from Nuclear Fuel Sale/Leaseback
 

 
110

 

Principal Payments for Capital Lease Obligations
 
(120
)
 
(82
)
 
(71
)
Dividends Paid on Common Stock
 
(998
)
 
(954
)
 
(916
)
Other Financing Activities
 
7

 
8

 
5

Net Cash Flows Used for Financing Activities
 
(162
)
 
(449
)
 
(355
)
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
45

 
(161
)
 
58

Cash and Cash Equivalents at Beginning of Period
 
118

 
279

 
221

Cash and Cash Equivalents at End of Period
 
$
163

 
$
118

 
$
279

See Notes to Consolidated Financial Statements beginning on page 65.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
Page
Number
 
 
Organization and Summary of Significant Accounting Policies
New Accounting Pronouncements
Comprehensive Income
Rate Matters
Effects of Regulation
Commitments, Guarantees and Contingencies
Acquisition and Impairments
Benefit Plans
Business Segments
Derivatives and Hedging
Fair Value Measurements
Income Taxes
Leases
Financing Activities
Stock-based Compensation
Variable Interest Entities
Property, Plant and Equipment
Cost Reduction Programs
Unaudited Quarterly Financial Information
Goodwill and Other Intangible Assets

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

Our principal business is the generation, transmission and distribution of electric power.  The subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines.  Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions except Energy Supply subsidiaries.

We provide competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provide energy management solutions throughout the United States, including energy efficiency services through our independent retail electric supplier.

We also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services.  In addition, our operations include nonregulated wind farms and barging operations.

Corporate Separation

Background

On December 31, 2013, as approved by the FERC and the PUCO, OPCo transferred its generation assets and related generation liabilities at net book value to AGR.  In accordance with Ohio law, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers.  Effective January 1, 2014, OPCo began purchasing power from both affiliated and nonaffiliated entities, subject to PUCO approval, to meet the energy and capacity needs of customers. On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value its ownership (867 MW) in Amos Plant, Unit 3 to APCo and one-half of its interest (780 MW) in the Mitchell Plant to KPCo.  

Other Impacts of Corporate Separation

The Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.

Effective January 1, 2014, the FERC approved:

A PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  Under the PCA, APCo, I&M and KPCo are individually responsible for planning their respective capacity obligations and there are no capacity equalization charges/credits under the PCA on deficit/surplus companies.   Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.
A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent.  The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies will fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year.  Under the Bridge Agreement, AGR is committed to use its capacity to help meet the PJM capacity obligations of member companies through May 31, 2015.

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A Power Supply Agreement (PSA) between AGR and OPCo for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

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

The FERC regulates wholesale power markets and wholesale power transactions.  Our wholesale power transactions are generally market-based.  Wholesale power transactions are cost-based regulated when we negotiate and file a cost-based contract with the FERC or the FERC determines that we have “market power” in the region where the transaction occurs.  We have entered into wholesale power supply contracts with various municipalities and cooperatives that are FERC-regulated, cost-based contracts.  These contracts are generally formula rate mechanisms, which are trued up to actual costs annually.  

The state regulatory commissions regulate all of the distribution operations and rates of our retail public utilities on a cost basis.  The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas.  The ESP rates in Ohio continue the process of transitioning generation/power supply rates over time to market rates.  In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing and is conducted by Texas Retail Electric Providers (REPs).  Through our nonregulated subsidiaries, we enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market.  In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT.  We have no active REPs in ERCOT.

The FERC also regulates our wholesale transmission operations and rates.  The FERC claims jurisdiction over retail transmission rates when retail rates are unbundled in connection with restructuring.  OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled.  OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based.  Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT.  Bundled retail transmission rates are regulated, on a cost basis, by the state commissions.  Transmission rates for our seven wholly-owned transmission subsidiaries within our AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based.

In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which are still active and allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement.  In accordance with our October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.  In December 2013, the FERC issued orders approving the creation of a PCA, effective January 1, 2014.  Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. Effective June 1, 2014, the FERC approved the cancellation of the System Transmission Integration Agreement.

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Principles of Consolidation

Our consolidated financial statements include our wholly-owned and majority-owned subsidiaries and VIEs of which we are the primary beneficiary.  Intercompany items are eliminated in consolidation.  We use the equity method of accounting for equity investments where we exercise significant influence but do not hold a controlling financial interest.  Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. Our proportionate share of the investee's equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. We have ownership interests in generating units that are jointly-owned.  Our proportionate share of the operating costs associated with such facilities is included on the statements of income and our proportionate share of the assets and liabilities are reflected on the balance sheets.

Accounting for the Effects of Cost-Based Regulation

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

Use of Estimates

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

Cash and Cash Equivalents

Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.

Other Temporary Investments

Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that we intend to hold for less than one year and investments by our protected cell of EIS.

We classify our investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance.  We do not have any investments classified as trading.

Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI.  Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost.  The cost of securities sold is based on the specific identification or weighted average cost method.


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In evaluating potential impairment of securities with unrealized losses, we considered, among other criteria, the current fair value compared to cost, the length of time the security's fair value has been below cost, our intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions.  See “Fair Value Measurements of Other Temporary Investments” in Note 11.

Inventory

Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market.  Materials and supplies inventories are carried at average cost.

Accounts Receivable

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

We recognize revenue from electric power sales when we deliver power to our customers.  To the extent that deliveries have occurred but a bill has not been issued, we accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, for I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo.  Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit.  AEP Credit has a receivables securitization agreement with bank conduits.  Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries.

Allowance for Uncollectible Accounts

Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries.  For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable.  For customer accounts receivables related to our risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis.  For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful.  For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified.  Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.

Emission Allowances

In regulated jurisdictions, we record emission allowances at cost, including the annual SO2 and NOx emission allowance entitlements received at no cost from the Federal EPA.  For our nonregulated business, we record allowances at the lower of cost or market.  We follow the inventory model for these allowances.  We record allowances expected to be consumed within one year in Materials and Supplies and allowances with expected consumption beyond one year in Deferred Charges and Other Noncurrent Assets on the balance sheets.  We record the consumption of allowances in the production of energy in Fuel and Other Consumables Used for Electric Generation on the statements of income at an average cost.  We report the purchases and sales of allowances in the Operating Activities section of the statements of cash flows.  We record the net margin on sales of emission allowances in Vertically Integrated Utilities Revenue on the statements of income because of its integral nature to the production process of energy and our revenue optimization strategy for our utility operations.  The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.

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Property, Plant and Equipment

Regulated

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

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.”  When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense.

The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Nonregulated

Our nonregulated operations generally follow the policies of our rate-regulated operations listed above but with the following exceptions.  Property, plant and equipment of nonregulated operations are stated at fair value at acquisition (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals.  Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation.  For nonregulated plant assets, a gain or loss would be recorded if the retirement is not considered an interim routine replacement.  Removal costs are charged to expense.

Allowance for Funds Used During Construction and Interest Capitalization

For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant.  We record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense.  For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments.  The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value.


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Fair Value Measurements of Assets and Liabilities

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.  Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.  The Competitive Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply's President and Vice President.

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

We utilize our trustee’s external pricing service in our estimate of the fair value of the underlying investments held in the benefit plan and nuclear trusts.  Our investment managers review and validate the prices utilized by the trustee to determine fair value.  We perform our own valuation testing to verify the fair values of the securities.  We receive audit reports of our trustee’s operating controls and valuation processes.  The trustee uses multiple pricing vendors for the assets held in the trusts.

Assets in the benefits and nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds.  Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by

71



securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.  Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate or private equity investment.

Deferred Fuel Costs

The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized.  The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method.  In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets.  Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended.  These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval.  The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions.  On a routine basis, state regulatory commissions review and/or audit our fuel procurement policies and practices, the fuel cost calculations and FAC deferrals.  When a FAC under-recovery is no longer probable of recovery, we adjust our FAC deferrals and record provisions for estimated refunds to recognize these probable outcomes.

Changes in fuel costs, including purchased power in Kentucky for KPCo, in Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO and in Virginia and West Virginia (upon securitization in November 2013) for APCo are reflected in rates in a timely manner generally through the FAC.  Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo and in West Virginia (prior to securitization in November 2013) for APCo are reflected in rates through FAC phase-in plans.  The FAC generally includes some sharing of off-system sales margins.  In West Virginia for APCo, all of the margins from off-system sales are given to customers through the FAC.  Prior to corporate separation, none of the margins from off-system sales were given to customers through the FAC in Ohio for OPCo.  A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Virginia for APCo and in Indiana and Michigan for I&M.  Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.

Revenue Recognition

Regulatory Accounting

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


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

Electricity Supply and Delivery Activities

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services.  For regulated and nonregulated operations, we recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.  In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue.

Most of the power produced at our generation plants is sold to PJM or SPP.  We also purchase power from PJM and SPP to supply our customers.  Generally, these power sales and purchases for the regulated subsidiaries are reported on a net basis as revenues on the statements of income.  However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of our nonregulated subsidiaries are reported as gross purchases or sales.

Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income.  Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances.  Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income.  All other non-trading derivative purchases are recorded net in revenues.

In general, we record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated.  In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Energy Marketing and Risk Management Activities

We engage in wholesale power, coal and natural gas marketing and risk management activities focused on wholesale markets where we own assets and adjacent markets.  Our activities include the purchase and sale of energy under forward contracts at fixed and variable prices.  These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options.  We engage in certain energy marketing and risk management transactions with RTOs.

We recognize revenues and expenses from wholesale marketing and risk management transactions that are not derivatives upon delivery of the commodity.  We use MTM accounting for wholesale marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or a normal purchase or sale.  We include unrealized and realized gains and losses on wholesale marketing and risk management transactions that are accounted for using MTM in revenues or expense on the transaction's facts and circumstances.   In jurisdictions subject to cost-based regulation, we defer unrealized MTM amounts and some realized gains and losses as regulatory assets (for losses) and regulatory liabilities (for gains).  We include unrealized MTM gains and losses resulting from derivative contracts on the balance sheets as Risk Management Assets or Liabilities as appropriate.

Certain qualifying wholesale marketing and risk management derivative transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge).  We initially record the effective portion of the cash flow hedge’s gain or loss as a component of AOCI.  When the forecasted transaction is realized and affects net income, we subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses

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within the same financial statement line item as the forecasted transaction on the statements of income.  Excluding those jurisdictions subject to cost-based regulation, we recognize the ineffective portion of the gain or loss in revenues or expense immediately on the statements of income, depending on the specific nature of the associated hedged risk.  In regulated jurisdictions, we defer the ineffective portion as regulatory assets (for losses) and regulatory liabilities (for gains).  See “Accounting for Cash Flow Hedging Strategies” section of Note 10.

Barging Activities

AEP River Operations’ revenue is recognized based on percentage of voyage completion.  The proportion of freight transportation revenue to be recognized is determined by applying a percentage to the contractual charges for such services.  The percentage is determined by dividing the number of miles from the loading point to the position of the barge as of the end of the accounting period by the total miles to the destination specified in the customer’s freight contract.  The position of the barge at accounting period end is determined by our computerized barge tracking system.

SPP Integrated Power Market
In March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In the past, PSO and SWEPCo would satisfy their load requirements with their own generation resources or through the Operating Agreement. In the new integrated power market, PSO and SWEPCo operate as standalone entities by offering their respective generation into the SPP power market, which then economically dispatches the resources. This change further enables retail customers to obtain power through either internal generation or power purchases from the SPP market. The new integrated power market now operates in a similar manner as the PJM power market for the AEP East Companies. The change in the SPP integrated power market did not have a significant effect on the 2014 results of operations or cash flows.

Levelization of Nuclear Refueling Outage Costs

In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over the period beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins.  I&M adjusts the amortization amount as necessary to ensure full amortization of all deferred costs by the end of the refueling cycle.

Maintenance

We expense maintenance costs as incurred.  If it becomes probable that we will recover specifically-incurred costs through future rates, we establish a regulatory asset to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues.  In certain regulatory jurisdictions, we defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.

Income Taxes and Investment Tax Credits

We use the liability method of accounting for income taxes.  Under the liability method, we provide deferred income taxes for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence.

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

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We account for investment tax credits under the flow-through method except where regulatory commissions reflect investment tax credits in the rate-making process on a deferral basis.  We amortize deferred investment tax credits over the life of the plant investment.

We account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.”  We classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense.

Excise Taxes

We act as an agent for some state and local governments and collect from customers certain excise taxes levied by those state or local governments on our customers.  We do not recognize these taxes as revenue or expense.

Debt

We defer gains and losses from the reacquisition of debt used to finance regulated electric utility plants and amortize the deferral over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced.  If we refinance the reacquired debt associated with the regulated business, the reacquisition costs attributable to the portions of the business subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates.  Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition.

We defer debt discount or premium and debt issuance expenses and amortize generally utilizing the straight-line method over the term of the related debt.  The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations.  We include the net amortization expense in Interest Expense on the statements of income.

Goodwill and Intangible Assets

When we acquire businesses, we record the fair value of all assets and liabilities, including intangible assets.  To the extent that consideration exceeds the fair value of identified assets, we record goodwill.  We do not amortize goodwill and intangible assets with indefinite lives.  We test acquired goodwill and other intangible assets with indefinite lives for impairment at least annually at their estimated fair value.  We test goodwill at the reporting unit level and other intangibles at the asset level.  Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties, that is, 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, we estimate fair value using various internal and external valuation methods.  We amortize intangible assets with finite lives over their respective estimated lives to their estimated residual values.  We also review the lives of the amortizable intangibles with finite lives on an annual basis.

Investments Held in Trust for Future Liabilities

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


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Benefit Plans

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

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

Maintaining a long-term investment horizon.
Diversifying assets to help control volatility of returns at acceptable levels.
Managing fees, transaction costs and tax liabilities to maximize investment earnings.
Using active management of investments where appropriate risk/return opportunities exist.
Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks.
Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.
 
The investment policy for the pension fund allocates assets based on the funded status of the pension plan.  The objective of the asset allocation policy is to reduce the investment volatility of the plan over time.  Generally, more of the investment mix will be allocated to fixed income investments as the plan becomes better funded.  Assets will be transferred away from equity investments into fixed income investments based on the market value of plan assets compared to the plan’s projected benefit obligation.  The current target asset allocations are as follows:
Pension Plan Assets
 
Target
Equity
 
30.0
%
Fixed Income
 
55.0
%
Other Investments
 
15.0
%
 
 
 
OPEB Plans Assets
 
Target
Equity
 
65.0
%
Fixed Income
 
33.0
%
Cash
 
2.0
%

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

For equity investments, the limits are as follows:

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


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For fixed income investments, the concentration limits must not exceed:

3% in any single issuer.
5% for private placements.
5% for convertible securities.
60% for bonds rated AA+ or lower.
50% for bonds rated A+ or lower.
10% for bonds rated BBB- or lower.

For obligations of non-government issuers within the fixed income portfolio, the following limitations apply:

AAA rated debt: a single issuer should account for no more than 5% of the portfolio.
AA+, AA, AA- rated debt: a single issuer should account for no more than 3% of the portfolio.
Debt rated A+ or lower:  a single issuer should account for no more than 2% of the portfolio.
No more than 10% of the portfolio may be invested in high yield and emerging market debt combined at any time.

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

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

We participate in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses.  We lend securities to borrowers approved by BNY Mellon in exchange for collateral.  All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested.  The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security.  The securities lending program’s objective is providing modest incremental income with a limited increase in risk.

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


77



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

Nuclear Trust Funds

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

Acceptable investments (rated investment grade or above when purchased).
Maximum percentage invested in a specific type of investment.
Prohibition of investment in obligations of AEP or its affiliates.
Withdrawals permitted only for payment of decommissioning costs and trust expenses.

We maintain trust records for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds.  These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities.  The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

We record securities held in these trust funds as Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.  We record these securities at fair value.  We classify securities in the trust funds as available-for-sale due to their long-term purpose.  Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  We record unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.  See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters.  See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.

Comprehensive Income (Loss)

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

Stock-Based Compensation Plans

As of December 31, 2014, we had performance units and restricted stock units outstanding under the Amended and Restated American Electric Power System Long-Term Incentive Plan (LTIP).  This plan was last approved by shareholders in April 2010.  Upon vesting, performance units are paid in cash and restricted stock units are settled in AEP Common Shares, except for restricted stock units granted after January 1, 2013 and vesting to executive officers, which are paid in cash.


78



We maintain a variety of tax qualified and nonqualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock.  This includes career share accounts maintained under the American Electric Power System Stock Ownership Requirement Plan, which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors.  Career shares are derived from vested performance units granted to employees under the LTIP.  Career shares are equal in value to shares of AEP common stock and become payable to executives in cash after their service ends.  Career shares accrue additional dividend shares in an amount equal to dividends paid on AEP Common shares, and are reinvested in such shares at the closing market price on the dividend payments date.

We compensate our non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors.  These stock units become payable in cash to directors after their service ends.

We measure and recognize compensation expense for all share-based payment awards to employees and directors, including stock options, based on estimated fair values. For share-based payment awards with service only vesting conditions, we recognize compensation expense using the straight-line single-option method.  Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2014, 2013 and 2012 is based on awards ultimately expected to vest.  Therefore, stock-based compensation expense has been reduced to reflect estimated forfeitures.  Accounting guidance for “Compensation - Stock Compensation” requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates.

For the years ended December 31, 2014, 2013 and 2012, compensation expense is included in Net Income for the performance units, career shares, restricted stock units and the non-employee director’s stock units.  See Note 15 for additional discussion.

Earnings Per Share (EPS)

Shown below are income statement amounts attributable to AEP common shareholders:
 
 
Years Ended December 31,
Amounts Attributable to AEP Common Shareholders
 
2014
 
2013
 
2012
 
 
(in millions)
Net Income
 
$
1,638

 
$
1,484

 
$
1,262

Net Income Attributable to Noncontrolling Interests
 
4

 
4

 
3

Earnings Attributable to AEP Common Shareholders
 
$
1,634

 
$
1,480

 
$
1,259


Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period.  Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.

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The following table presents our basic and diluted EPS calculations included on the statements of income:
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(in millions, except per share data)
 
 
 
 
$/share
 
 
 
$/share
 
 
 
$/share
Earnings Attributable to AEP Common Shareholders
 
$
1,634

 
 
 
$
1,480

 
 
 
$
1,259

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares Outstanding
 
488.6

 
$
3.34

 
486.6

 
$
3.04

 
484.7

 
$
2.60

Weighted Average Dilutive Effect of Restricted Stock Units
 
0.3

 

 
0.4

 

 
0.4

 

Weighted Average Number of Diluted Shares Outstanding
 
488.9

 
$
3.34

 
487.0

 
$
3.04

 
485.1

 
$
2.60


There were no antidilutive shares outstanding as of December 31, 2014, 2013 and 2012.

OPCo Revised Depreciation Rates

Effective December 1, 2011, we revised book depreciation rates for certain of OPCo’s generation plants consistent with shortened depreciable lives for the generating units.  This change in depreciable lives resulted in a $52 million increase in depreciation expense in 2012.

In the fourth quarter of 2012, we impaired certain Ohio generating units (see Note 7).  As a result of this impairment of the full book value of these assets, we ceased depreciation on these generating units effective December 1, 2012.

In the second quarter of 2013, we impaired Muskingum River Plant, Unit 5 (MR5).  As a result of this impairment of the full book value of this generating unit, we ceased depreciation on MR5 effective July 1, 2013.

The effect of these revised depreciation rates and impairments is reported in the Generation & Marketing segment.

Supplementary Related Party Information

AEP and several nonaffiliated utility companies jointly own OVEC.  As of December 31, 2014, AEP’s ownership and investment in OVEC were 43.47% and $4.4 million, respectively.

OVEC’s owners are members to an intercompany power agreement.  Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,200 MWs, in proportion to their respective power participation ratios.  The aggregate power participation ratio of certain AEP utility subsidiaries is 43.47%.  The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and provide a return on capital.  The intercompany power agreement ends in June 2040.
 
AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures totaling $1.3 billion in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants.  These environmental projects were funded through debt issuances.  As of December 31, 2014, both generation plants were operating with environmental controls.


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The following details related party transactions for the years ended December 31, 2014, 2013 and 2012:
 
 
Years Ended December 31,
Related Party Transactions
 
2014
 
2013
 
2012
 
 
(in millions)
AEP Consolidated Revenues – Other Revenues:
 
 
 
 
 
 
OVEC – Barging and Other Transportation Services
 
$
24

 
$
21

 
$
30

AEP Consolidated Expenses – Purchased Electricity for Resale:
 
 
 
 
 
 
OVEC
 
268

 
289

 
273


Supplementary Income Statement Information

The following table provides the components of Depreciation and Amortization for the years ended December 31, 2014, 2013 and 2012:
 
 
Years Ended December 31,
Depreciation and Amortization
 
2014
 
2013
 
2012
 
 
(in millions)
Depreciation and Amortization of Property, Plant and Equipment
 
$
1,605

 
$
1,472

 
$
1,505

Amortization of Certain Securitized Assets
 
310

 
248

 
224

Amortization of Regulatory Assets and Liabilities
 
14

 
23

 
53

Total Depreciation and Amortization
 
$
1,929

 
$
1,743

 
$
1,782


Supplementary Cash Flow Information
 
 
Years Ended December 31,
Cash Flow Information
 
2014
 
2013
 
2012
 
 
(in millions)
Cash Paid (Received) for:
 
 
 
 
 
 
Interest, Net of Capitalized Amounts
 
$
838

 
$
882

 
$
931

Income Taxes
 
117

 
(55
)
 
(82
)
Noncash Investing and Financing Activities:
 
 
 
 
 
 
Acquisitions Under Capital Leases
 
135

 
182

 
63

Construction Expenditures Included in Current Liabilities as of December 31,
 
559

 
492

 
439

Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,
 
45

 

 
35

Assumption of Liabilities Related to Acquisitions
 

 

 
56

Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage
 
3

 
4

 
30



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2.  NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of final pronouncements, we review the new accounting literature to determine its relevance, if any, to our business. The following final pronouncements will impact our financial statements.

ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08)

In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of our financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. We adopted ASU 2014-08 effective January 1, 2015. We expect no impact on the financial statements in the first quarter of 2015.

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

In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, 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 new accounting guidance is effective for interim and annual periods beginning after December 15, 2016. Early adoption is not permitted. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. We plan to adopt ASU 2014-09 effective January 1, 2017.

ASU 2015-01 “Income Statement Extraordinary and Unusual Items” (ASU 2015-01)

In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. 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.
 
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. We plan to adopt ASU 2015-01 effective January 1, 2016.

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3.  COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI for the years ended December 31, 2014 and 2013.  All amounts in the following tables are presented net of related income taxes.
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
 
 
Pension and OPEB
 
 
 
 
Commodity
 
Interest Rate
and Foreign
Currency
 
Securities Available for Sale
 
Amortization
of Deferred
Costs
 
Changes
in Funded
Status
 
Total
 
 
(in millions)
Balance in AOCI as of December 31, 2013
 
$

 
$
(23
)
 
$
7

 
$
134

 
$
(233
)
 
$
(115
)
Change in Fair Value Recognized in AOCI
 
(10
)
 

 
1

 

 
1

 
(8
)
Amounts Reclassified from AOCI
 
11

 
4

 

 
5

 

 
20

Net Current Period Other Comprehensive Income
 
1

 
4

 
1

 
5

 
1

 
12

Balance in AOCI as of December 31, 2014
 
$
1

 
$
(19
)
 
$
8

 
$
139

 
$
(232
)
 
$
(103
)
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
 
 
Pension and OPEB
 
 
 
 
Commodity
 
Interest Rate
and Foreign
Currency
 
Securities Available for Sale
 
Amortization
of Deferred
Costs
 
Changes
in Funded
Status
 
Total
 
 
(in millions)
Balance in AOCI as of December 31, 2012
 
$
(8
)
 
$
(30
)
 
$
4

 
$
112

 
$
(415
)
 
$
(337
)
Change in Fair Value Recognized in AOCI
 
10

 
2

 
3

 

 
177

 
192

Amounts Reclassified from AOCI
 
(2
)
 
5

 

 
22

 

 
25

Net Current Period Other Comprehensive Income
 
8

 
7

 
3

 
22

 
177

 
217

Pension and OPEB Adjustment Related to Mitchell Plant
 

 

 

 

 
5

 
5

Balance in AOCI as of December 31, 2013
 
$

 
$
(23
)
 
$
7

 
$
134

 
$
(233
)
 
$
(115
)


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Reclassifications from Accumulated Other Comprehensive Income

The following table provides details of reclassifications from AOCI for the years ended December 31, 2014 and 2013.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs.  See Note 8 for additional details.
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Years Ended December 31, 2014 and 2013
 
 
 
 
 
 
 
Amount of (Gain) Loss
Reclassified from AOCI
 
 
Years Ended December 31,
 
 
2014
 
2013
Gains and Losses on Cash Flow Hedges
 
(in millions)
Commodity:
 
 
 
 
Vertically Integrated Utilities Revenues
 
$

 
$
(1
)
Generation & Marketing Revenues
 
59

 
(10
)
Purchased Electricity for Resale
 
(39
)
 
8

Regulatory Assets/(Liabilities), Net (a)
 
(3
)
 

Subtotal  Commodity
 
17

 
(3
)
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
Interest Expense
 
6

 
7

Subtotal  Interest Rate and Foreign Currency
 
6

 
7

 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
23

 
4

Income Tax (Expense) Credit
 
8

 
1

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
15

 
3

 
 
 
 
 
Pension and OPEB
 
 
 
 
Amortization of Prior Service Cost (Credit)
 
(21
)
 
(21
)
Amortization of Actuarial (Gains)/Losses
 
29

 
55

Reclassifications from AOCI, before Income Tax (Expense) Credit
 
8

 
34

Income Tax (Expense) Credit
 
3

 
12

Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
5

 
22

 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
20

 
$
25


(a)
Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. 
 

84



The following table provides details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges for the year ended December 31, 2012.  All amounts in the following table are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Year Ended December 31, 2012
 
 
 
 
 
 
 
Commodity
 
Interest Rate
and Foreign
Currency
 
Total
 
(in millions)
Balance in AOCI as of December 31, 2011
$
(3
)
 
$
(20
)
 
$
(23
)
Changes in Fair Value Recognized in AOCI
(15
)
 
(14
)
 
(29
)
Amount of (Gain) or Loss Reclassified from AOCI
to Statement of Income/within Balance Sheet:
 
 
 
 
 
Vertically Integrated Utilities Revenues

 

 

Generation & Marketing Revenues
(5
)
 

 
(5
)
Purchased Electricity for Resale
13

 

 
13

Other Operation Expense

 

 

Maintenance Expense

 

 

Interest Expense

 
4

 
4

Property, Plant and Equipment

 

 

Regulatory Assets (a)
2

 

 
2

Balance in AOCI as of December 31, 2012
$
(8
)
 
$
(30
)
 
$
(38
)

(a)
Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

The following table provides details of changes in unrealized gains and losses related to securities available for sale and the reasons for changes for the year ended December 31, 2012.  All amounts in the following table are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity for Securities Available for Sale
Year Ended December 31, 2012
 
 
 
(in millions)
Balance in AOCI as of December 31, 2011
$
2

Changes in Fair Value Recognized in AOCI
2

Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income:
 
    Interest Income

Balance in AOCI as of December 31, 2012
$
4


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4.  RATE MATTERS

Our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  Rate matters can have a material impact on net income, cash flows and possibly financial condition.  Our recent significant rate orders and pending rate filings are addressed in this note.

OPCo Rate Matters

Ohio Electric Security Plan Filings

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. The PUCO’s March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO.

In October 2011, the PUCO issued an order in the remand proceeding, which was subsequently appealed. In February 2014, the Supreme Court of Ohio affirmed the PUCO’s decision and rejected all appeals.
 
In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU and the Ohio Consumers' Counsel (OCC) also filed appeals of the PUCO decision which principally argued that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues. IEU's appeal also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of December 31, 2014, could reduce carrying costs by $26 million including $14 million of unrecognized equity carrying costs. In December 2014, IEU filed a motion to withdraw its argument related to the collection of POLR revenues. In January 2015, the OCC filed a request to dismiss its appeal altogether. Oral arguments at the Supreme Court of Ohio were held in February 2015. OPCo argued for a remand to reinstate the WACC carrying charges initially approved by the PUCO and challenged the IEU argument that the carrying charges should be reduced due to an accumulated deferred income tax credit. A decision from the Supreme Court of Ohio is pending.

Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition.

June 2012 – May 2015 ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and is $150/MW day from June 2014 through May 2015.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.


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As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR was collected from customers at $3.50/MWh through May 2014 and is currently collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs.  As of December 31, 2014, OPCo’s incurred deferred capacity costs balance of $422 million, including debt carrying costs, was recorded in regulatory assets on the balance sheet.

In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order, including the implementation of the RSR. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR.

In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. As ordered, in 2014, OPCo conducted multiple energy-only auctions for a total of 100% of the SSO load with delivery beginning April 2014 through May 2015. For delivery starting in June 2015, OPCo will conduct energy and capacity auctions for its entire SSO load. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit.

In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor recommends a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and intends to oppose the findings in the audit report.
 
If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.

Proposed June 2015 – May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal included a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM capacity and energy auction-based generation through OPCo. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based purchase power agreement. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In May 2014, intervenors and the PUCO staff filed testimony that provided various recommendations including the rejection and/or modification of various riders, including the DIR and the proposed PPA. Hearings at the PUCO in the ESP case were held in June 2014.


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In July 2014, OPCo submitted a separate application to continue the RSR established in the June 2012 - May 2015 ESP to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. In December 2014, the PUCO staff and intervenors filed comments related to the RSR application. The PUCO staff recommended approval of the application. Intervenors objected to the application and recommended approval of a pending motion to dismiss.

In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA for inclusion in the PPA rider, discussed above. The new PPA would include an additional 2,671 MW to be purchased from AGR over the life of the respective generating units.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.

Significantly Excessive Earnings Test Filings

In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending.

In March 2014, the PUCO approved a stipulation agreement between OPCo and the PUCO staff that there were no significantly excessive earnings in 2011 for CSPCo or OPCo. In May 2014 and December 2014, the PUCO approved stipulation agreements between OPCo and the PUCO staff that there were no significantly excessive earnings for OPCo in 2012 and 2013, respectively.

Management believes its financial statements adequately address the impact of 2014 SEET requirements.

Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo’s generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition.

Storm Damage Recovery Rider (SDRR)

In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates to recover 2012 incremental storm distribution expenses. In April 2014, the PUCO approved a stipulation agreement to recover $55 million over a 12-month period. The agreement also provided that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period. Compliance tariffs were filed with the PUCO and new rates were implemented in April 2014. In May 2014, the PUCO upheld the settlement agreement on rehearing.
 

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2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.

In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC, with carrying charges. In September 2014, the Supreme Court of Ohio upheld the PUCO order. A review of the coal reserve valuation by an outside consultant is still pending. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a WACC. In May 2014, the PUCO issued an order that generally approved OPCo's 2010-2011 fuel costs and rejected the auditor recommendation to adjust the WACC carrying charges related to accumulated deferred income taxes. Additionally, the PUCO requested further review related to an affiliate barging agreement and the modification of certain fuel procurement processes and practices. Further, the order provided for the auditor to address any remaining concerns in the next audit report, as deemed necessary. In July 2014, the PUCO issued an order that denied all requests for rehearing.

2012 and 2013 Fuel Adjustment Clause Audits

In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June 2012 - May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition.

Ormet

Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In February 2013, Ormet filed for bankruptcy and subsequently shut down operations in October 2013. Based upon previous PUCO rulings providing rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider (EDR), except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet’s October and November 2012 power bills. In February 2014, a stipulation agreement between OPCo and Ormet was filed with the PUCO. The stipulation recommended approval of OPCo’s right to fully recover approximately $49 million of foregone revenues through the EDR. Intervenor comments were also filed objecting to full recovery of these foregone revenues. In March 2014, the PUCO issued an order in OPCo’s EDR filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of December 31, 2014, is recorded in regulatory assets on the balance sheet. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement was held in May 2014.

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In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.

To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition.
 
Ohio IGCC Plant

In 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. As of December 31, 2014, OPCo has collected $24 million in pre-construction costs authorized in a 2006 PUCO order. Intervenors filed motions and comments with the PUCO requesting that OPCo refund all collected pre-construction costs to Ohio ratepayers with interest. In December 2014, a stipulation agreement between OPCo, the PUCO staff and intervenors was filed at the PUCO. The parties to the stipulation agreement proposed that OPCo will refund $13 million to its customers. In February 2015, the PUCO approved the stipulation agreement.

SWEPCo Rate Matters

2012 Texas Base Rate Case
 
In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In October 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of December 31, 2014, the net book value of Welsh Plant, Unit 2 was $84 million, before cost of removal, including materials and supplies inventory and CWIP. See “Regulated Generating Units to be Retired Before or During 2016” section of Note 5.

Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase is approximately $52 million. In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses.

If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

Texas Transmission Cost Recovery Factor Filing

In May 2014, SWEPCo filed an application with the PUCT to implement its transmission cost recovery factor (TCRF) requesting additional annual revenue of $15 million. The TCRF is designed to recover increases from the amounts included in SWEPCo’s Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC. SWEPCo’s application included Turk Plant transmission-related costs. In November 2014, the PUCT issued an order approving a proposal for decision, issued by an Administrative Law Judge in October 2014, that recommended approval of SWEPCo's application with an increase in annual revenue of $14 million. In December 2014, the PUCT order became final and TCRF rates were implemented.

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2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually.  The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit. The rates are subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC review base rates in 2014 and 2015 and that SWEPCo recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million, primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition.

2014 Louisiana Formula Rate Filing

In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC.  The filing included a $5 million annual increase, which was effective August 2014.  SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchase power agreement attributable to Louisiana customers.  In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC.  Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC.  As of December 31, 2014, SWEPCo has incurred costs of $164 million and has remaining contractual construction obligations of $108 million related to these projects.  SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of December 31, 2014, the net book value of Welsh Plant, Units 1 and 3 was $388 million, before cost of removal, including materials and supplies inventory and CWIP.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 

 APCo and WPCo Rate Matters

Plant Transfer

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a cost-of-service basis, to their respective customers. West Virginia generally allows for timely recovery of fuel costs through an expanded net energy cost which trues-up to actual expenses. In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo until APCo's West Virginia base rates are updated. See the "2014 West Virginia Base Rate Case" below. In June 2014, the FERC issued an order approving a request by AGR and WPCo to transfer AGR’s one-half interest in the Mitchell Plant to WPCo.


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In October 2014, a stipulation agreement between APCo, WPCo, the WVPSC staff and intervenors in the case was filed with the WVPSC. The stipulation agreement recommended approval for WPCo to acquire, at net book value, the one-half interest in the Mitchell Plant, excluding certain assets, and to pay AGR $20 million upon transfer, which WPCo will record as a regulatory asset, include in rate base and recover over the life of the plant. Additionally, the agreement stated that 82.5% of the costs associated with the acquired interest will be reflected in rates effective from the date of the transfer via a surcharge with an offset in ENEC revenues of $93 million. The remaining 17.5% of the costs associated with the acquired interest is to be included in rates by January 2020. The agreement also proposed that WPCo share the energy margins for 82.5% of the plant’s output with ratepayers and that WPCo retain all of the energy margins from sales into the wholesale market on the remaining 17.5%, to offset fixed costs associated with this portion, until the remaining portion is included in rates. In December 2014, the WVPSC issued an order that approved the settlement agreement, subject to certain modifications related to 82.5% of the energy and capacity margin sharing. The WVPSC determined that the sharing mechanism that was proposed is reasonable and will be adopted provided the result of the sharing mechanism will be adjusted, if necessary, so that the sharing mechanism does not result in a net cost to ratepayers that exceeds the actual variable cost of generation. In January 2015, the transfer of the one-half interest in the Mitchell Plant to WPCo was completed.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a biennial generation and distribution base rate case with the Virginia SCC. In accordance with a Virginia statute, APCo did not request a change in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 was within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to changes in the expected service lives of various generating units and the extended recovery through 2040 of the net book value of certain planned 2015 plant retirements. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to IGCC and other deferred costs. APCo also requested approval to amortize $38 million related to an accumulated deferred Virginia state income tax (ADVSIT) liability over 20 years, beginning February 2015.

In November 2014, the Virginia SCC issued an order concluding that APCo's adjusted earned rate of return on common equity for 2012 and 2013, reflecting their ordered adjustments, was above the allowed threshold. The order included (a) a $6 million refund to customers for the years 2012 through 2013, (b) the write-off of $10 million of IGCC pre-construction costs, (c) approval to amortize a $38 million ADVSIT liability over 20 years, beginning February 2015 and (d) no change to generation depreciation rates with rates to be reviewed again in the next biennial rate case. The order also approved a new return on common equity of 9.7% effective for 2014 and 2015. Management believes its financial statements adequately address the impact of this order for 2014.

The Virginia SCC did not rule on a Virginia SCC staff recommendation to write-down certain costs, for ratemaking purposes, for the biennial period based on APCo’s earnings within the statutory equity range. In January 2015, the Virginia SCC initiated a separate proceeding to address the proper treatment of APCo’s authorized regulatory assets. As of December 31, 2014, APCo’s authorized regulatory assets under review in the separate proceeding, based upon the Virginia SCC staff recommendation, are estimated to be $15 million. In February 2015, initial briefs related to this proceeding were filed by various parties. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Potential New Virginia Legislation Affecting Biennial Reviews

In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were approved by the Virginia General Assembly and have been sent to the Governor. If these amendments are enacted, APCo’s existing generation and distribution base rates would freeze until after the Virginia SCC rules on APCo’s next biennial review, which APCo would file in March 2020 for the 2018 and 2019 test years. These amendments would also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. Management continues to monitor this potential new legislation in Virginia.


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2014 West Virginia Base Rate Case

In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $181 million, based upon a 10.62% return on common equity, to be effective in the second quarter of 2015.  The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units.  The filing also requested recovery of $89 million over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs.  In addition to the base rate request, the filing also included a request to implement a rider of approximately $45 million annually to recover vegetation management costs, including a return on capital investment.  In October 2014, the WVPSC approved APCo's motion to revise the procedural schedule which included a request to change the date of implementation of the new rates to May 2015.  In December 2014 and January 2015, intervenors filed testimony which proposed total annual revenue increases ranging from $35 million to $59 million based upon returns on common equity ranging from 9% to 10% and regulatory asset disallowances ranging from $7 million to $9 million.  Additionally, other intervenors proposed that the revenue requirement be based on a return on common equity of 8.7% and that $89 million of regulatory assets be disallowed.  Intervenors also recommended a disallowance of approximately $44 million related to the December 2013 transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo.  Hearings at the WVPSC were held in January 2015.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Transmission Rate Adjustment Clause (Transmission RAC)

In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually to be effective May 2014.  In March 2014, the Virginia SCC issued an order approving a stipulation agreement between APCo and the Virginia SCC staff increasing the transmission RAC revenues by $49 million annually, subject to true-up, effective May 2014. Pursuant to the order, the Virginia SCC staff will audit APCo’s transmission RAC under-recoveries and report its findings and recommendations in testimony in APCo’s next transmission RAC proceeding in 2015.

PSO Rate Matters

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity.  This revenue increase includes a proposed increase in depreciation rates of $29 million.  In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three.  The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years.

In April and May 2014, testimony was filed by the OCC staff and intervenors with recommendations that included adjustments to annual base rates ranging from an increase of $16 million to a reduction of $22 million, primarily based upon the determination of depreciation rates and a return on common equity between 9.18% and 9.5%. Additionally, the recommendations did not support the advanced metering rider or the expansion of the transmission rider. In May 2014, PSO filed rebuttal testimony that included an updated annual base rate increase request of $42 million to reflect certain updated costs.

In June 2014, a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors was filed with the OCC. The parties to the stipulation recommended no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider would provide $24 million of revenues over 14 months beginning in November 2014 and increase to $27 million in 2016. New depreciation rates are recommended for advanced metering investments and existing meters, also to be effective November 2014. Further, the stipulation recommends a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component. Additionally, the stipulation recommends

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recovery of regulatory assets for 2013 storms and regulatory case expenses. In July 2014, the Attorney General joined in the stipulation agreement. A hearing at the OCC was held in July 2014. In October 2014, the Administrative Law Judge (ALJ) recommended approval of the stipulation agreement and interim rates were implemented in November 2014, subject to refund. In November 2014, intervenors opposing the stipulation agreement filed exceptions to the ALJ's report and oral arguments were held at the OCC in December 2014. An order is anticipated in the first quarter of 2015. If the OCC were to disallow any portion of this settlement agreement, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters
 
2011 Indiana Base Rate Case
 
In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2% and adjusted the authorized annual increase in base rates to $92 million in March 2013. In April 2014, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal to the Indiana Supreme Court related to the inclusion of a prepaid pension asset in rate base, which is approximately $7 million in annual revenues. In August 2014, the Indiana Supreme Court denied the appeal filed by the OUCC.

Cook Plant Life Cycle Management Project (LCM Project)

In 2012, I&M filed a petition with the IURC and the MPSC for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of December 31, 2014, I&M has incurred costs of $550 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In May 2014, the IURC issued a final order approving the LCM rider rates that were implemented in January 2014.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project. In October 2014, the Michigan Court of Appeals issued an order that affirmed the MPSC decision in part, but reversed the portion of the MPSC decision related to certain costs. The order indicated that I&M could recover those costs in a future Michigan base case if they can show that the costs were reasonable and prudent.

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

Tanners Creek Plant

I&M announced that it would retire Tanners Creek Plant by June 2015 to comply with proposed environmental regulations. I&M is currently recovering depreciation and a return on the net book value of the Tanners Creek Plant in base rates and plans to seek recovery of all of the plant’s retirement related costs in its next Indiana and Michigan base rate cases.


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In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015. Upon the retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant.

In September 2014, a settlement agreement was approved by the MPSC that included the authorization for I&M to implement revised depreciation rates for Rockport Plant, Unit 1, effective upon the retirement date of the Tanners Creek Plant. Upon implementation of the revised depreciation rates, I&M is authorized to reduce customer rates through a credit rider until the revised rates for Rockport Plant, Unit 1 are included in base rates.

In October 2014, I&M filed a similar application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In February 2015, the OUCC filed testimony that recommended approval of I&M's application. A hearing at the IURC is scheduled for March 2015.

As of December 31, 2014, the net book value of the Tanners Creek Plant was $340 million, before cost of removal, including material and supplies inventory and CWIP.  See “Regulated Generating Units to be Retired Before or During 2016” section of Note 5. If I&M is ultimately not permitted to fully recover its net book value of the Tanners Creek Plant and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition.

Transmission, Distribution and Storage System Improvement Charge (TDSIC)

In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan, from 2015 through 2021, for eligible transmission, distribution and storage system improvements. The initial estimated cost of the capital improvements and associated operation and maintenance expenses included in the TDSIC Plan of $787 million, excluding AFUDC, will be updated annually. The TDSIC Plan included distribution investments specific to the Indiana jurisdiction. The TDSIC Rider will allow the periodic adjustment of I&M's rates to provide for timely recovery of 80% of approved TDSIC Plan costs. I&M will defer the remaining 20% of approved TDSIC Plan costs to be recovered in I&M's next general rate case. I&M is not seeking a rate adjustment in this proceeding but is seeking approval of a TDSIC Rider rate adjustment mechanism for subsequent proceedings. In January 2015, intervenors filed testimony that recommended denial of certain portions of the TDSIC Plan including recommended changes to the capital structure, recovery of requested operation and maintenance cost allocations and the rate design within the TDSIC Rider mechanism. A hearing at the IURC was held in February 2015. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

KPCo Rate Matters

Plant Transfer

In December 2012, KPCo filed a request with the KPSC for approval to transfer at net book value to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. KPCo also requested that costs related to the Big Sandy Plant, Unit 2 FGD project be established as a regulatory asset. As of December 31, 2014, the net book value of Big Sandy Plant, Unit 2 was $253 million, before cost of removal, including materials and supplies inventory and CWIP. See “Regulated Generating Units to be Retired Before or During 2016” section of Note 5.

In October 2013, the KPSC issued an order approving a modified settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club. The modified settlement approved the transfer of a one-half interest in the Mitchell Plant to KPCo at net book value on December 31, 2013 with the limitation that the net book value of the Mitchell Plant transfer not exceed the amount to be determined by a WVPSC order. In December 2014,

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the WVPSC issued the Mitchell Plant transfer order with no disallowances. See the "Plant Transfer" disclosure above within the APCo and WPCo Rate Matters section. The modified settlement agreement approved by the KPSC also included the implementation of an Asset Transfer Rider to collect $44 million annually effective January 2014, subject to true-up, and allowed KPCo to retain any off-system sales margins above the $15.3 million annual level in base rates. Additionally, the settlement allows for KPCo to file a Certificate of Public Convenience and Necessity to convert Big Sandy Plant, Unit 1 to natural gas, provided the cost is approximately $60 million, and addressed potential greenhouse gas initiatives on the Mitchell Plant. The settlement also approved recovery, including a return, of coal-related retirement costs related to Big Sandy Plant over 25 years when base rates are set (no earlier than June 2015) in the next base rate case, but rejected KPCo’s request to defer FGD project costs for Big Sandy Plant, Unit 2. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed.

In December 2013, the Attorney General filed an appeal with the Franklin County Circuit Court. In May 2014, KPCo's motion to dismiss the appeal was denied. In May 2014, KPCo filed motions for reconsideration and clarification with the Franklin County Circuit Court. In June 2014, the motion for reconsideration was denied but the motion to clarify was granted, thereby limiting the appeal to the issues of law presented in the Attorney General's appeal. If any part of the KPSC order is overturned, it could reduce future net income and cash flows and impact financial condition.

Kentucky Fuel Adjustment Clause Review

In August 2014, the KPSC issued an order initiating a review of KPCo's FAC from November 2013 through April 2014. In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owns and operates both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. Additionally, the KPSC directed KPCo to refund to customers $13 million of fuel costs, by the end of the second quarter of 2015, collected during the FAC review period of January 2014 through April 2014. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court.

2014 Kentucky Base Rate Case

In December 2014, KPCo filed a request with the KPSC for an increase in rates of $70 million, which consists of a $75 million increase in rider rates, offset by a $5 million decrease in annual base rates, to be effective July 2015. The net increase reflects KPCo's ownership interest in the Mitchell Plant, riders to recover the Big Sandy Plant retirement and operational costs and the inclusion of an environmental compliance plan related to the Mitchell Plant FGD. Additionally, the filing included a request to recover deferred storm costs. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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5.  EFFECTS OF REGULATION

Regulated Generating Units to be Retired Before or During 2016

The following regulated generating units are probable of abandonment.  Accordingly, CWIP and Plant in Service has been reclassified as Other Property, Plant and Equipment on the balance sheet as of December 31, 2014.  The following table summarizes the plant investment and cost of removal, currently being recovered, for each generating unit as of December 31, 2014.
Plant Name and Unit
 
Company
 
Gross
Investment
 
Accumulated
Depreciation
 
Net
Investment
 
Cost of
Removal
Regulatory
Liability
 
Expected
Retirement
Date
 
Remaining
Recovery
Period
(in millions)
Tanners Creek Plant, Units 1-4
 
I&M
 
$
711

 
$
384

 
$
327

 
$
89

 
2015
 
16 years
Big Sandy Plant, Unit 2
 
KPCo
 
455

 
208

 
247

 
51

 
2015
 
26 years
Northeastern Station, Unit 4
 
PSO
 
182

 
91

 
91

 
11

 
2016
 
26 years
Welsh Plant, Unit 2
 
SWEPCo
 
175

 
96

 
79

 
20

 
2016
 
26 years
Total
 
 
 
$
1,523

 
$
779

 
$
744

 
$
171

 
 
 
 

In accordance with accounting guidance for “Regulated Operations,” APCo regulated generating units expected to be retired before or during 2016 are not considered probable of abandonment.


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Regulatory Assets

Regulatory assets are comprised of the following items:
 
 
December 31,
 
Remaining Recovery Period
 
 
2014
 
2013
 
Current Regulatory Assets
 
(in millions)
 
 
Under-recovered Fuel Costs - earns a return
 
$
121

 
$
61

 
1 year
Under-recovered Fuel Costs - does not earn a return
 
6

 
19

 
1 year
Total Current Regulatory Assets
 
$
127

 
$
80

 
 
 
 
 
 
 
 
 
Noncurrent Regulatory Assets
 
 
 
 
 
 
Regulatory assets pending final regulatory approval:
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
Storm Related Costs
 
$
20

 
$
22

 
 
West Virginia Vegetation Management Program
 
20

 

 
 
Ohio Economic Development Rider
 

 
14

 
 
Other Regulatory Assets Pending Final Regulatory Approval
 

 
4

 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
Storm Related Costs
 
100

 
161

 
 
Carbon Capture and Storage Product Validation Facility
 
13

 
13

 
 
IGCC Pre-Construction Costs
 
11

 

 
 
Ormet Special Rate Recovery Mechanism
 
10

 
36

 
 
Expanded Net Energy Charge - Coal Inventory
 
3

 
21

 
 
Indiana Under-Recovered Capacity Costs
 

 
22

 
 
Other Regulatory Assets Pending Final Regulatory Approval
 
49

 
37

 
 
Total Regulatory Assets Pending Final Regulatory Approval
 
226

 
330

 
 
 
 
 
 
 
 
 
Regulatory assets approved for recovery:
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
Ohio Capacity Deferral
 
422

 
288

 
4 years
Ohio Fuel Adjustment Clause
 
378

 
445

 
4 years
Unamortized Loss on Reacquired Debt
 
66

 
81

 
29 years
Texas Meter Replacement Costs
 
59

 
77

 
13 years
Ohio Distribution Decoupling
 
35

 
31

 
2 years
Ohio Transmission Cost Recovery Rider
 
28

 
87

 
2 years
Storm Related Costs
 
13

 
17

 
4 years
Red Rock Generating Facility
 
10

 
10

 
42 years
RTO Formation/Integration Costs
 
9

 
12

 
5 years
Other Regulatory Assets Approved for Recovery
 
21

 
18

 
various
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
Income Taxes, Net
 
1,268

 
1,390

 
53 years
Pension and OPEB Funded Status
 
1,273

 
1,157

 
13 years
Peak Demand Reduction/Energy Efficiency
 
62

 
44

 
2 years
Virginia Transmission Rate Adjustment Clause
 
53

 
47

 
2 years
Medicare Subsidy
 
46

 
51

 
10 years
Postemployment Benefits
 
39

 
40

 
4 years
Cook Plant Nuclear Refueling Outage Levelization
 
38

 
58

 
2 years
Storm Related Costs
 
26

 
18

 
4 years
Indiana Under-Recovered Capacity Costs
 
25

 

 
1 year
United Mine Workers of America Pension Withdrawal
 
25

 
27

 
11 years
Under-Recovery of PJM Expense
 
22

 

 
2 years
Under-Recovered gridSMART® Costs
 
16

 
8

 
2 years
Under-Recovery of Transmission Cost Recovery Factor
 
15

 
20

 
1 year
Under-Recovered Distribution Investment Rider
 
10

 
9

 
2 years
Unrealized Loss on Forward Commitments
 
10

 

 
3 years
Litigation Settlement
 
9

 
10

 
11 years
Deferred Restructuring Costs
 
8

 
11

 
4 years
Vegetation Management
 
5

 
14

 
1 year
Virginia Environmental Rate Adjustment Clause
 
3

 
27

 
1 year
Other Regulatory Assets Approved for Recovery
 
44

 
49

 
various
Total Regulatory Assets Approved for Recovery
 
4,038

 
4,046

 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Assets
 
$
4,264

 
$
4,376

 
 

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Regulatory Liabilities

Regulatory liabilities are comprised of the following items:
 
 
December 31,
 
Remaining
 
 
2014
 
2013
 
Refund Period
Current Regulatory Liabilities
 
(in millions)
 
 
Over-recovered Fuel Costs - pays a return
 
$

 
$
9

 

Over-recovered Fuel Costs - does not pay a return
 
55

 
110

 
1 year
Total Current Regulatory Liabilities
 
$
55

 
$
119

 
 
 
 
 
 
 
 
 
Noncurrent Regulatory Liabilities and
 
 
 
 
 
 
Deferred Investment Tax Credits
 
 
 
 
 
 
Regulatory liabilities pending final regulatory determination:
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
Other Regulatory Liabilities Pending Final Regulatory Determination
 
$

 
$
5

 
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
Provision for Regulatory Loss
 
35

 

 
 
Other Regulatory Liabilities Pending Final Regulatory Determination
 
17

 
3

 
 
Total Regulatory Liabilities Pending Final Regulatory Determination
 
52

 
8

 
 
 
 
 
 
 
 
 
Regulatory liabilities approved for payment:
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
Asset Removal Costs
 
2,660

 
2,589

 
(a)
Louisiana Refundable Construction Financing Costs
 
58

 
78

 
4 years
Advanced Metering Infrastructure Surcharge
 
44

 
68

 
6 years
Deferred Investment Tax Credits
 
26

 
29

 
46 years
Excess Earnings
 
11

 
12

 
39 years
Other Regulatory Liabilities Approved for Payment
 
4

 
1

 
various
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
Excess Asset Retirement Obligations for Nuclear
 
 
 
 
 
 
Decommissioning Liability
 
695

 
597

 
(b)
Deferred Investment Tax Credits
 
112

 
121

 
50 years
Unrealized Gain on Forward Commitments
 
92

 
35

 
18 years
Over-Recovery of Transition Charges
 
47

 
40

 
13 years
Spent Nuclear Fuel Liability
 
44

 
43

 
(b)
Indiana Off-system Sales Margin Sharing
 
19

 

 
2 years
Peak Demand Reduction/Energy Efficiency
 
3

 
18

 
2 years
Deferred State Income Tax Coal Credits
 

 
28

 

Over-Recovery of PJM Expense
 

 
14

 

Other Regulatory Liabilities Approved for Payment
 
25

 
13

 
various
Total Regulatory Liabilities Approved for Payment
 
3,840

 
3,686

 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
 
$
3,892

 
$
3,694

 
 

(a)
Relieved as removal costs are incurred.
(b)
Relieved when plant is decommissioned.

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6.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

We are subject to certain claims and legal actions arising in our ordinary course of business.  In addition, our business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation against us cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on our financial statements.

COMMITMENTS

Construction and Commitments

The AEP System has substantial construction commitments to support its operations and environmental investments.  In managing the overall construction program and in the normal course of business, we contractually commit to third-party construction vendors for certain material purchases and other construction services.  The subsidiaries purchase fuel, materials, supplies, services and property, plant and equipment under contract as part of their normal course of business.  Certain supply contracts contain penalty provisions for early termination.

The following table summarizes our actual contractual commitments as of December 31, 2014:
Contractual Commitments
 
Less Than
1 Year
 
2-3 Years
 
4-5 Years
 
After
5 Years
 
Total
 
 
(in millions)
Fuel Purchase Contracts (a)
 
$
2,240

 
$
2,735

 
$
1,825

 
$
2,104

 
$
8,904

Energy and Capacity Purchase Contracts
 
363

 
405

 
426

 
2,087

 
3,281

Construction Contracts for Capital Assets (b)
 
191

 

 

 

 
191

Total
 
$
2,794

 
$
3,140

 
$
2,251

 
$
4,191

 
$
12,376


(a)
Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.
(b)
Represents only capital assets for which we have 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.

GUARANTEES

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

Letters of Credit

We enter into standby letters of credit with third parties.  As Parent, we issue all of these letters of credit in our ordinary course of business on behalf of our subsidiaries.  These letters of credit cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

We have two revolving credit facilities totaling $3.5 billion, under which we may issue up to $1.2 billion as letters of credit.  As of December 31, 2014, the maximum future payments for letters of credit issued under the revolving credit facilities were $63 million with maturities ranging from February 2015 to March 2016.


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In January 2014, we issued letters of credit under an $85 million uncommitted facility.  In October 2014, the uncommitted facility was renewed through October 2015 and increased to $100 million. As of December 31, 2014, the maximum future payments for letters of credit issued under the revolving credit facilities were $81 million with a maturity of July 2015. An uncommitted facility gives the issuer of the facility the right to accept or decline each request we make under the facility.

We have $477 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $483 million.  The letters of credit have maturities ranging from March 2015 to July 2017.  In February 2015, $78 million of bilateral letters of credit maturing in March 2015 were extended to March 2017.
 
Guarantees of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study completed in 2010, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation.  As of December 31, 2014, SWEPCo has collected approximately $64 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $48 million is recorded in Asset Retirement Obligations on the balance sheet.

Sabine charges SWEPCo, its only customer, all of its costs.  SWEPCo passes these costs to customers through its fuel clause.

Indemnifications and Other Guarantees

Contracts

We enter into several types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, our exposure generally does not exceed the sale price.  As of December 31, 2014, there were no material liabilities recorded for any indemnifications.

Lease Obligations

We lease certain equipment under master lease agreements.  See “Master Lease Agreements” and “Railcar Lease” sections of Note 13 for disclosure of lease residual value guarantees.

ENVIRONMENTAL CONTINGENCIES

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation
 
By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, our generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials.  We currently incur costs to dispose of these substances safely.


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Superfund addresses clean-up of hazardous substances that have been released to the environment.  The Federal EPA administers the clean-up programs.  Several states have enacted similar laws.  As of December 31, 2014, our subsidiaries are named by the Federal EPA as a Potentially Responsible Party (PRP) for four sites for which alleged liability is unresolved.  There are nine additional sites for which our subsidiaries have received information requests which could lead to PRP designation.  Our subsidiaries have also been named potentially liable at three sites under state law including the I&M site discussed in the next paragraph.  In those instances where we have been named a PRP or defendant, our disposal or recycling activities were in accordance with the then-applicable laws and regulations.  Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories.  Liability has been resolved for a number of sites with no significant effect on net income.

In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M started remediation work in accordance with a plan approved by MDEQ.  In September 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As of December 31, 2014, I&M’s accrual for all of these sites is approximately $15 million.  As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation.  We cannot predict the amount of additional cost, if any.

We evaluate the potential liability for each Superfund site separately, but several general statements can be made about our potential future liability.  Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often 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, our estimates do not anticipate material cleanup costs for any of our identified Superfund sites, except the I&M sites discussed above.

NUCLEAR CONTINGENCIES

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC).  We have a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S.  Should a nuclear incident occur at any nuclear power plant in the U.S., the liability could be substantial.

Decommissioning and Low Level Waste Accumulation Disposal

The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program.  Decommissioning costs are accrued over the service life of the Cook Plant.  The most recent decommissioning cost study was performed in 2012.  According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste ranges from $1.3 billion to $1.7 billion in 2012 nondiscounted dollars.  The wide range in estimated costs is caused by variables in assumptions.  I&M recovers estimated decommissioning costs for the Cook Plant in its rates.  The amounts recovered in rates were $9 million, $10 million and $14 million for the years ended December 31, 2014, 2013 and 2012, respectively.  Decommissioning costs recovered from customers are deposited in external trusts.

As of December 31, 2014 and 2013, the total decommissioning trust fund balance was $1.8 billion and $1.6 billion, respectively.  Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers.  The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability.


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I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant.  However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.

SNF Disposal

The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal.  A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant was being collected from customers and remitted to the U.S. Treasury. This fee was terminated in May 2014.  As of December 31, 2014 and 2013, fees and related interest of $266 million and $265 million, respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $309 million and $309 million, respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts.  I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.

In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage.  Under the settlement agreement, I&M received $22 million, $31 million and $20 million in 2014, 2013 and 2012, respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016.  The proceeds reduced costs for dry cask storage.  As of December 31, 2014, I&M has deferred $13 million in Prepayments and Other Current Assets and $2 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement.

See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.

Nuclear Incident Liability

I&M carries insurance coverage for a nuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion.  Insurance coverage for a nonnuclear incident at the Cook Plant is $1.7 billion.  Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage.  I&M utilizes industry mutual insurers for the placement of this insurance coverage.  Participation in this mutual insurance requires a contingent financial obligation of up to $44 million for I&M which is assessable if the insurer’s financial resources would be inadequate to pay for losses.
 
The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $13.6 billion and covers any incident at a licensed reactor in the U.S.  Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage.  In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $121 million on each licensed reactor in the U.S. payable in annual installments of $19 million.  As a result, I&M could be assessed $242 million per nuclear incident payable in annual installments of $38 million.  The number of incidents for which payments could be required is not limited.

In the event of an incident of a catastrophic nature, I&M is initially covered for the first $375 million through commercially available insurance.  The next level of liability coverage of up to $13.2 billion would be covered by claims made under the Price-Anderson Act.  If the liability were in excess of amounts recoverable from insurance and retrospective claim payments made under the Price-Anderson Act, I&M would seek to recover those amounts from customers through rate increases.  In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition.


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OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

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

See “Nuclear Contingencies” section of this footnote for a discussion of nuclear exposures and related insurance.

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

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.  The New York court has granted our motion to transfer this case to the U.S. District Court for the Southern District of Ohio.  In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing.  We will continue to defend against the remaining claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Natural Gas Markets Lawsuits

In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity.  AEP was dismissed from the case.  A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies.  AEP (or a subsidiary) is among the companies named as defendants in some of these cases.  We settled, received summary judgment or were dismissed from all of these cases.  The plaintiffs appealed the Nevada federal district court's dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit.  In April 2013, the appellate court reversed in part, and affirmed in part, the district court's orders in these cases.  The appellate court reversed the district court's holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases.  Defendants in these cases, including AEP, previously filed a petition seeking further review with the U.S. Supreme Court on the preemption issue. In June 2014, AEP filed a petition with the U.S. Supreme Court seeking review of the personal jurisdiction issue. In July 2014,

104



the U.S. Supreme Court granted the defendants' previously filed petition for further review with the U.S. Supreme Court on the preemption issue. Oral argument occurred in January 2015.  We will continue to defend the cases.  We believe the provision we have is adequate. We are unable to determine the amount of potential additional losses that are reasonably possible of occurring.

Wage and Hours Lawsuit

In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act.  Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked.  Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs.  Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount.

In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action.  Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. We will continue to defend the case. We are unable to determine a range of potential losses that are reasonably possible of occurring.

National Do Not Call Registry Lawsuit

In May 2014, AEP Energy was served with a complaint filed in the U.S. District Court for the Northern District of Illinois, alleging violations of the Telephone Consumer Protection Act (TCPA). The plaintiff alleges that he received telemarketing calls on behalf of AEP Energy despite having registered his telephone number on the National Do Not Call Registry. Plaintiff seeks to represent a class of persons who allegedly received such calls. Plaintiff seeks statutory damages under the TCPA on behalf of himself and the alleged class as well as injunctive relief. As a result of a mediation held in October 2014, the parties reached an agreement in principle, subject to final documentation and preliminary and final court approval. We will continue to defend the case. We believe the provision we have is adequate. We are unable to determine the amount of potential additional losses that are reasonably possible of occurring.

Gavin Landfill Litigation

In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill.  The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors.  Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims.  The plaintiffs seek compensatory and punitive damages, as well as medical monitoring.  In September 2014, we filed a motion to dismiss the complaint, contending the case should be filed in Ohio.  That motion is pending.  We will continue to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

105



7.  ACQUISITION AND IMPAIRMENTS

ACQUISITION

2012

BlueStar Energy (Generation & Marketing segment)

In March 2012, we completed the acquisition of BlueStar Energy Holdings, Inc. (BlueStar) and its independent retail electric supplier BlueStar Energy Solutions for $70 million.  This transaction also included goodwill of $15 million, intangible assets associated with sales contracts and customer accounts of $58 million and liabilities associated with supply contracts of $25 million.  BlueStar has been in operation since 2002.  Beginning in June 2012, BlueStar began doing business as AEP Energy.  AEP Energy provides electric supply for retail customers in Ohio, Illinois and other deregulated electricity markets and also provides energy solutions throughout the United States, including demand response and energy efficiency services.

IMPAIRMENTS

2013

Amos Plant, Unit 3 (Vertically Integrated Utilities segment)

In July 2013, the Virginia SCC approved the transfer of a two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax.  The Virginia jurisdictional share of the reduced price is approximately $39 million.  In December 2013, the WVPSC issued an order that approved the transfer of a two-thirds interest in the Amos Plant, Unit 3 to APCo but deferred a final decision related to the $83 million pretax reduction in transfer price until APCo’s next base rate case.  The West Virginia and FERC jurisdictional share of the potential reduced transfer price is approximately $44 million.  Upon evaluation, management believes the West Virginia jurisdictional share is probable of recovery.  As a result of the Virginia order, in the fourth quarter of 2013, we recorded a pretax impairment of $39 million in Asset Impairments and Other Related Charges on the statement of income.  
 
Big Sandy Plant, Unit 2 FGD Project (Vertically Integrated Utilities segment)

In the third quarter of 2013, KPCo recorded a pretax write-off of $33 million in Asset Impairments and Other Related Charges on the statement of income primarily related to the Big Sandy Plant, Unit 2 FGD project as disallowed by the KPSC.  

Muskingum River Plant, Unit 5 (Generation & Marketing segment)

In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including the 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant.  Under the modification to the consent decree, we have the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017.  In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, we re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project, which would have extended the useful life of MR5, is remote.  As a result, management completed an impairment analysis and concluded that MR5 was impaired.  Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit.  In the second quarter of 2013, we recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory.  Management expects to retire the plant in 2015.

106




2012

Beckjord Plant, Unit 6, Conesville Plant, Unit 3, Kammer Plant, Units 1-3, Muskingum River Plant, Units 1-4, Sporn Plant, Units 2 and 4 and Picway Plant, Unit 5 (Generation & Marketing segment)

In October 2012, we filed applications with the FERC proposing to terminate the Interconnection Agreement and seeking to complete the corporate separation of OPCo's generation assets.  Based on the intention to terminate the Interconnection Agreement and the FERC filing, we performed an evaluation of the recoverability of generation assets.  As a result, in November 2012, we, using generating unit specific estimated future cash flows, concluded that we had a material impairment of certain Ohio generation assets.  Under a market-based value approach, using level 3 unobservable inputs, we determined that the fair value of these generating units was zero based on the lack of installed environmental control equipment and the nature and condition of these generating units.  In the fourth quarter of 2012, we recorded a pretax impairment of $287 million in Asset Impairments and Other Related Charges on the statement of income related to Beckjord Plant, Unit 6, Conesville Plant, Unit 3, Kammer Plant, Units 1-3, Muskingum River Plant, Units 1-4, Sporn Plant, Units 2 and 4 and Picway Plant, Unit 5 generating units which includes $13 million of related material and supplies inventory.

Turk Plant (Vertically Integrated Utilities segment)

In 2012, SWEPCo recorded a pretax write-off of $13 million in Asset Impairments and Other Related Charges on the statement of income related to unrecoverable construction costs subject to the Texas capital costs cap portion of the Turk Plant.

107



8.  BENEFIT PLANS

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

We sponsor a qualified pension plan and two unfunded nonqualified pension plans.  Substantially all of our employees are covered by the qualified plan or both the qualified and a nonqualified pension plan.  We sponsor OPEB plans to provide health and life insurance benefits for retired employees.

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

Actuarial Assumptions for Benefit Obligations

The weighted-average assumptions as of December 31 of each year used in the measurement of our benefit obligations are shown in the following table:
 
 
Pension Plans
 
 
Other Postretirement
Benefit Plans
Assumptions
 
2014
 
2013
 
 
2014
 
2013
Discount Rate
 
4.00
%
 
4.70
%
 
 
4.00
%
 
4.70
%
Rate of Compensation Increase
 
4.80
%
(a)
4.85
%
(a)
 
NA

 
NA


(a)
Rates are for base pay only.  In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
NA
Not applicable.

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

For 2014, the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with an average increase of 4.8%.

We updated our mortality assumption for the December 31, 2014 benefit obligation measurements based on mortality tables issued by the Society of Actuaries in October 2014. These updates increased our benefit obligations by approximately $128 million for the pension plans and $8 million for the OPEB plans.


108



Actuarial Assumptions for Net Periodic Benefit Costs

The weighted-average assumptions as of January 1 of each year used in the measurement of our benefit costs are shown in the following table:
 
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Discount Rate
 
4.70
%
 
3.95
%
 
4.55
%
 
4.70
%
 
3.95
%
 
4.75
%
Expected Return on Plan Assets
 
6.00
%
 
6.50
%
 
7.25
%
 
6.75
%
 
7.00
%
 
7.25
%
Rate of Compensation Increase
 
4.85
%
 
4.95
%
 
4.85
%
 
NA

 
NA

 
NA


NA
Not applicable.

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

The health care trend rate assumptions as of January 1 of each year used for OPEB plans measurement purposes are shown below:
Health Care Trend Rates
 
2014
 
2013
Initial
 
6.50
%
 
6.75
%
Ultimate
 
5.00
%
 
5.00
%
Year Ultimate Reached
 
2020

 
2020


Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans.  A 1% change in assumed health care cost trend rates would have the following effects:
 
 
1% Increase
 
1% Decrease
 
 
(in millions)
Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost
 
$
4

 
$
(3
)
 
 
 
 
 
Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation
 
77

 
(60
)

Significant Concentrations of Risk within Plan Assets

In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets.  The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits.  The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment.  We monitor the plans to control security diversification and ensure compliance with our investment policy.  As of December 31, 2014, the assets were invested in compliance with all investment limits.  See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details.


109



Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2014 and 2013

The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status as of December 31.  The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.
 
 
Pension Plans
 
Other Postretirement
 Benefit Plans
 
 
2014
 
2013
 
2014
 
2013
Change in Benefit Obligation
 
(in millions)
Benefit Obligation as of January 1,
 
$
4,841

 
$
5,205

 
$
1,456

 
$
1,849

Service Cost
 
72

 
69

 
14

 
23

Interest Cost
 
221

 
203

 
67

 
71

Actuarial (Gain) Loss
 
387

 
(305
)
 
(14
)
 
(395
)
Benefit Payments
 
(296
)
 
(331
)
 
(134
)
 
(140
)
Participant Contributions
 

 

 
42

 
39

Medicare Subsidy
 

 

 
8

 
9

Benefit Obligation as of December 31,
 
$
5,225

 
$
4,841

 
$
1,439

 
$
1,456

 
 
 
 
 
 
 
 
 
Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
 
Fair Value of Plan Assets as of January 1,
 
$
4,711

 
$
4,696

 
$
1,699

 
$
1,568

Actual Gain on Plan Assets
 
474

 
340

 
83

 
208

Company Contributions
 
79

 
6

 
4

 
24

Participant Contributions
 

 

 
42

 
39

Benefit Payments
 
(296
)
 
(331
)
 
(134
)
 
(140
)
Fair Value of Plan Assets as of December 31,
 
$
4,968

 
$
4,711

 
$
1,694

 
$
1,699

 
 
 
 
 
 
 
 
 
Funded (Underfunded) Status as of December 31,
 
$
(257
)
 
$
(130
)
 
$
255

 
$
243


Amounts Recognized on the Balance Sheets as of December 31, 2014 and 2013
 
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
 
December 31,
 
 
2014
 
2013
 
2014
 
2013
 
 
(in millions)
Deferred Charges and Other Noncurrent Assets  Prepaid Benefit Costs
 
$

 
$

 
$
337

 
$
264

Other Current Liabilities  Accrued Short-term Benefit Liability
 
(6
)
 
(7
)
 
(4
)
 
(4
)
Employee Benefits and Pension Obligations  Accrued Long-term Benefit Liability
 
(251
)
 
(123
)
 
(78
)
 
(17
)
Funded (Underfunded) Status
 
$
(257
)
 
$
(130
)
 
$
255

 
$
243



110



Amounts Included in AOCI and Regulatory Assets as of December 31, 2014 and 2013
 
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
 
December 31,
 
 
2014
 
2013
 
2014
 
2013
Components
 
(in millions)
Net Actuarial Loss
 
$
1,612

 
$
1,561

 
$
420

 
$
428

Prior Service Cost (Credit)
 
5

 
8

 
(624
)
 
(693
)
 
 
 
 
 
 
 
 
 
Recorded as
 
 
 
 
 
 
 
 
Regulatory Assets
 
$
1,418

 
$
1,343

 
$
(149
)
 
$
(191
)
Deferred Income Taxes
 
70

 
79

 
(19
)
 
(26
)
Net of Tax AOCI
 
129

 
147

 
(36
)
 
(48
)

Components of the change in amounts included in AOCI and Regulatory Assets during the years ended December 31, 2014 and 2013 are as follows:
 
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2014
 
2013
Components
 
(in millions)
Actuarial (Gain) Loss During the Year
 
$
175

 
$
(367
)
 
$
14

 
$
(496
)
Amortization of Actuarial Loss
 
(124
)
 
(183
)
 
(22
)
 
(65
)
Amortization of Prior Service Credit (Cost)
 
(3
)
 
(3
)
 
69

 
69

Change for the Year
 
$
48

 
$
(553
)
 
$
61

 
$
(492
)


111



Pension and Other Postretirement Benefits Plans’ Assets

The following table presents the classification of pension plan assets within the fair value hierarchy as of December 31, 2014:
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Year End
Allocation
 
 
(in millions)
 
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
589

 
$

 
$

 
$

 
$
589

 
11.9
 %
International
 
502

 

 

 

 
502

 
10.1
 %
Options
 

 
14

 

 

 
14

 
0.3
 %
Real Estate Investment Trusts
 
54

 

 

 

 
54

 
1.1
 %
Common Collective Trust  Global
 

 
377

 

 

 
377

 
7.6
 %
Common Collective Trust  International
 

 
19

 

 

 
19

 
0.4
 %
Subtotal  Equities
 
1,145

 
410

 

 

 
1,555

 
31.4
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust  Debt
 

 
30

 

 

 
30

 
0.6
 %
United States Government and Agency Securities
 

 
450

 

 

 
450

 
9.0
 %
Corporate Debt
 

 
1,799

 

 

 
1,799

 
36.2
 %
Foreign Debt
 

 
401

 

 

 
401

 
8.1
 %
State and Local Government
 

 
15

 

 

 
15

 
0.3
 %
Other  Asset Backed
 

 
29

 

 

 
29

 
0.6
  %
Subtotal  Fixed Income
 

 
2,724

 

 

 
2,724

 
54.8
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
Infrastructure
 

 

 
13

 

 
13

 
0.3
 %
Real Estate
 

 

 
236

 

 
236

 
4.7
 %
Alternative Investments
 

 

 
379

 

 
379

 
7.6
 %
Securities Lending
 

 
220

 

 

 
220

 
4.4
 %
Securities Lending Collateral (a)
 

 

 

 
(222
)
 
(222
)
 
(4.5
)%
Cash and Cash Equivalents
 

 
53

 

 

 
53

 
1.1
 %
Other  Pending Transactions and Accrued Income (b)
 

 

 

 
10

 
10

 
0.2
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
1,145

 
$
3,407

 
$
628

 
$
(212
)
 
$
4,968

 
100.0
  %

(a)
Amounts in "Other" column primarily represent an obligation to repay collateral received as part of the Securities Lending Program.
(b)
Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

The following table sets forth a reconciliation of changes in the fair value of assets classified as Level 3 in the fair value hierarchy for the pension assets:
 
 
Infrastructure
 
Real
Estate
 
Alternative
Investments
 
Total
Level 3
 
 
(in millions)
Balance as of January 1, 2014
 
$

 
$
238

 
$
330

 
$
568

Actual Return on Plan Assets
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 

 
6

 
32

 
38

Relating to Assets Sold During the Period
 

 
19

 
16

 
35

Purchases and Sales
 
13

 
(27
)
 
1

 
(13
)
Transfers into Level 3
 

 

 

 

Transfers out of Level 3
 

 

 

 

Balance as of December 31, 2014
 
$
13

 
$
236

 
$
379

 
$
628



112



The following table presents the classification of OPEB plan assets within the fair value hierarchy as of December 31, 2014:
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Year End
Allocation
 
 
(in millions)
 
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
466

 
$

 
$

 
$

 
$
466

 
27.5
%
International
 
567

 

 

 

 
567

 
33.5
%
Options
 

 
16

 

 

 
16

 
1.0
%
Common Collective Trust  Global
 

 
30

 

 

 
30

 
1.8
%
Subtotal  Equities
 
1,033

 
46

 

 

 
1,079

 
63.8
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust  Debt
 

 
104

 

 

 
104

 
6.1
%
United States Government and Agency Securities
 

 
71

 

 

 
71

 
4.2
%
Corporate Debt
 

 
125

 

 

 
125

 
7.4
%
Foreign Debt
 

 
21

 

 

 
21

 
1.3
%
State and Local Government
 

 
6

 

 

 
6

 
0.3
%
Other  Asset Backed
 

 
5

 

 

 
5

 
0.3
%
Subtotal  Fixed Income
 

 
332

 

 

 
332

 
19.6
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 

 
10

 

 

 
10

 
0.6
%
United States Bonds
 

 
212

 

 

 
212

 
12.5
%
Subtotal  Trust Owned Life Insurance
 

 
222

 

 

 
222

 
13.1
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
47

 
10

 

 

 
57

 
3.3
%
Other  Pending Transactions and Accrued Income (a)
 

 

 

 
4

 
4

 
0.2
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
1,080

 
$
610

 
$

 
$
4

 
$
1,694

 
100.0
%

(a)
Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.


113



The following table presents the classification of pension plan assets within the fair value hierarchy as of December 31, 2013:
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Year End
Allocation
 
 
(in millions)
 
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
1,092

 
$

 
$

 
$

 
$
1,092

 
23.2
 %
International
 
514

 

 

 

 
514

 
10.9
 %
Real Estate Investment Trusts
 
58

 

 

 

 
58

 
1.2
 %
Common Collective Trust  International
 

 
10

 

 

 
10

 
0.2
 %
Subtotal  Equities
 
1,664

 
10

 

 

 
1,674

 
35.5
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust  Debt
 

 
26

 

 

 
26

 
0.5
 %
United States Government and Agency Securities
 

 
387

 

 

 
387

 
8.2
 %
Corporate Debt
 

 
1,600

 

 

 
1,600

 
34.0
 %
Foreign Debt
 

 
344

 

 

 
344

 
7.3
 %
State and Local Government
 

 
28

 

 

 
28

 
0.6
 %
Other  Asset Backed
 

 
33

 

 

 
33

 
0.7
  %
Subtotal  Fixed Income
 

 
2,418

 

 

 
2,418

 
51.3
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 

 

 
238

 

 
238

 
5.0
 %
Alternative Investments
 

 

 
330

 

 
330

 
7.0
 %
Securities Lending
 

 
35

 

 

 
35

 
0.8
 %
Securities Lending Collateral (a)
 

 

 

 
(45
)
 
(45
)
 
(0.9
)%
Cash and Cash Equivalents
 

 
48

 

 

 
48

 
1.0
 %
Other  Pending Transactions and Accrued Income (b)
 

 

 

 
13

 
13

 
0.3
  %
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
1,664

 
$
2,511

 
$
568

 
$
(32
)
 
$
4,711

 
100.0
  %

(a)
Amounts in "Other" column primarily represent an obligation to repay collateral received as part of the Securities Lending Program.
(b)
Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

The following table sets forth a reconciliation of changes in the fair value of assets classified as Level 3 in the fair value hierarchy for the pension assets:
 
 
Real
Estate
 
Alternative
Investments
 
Total
Level 3
 
 
(in millions)
Balance as of January 1, 2013
 
$
220

 
$
195

 
$
415

Actual Return on Plan Assets
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
26

 
15

 
41

Relating to Assets Sold During the Period
 

 
15

 
15

Purchases and Sales
 
(8
)
 
105

 
97

Transfers into Level 3
 

 

 

Transfers out of Level 3
 

 

 

Balance as of December 31, 2013
 
$
238

 
$
330

 
$
568



114



The following table presents the classification of OPEB plan assets within the fair value hierarchy as of December 31, 2013:
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Year End
Allocation
 
 
(in millions)
 
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
473

 
$

 
$

 
$

 
$
473

 
27.9
%
International
 
616

 

 

 

 
616

 
36.2
%
Common Collective Trust  Global
 

 
15

 

 

 
15

 
0.9
%
Subtotal  Equities
 
1,089

 
15

 

 

 
1,104

 
65.0
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust  Debt
 

 
88

 

 

 
88

 
5.2
%
United States Government and Agency Securities
 

 
56

 

 

 
56

 
3.3
%
Corporate Debt
 

 
110

 

 

 
110

 
6.5
%
Foreign Debt
 

 
22

 

 

 
22

 
1.2
%
State and Local Government
 

 
5

 

 

 
5

 
0.3
%
Other  Asset Backed
 

 
8

 

 

 
8

 
0.5
%
Subtotal  Fixed Income
 

 
289

 

 

 
289

 
17.0
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 

 
13

 

 

 
13

 
0.8
%
United States Bonds
 

 
211

 

 

 
211

 
12.4
%
Subtotal  Trust Owned Life Insurance
 

 
224

 

 

 
224

 
13.2
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
68

 
9

 

 

 
77

 
4.5
%
Other  Pending Transactions and Accrued Income (a)
 

 

 

 
5

 
5

 
0.3
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
1,157

 
$
537

 
$

 
$
5

 
$
1,699

 
100.0
%

(a)
Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

Determination of Pension Expense

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

The accumulated benefit obligation for the pension plans is as follows:
 
 
December 31,
Accumulated Benefit Obligation
 
2014
 
2013
 
 
(in millions)
Qualified Pension Plan
 
$
4,982

 
$
4,638

Nonqualified Pension Plans
 
76

 
77

Total
 
$
5,058

 
$
4,715



115



For our underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans as of December 31, 2014 and 2013 were as follows:
 
 
Underfunded Pension Plans
 
 
December 31,
 
 
2014
 
2013
 
 
(in millions)
Projected Benefit Obligation
 
$
5,225

 
$
4,841

 
 
 
 
 
Accumulated Benefit Obligation
 
$
5,058

 
$
4,715

Fair Value of Plan Assets
 
4,968

 
4,711

Underfunded Accumulated Benefit Obligation
 
$
(90
)
 
$
(4
)

Estimated Future Benefit Payments and Contributions

We expect contributions and payments for the pension plans of $93 million and the OPEB plans of $6 million during 2015.  For the pension plans, this amount includes the payment of unfunded nonqualified benefits plus contributions to the qualified trust fund of at least the minimum amount required by the Employee Retirement Income Security Act.  For the qualified pension plan, we may also make additional discretionary contributions to maintain the funded status of the plan.  For the OPEB plans, expected payments include the payment of unfunded benefits.

The table below reflects the total benefits expected to be paid from the plan or from our assets.  The payments include the participants’ contributions to the plan for their share of the cost.  Effective for employees hired after December 2013, we will not provide retiree medical coverage.  Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results.  The estimated payments for pension benefits and OPEB are as follows:
 
 
Pension Plans
 
Other Postretirement Benefit Plans
 
 
Pension
Payments
 
Benefit
Payments
 
Medicare Subsidy
Receipts
 
 
(in millions)
2015
 
$
315

 
$
129

 
$

2016
 
323

 
129

 

2017
 
334

 
130

 

2018
 
341

 
132

 

2019
 
350

 
132

 

Years 2020 to 2024, in Total
 
1,822

 
688

 
2



116



Components of Net Periodic Benefit Cost

The following table provides the components of our net periodic benefit cost (credit) for the plans for the years ended December 31, 2014, 2013 and 2012:
 
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
 
 
(in millions)
Service Cost
 
$
72

 
$
69

 
$
76

 
$
14

 
$
23

 
$
47

Interest Cost
 
221

 
203

 
223

 
67

 
71

 
103

Expected Return on Plan Assets
 
(262
)
 
(278
)
 
(319
)
 
(111
)
 
(107
)
 
(101
)
Amortization of Transition Obligation
 

 

 

 

 

 
1

Amortization of Prior Service Cost (Credit)
 
3

 
3

 
(1
)
 
(69
)
 
(69
)
 
(18
)
Amortization of Net Actuarial Loss
 
124

 
183

 
155

 
22

 
65

 
57

Net Periodic Benefit Cost (Credit)
 
158

 
180

 
134

 
(77
)
 
(17
)
 
89

Capitalized Portion
 
(52
)
 
(56
)
 
(42
)
 
25

 
5

 
(28
)
Net Periodic Benefit Cost (Credit) Recognized in Expense
 
$
106

 
$
124

 
$
92

 
$
(52
)
 
$
(12
)
 
$
61


Estimated amounts expected to be amortized to net periodic benefit costs (credits) and the impact on the balance sheet during 2015 are shown in the following table:
 
 
Pension Plans
 
Other
Postretirement
Benefit Plans
Components
 
(in millions)
Net Actuarial Loss
 
$
108

 
$
17

Prior Service Cost (Credit)
 
2

 
(69
)
Total Estimated 2015 Amortization
 
$
110

 
$
(52
)
 
 
 
 
 
Expected to be Recorded as
 
 
 
 
Regulatory Asset
 
$
94

 
$
(38
)
Deferred Income Taxes
 
6

 
(5
)
Net of Tax AOCI
 
10

 
(9
)
Total
 
$
110

 
$
(52
)

American Electric Power System Retirement Savings Plan

We sponsor the American Electric Power System Retirement Savings Plan, a defined contribution retirement savings plan for substantially all employees who are not covered by a retirement savings plan of the United Mine Workers of America (UMWA).  It is a qualified plan offering participants an opportunity to contribute a portion of their pay with features under Section 401(k) of the Internal Revenue Code.  The matching contributions to the plan are 100% of the first 1% of eligible employee contributions and 70% of the next 5% of contributions.  The cost for matching contributions totaled $70 million in 2014, $67 million in 2013 and $66 million in 2012.

UMWA Benefits

We provide UMWA pension, health and welfare benefits for certain unionized employees, retirees and their survivors who meet eligibility requirements.  UMWA trustees make final interpretive determinations with regard to all benefits.  The pension benefits are administered by UMWA trustees and contributions are made to their trust funds.  The health and welfare benefits are administered by us and benefits are paid from our general assets.


117



The UMWA pension benefits are administered through a multiemployer plan that is different from single-employer plans as an employer’s contributions may be used to provide benefits to employees of other participating employers.  Required contributions not made by any employer may result in other employers bearing the unfunded plan obligations, while a withdrawing employer may be subject to a withdrawal liability.  UMWA pension benefits are provided through the United Mine Workers of America 1974 Pension Plan (Employer Identification Number: 52-1050282, Plan Number 2), which under the Pension Protection Act of 2006 (PPA) was in Critical Status for the plan year ending June 30, 2014 and in Seriously Endangered Status for the plan year ending June 30, 2013, without utilization of extended amortization provisions.  The Plan adopted a funding improvement plan in May 2012, as required under the PPA.

Contributions to the UMWA pension plan in 2014, 2013 and 2012 were made under a collective bargaining agreement that is scheduled to expire December 31, 2017.  We contributed immaterial amounts in 2014, 2013 and 2012 that represent less than 5% of the total contributions in the plan’s latest annual report for the years ended June 30, 2014, 2013 and 2012.  The contributions we made included a surcharge of 5% beginning December 2014 and are scheduled to include a surcharge of 10% beginning July 2015.  There are no minimum contributions for future years.

Based upon the plan to retrofit the Rockport Plant with dry sorbent injection technology to meet environmental emission control requirements and the timing of the closure of Cook Coal Terminal expected to be in or after 2025, we recorded a UWMA withdrawal liability in 2013.  The withdrawal liability regulatory asset recorded on the balance sheet should be recovered in future billings for transloading services before the planned closure. As of December 31, 2014 and 2013, the regulatory asset balance was $25 million and $27 million, respectively.

118



9.  BUSINESS SEGMENTS

Our primary business is the generation, transmission and distribution of electricity.  Within our Vertically Integrated Utilities segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

Our reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
OPCo purchases energy to serve SSO customers, and provides capacity for all connected load.

AEP Transmission Holdco

Development, construction and operation of transmission facilities through investments in our wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.

Generation & Marketing

Nonregulated generation in ERCOT and PJM.
Marketing, risk management and retail activities in ERCOT, PJM and MISO.

AEP River Operations

Commercial barging operations that transports liquids, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.

The remainder of our activities is presented as Corporate and Other.  While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries.  This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.


119



The tables below present our reportable segment income statement information for the years ended December 31, 2014, 2013 and 2012 and reportable segment balance sheet information as of December 31, 2014 and 2013.  These amounts include certain estimates and allocations where necessary.
 
 
Vertically Integrated Utilities
 
Transmission and Distribution Utilities
 
AEP Transmission Holdco
 
Generation & Marketing
 
AEP River Operations
 
Corporate and Other(a)
 
Reconciling Adjustments
 
Consolidated
 
 
(in millions)
Year Ended December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
9,397

(b)
$
4,553

 
$
74

 
$
2,384

(b)
$
642

 
$
22

 
$
(52
)
(c)
$
17,020

Other Operating Segments
 
87

(b)
261

 
118

 
1,466

(b)
58

 
73

 
(2,063
)
 

Total Revenues
 
$
9,484

 
$
4,814

 
$
192

 
$
3,850

 
$
700

 
$
95

 
$
(2,115
)
 
$
17,020

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
1,033

 
658

 
24

 
227

 
31

 

 
(44
)
(d)
1,929

Interest and Investment Income
 
4

 
11

 

 
5

 

 
7

 
(20
)
 
7

Carrying Costs Income
 
6

 
27

 

 

 

 

 

 
33

Interest Expense
 
526

 
280

 
23

 
46

 
17

 
26

 
(33
)
(d)
885

Income Tax Expense
 
434

 
211

 
63

 
179

 
40

 
15

 

 
942

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income
 
712

 
355

 
151

 
367

 
49

 
4

 

 
1,638

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross Property Additions
 
2,055

 
1,038

 
948

 
165

 
4

 
17

 
(28
)
 
4,199


120



 
 
Vertically Integrated Utilities
 
Transmission and Distribution Utilities
 
AEP Transmission Holdco
 
Generation & Marketing
 
AEP River Operations
 
Corporate and Other(a)
 
Reconciling Adjustments
 
Consolidated
 
 
(in millions)
Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
9,347

 
$
4,279

 
$
27

 
$
1,208

 
$
544

 
$
32

 
$
(80
)
(c)
$
15,357

Other Operating Segments
 
645

 
199

 
51

 
2,457

 
19

 
57

 
(3,428
)
 

Total Revenues
 
$
9,992

 
$
4,478

 
$
78

 
$
3,665

 
$
563

 
$
89

 
$
(3,508
)
 
$
15,357

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset Impairments and Other Related Charges
 
$
72

 
$

 
$

 
$
154

 
$

 
$

 
$

 
$
226

Depreciation and Amortization
 
941

 
591

 
10

 
236

 
31

 

 
(66
)
(d)
1,743

Interest and Investment Income
 
7

 
2

 

 
2

 

 
69

 
(22
)
 
58

Carrying Costs Income
 
14

 
16

 

 

 

 

 

 
30

Interest Expense
 
540

 
292

 
10

 
55

 
17

 
27

 
(35
)
(d)
906

Income Tax Expense (Credit)
 
398

 
198

 
29

 
112

 
7

 
(60
)
 

 
684

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income
 
681

 
358

 
80

 
228

 
12

 
125

 

 
1,484

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross Property Additions
 
1,822

 
871

 
843

 
185

 
7

 
9

 
(81
)
 
3,656


121



 
 
Vertically Integrated Utilities
 
Transmission and Distribution Utilities
 
AEP Transmission Holdco
 
Generation & Marketing
 
AEP River Operations
 
Corporate and Other(a)
 
Reconciling Adjustments
 
Consolidated
 
 
(in millions)
Year Ended December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
8,785

 
$
4,659

 
$
7

 
$
882

 
$
647

 
$
25

 
$
(60
)
(c)
$
14,945

Other Operating Segments
 
633

 
159

 
17

 
2,585

 
20

 
58

 
(3,472
)
 

Total Revenues
 
$
9,418

 
$
4,818

 
$
24

 
$
3,467

 
$
667

 
$
83

 
$
(3,532
)
 
$
14,945

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset Impairments and Other Related Charges
 
$
13

 
$

 
$

 
$
287

 
$

 
$

 
$

 
$
300

Depreciation and Amortization
 
873

 
561

 
3

 
349

 
29

 

 
(33
)
(d)
1,782

Interest and Investment Income
 
5

 
4

 

 
1

 

 
22

 
(24
)
 
8

Carrying Costs Income
 
28

 
24

 
1

 

 

 

 

 
53

Interest Expense
 
520

 
291

 
3

 
83

 
17

 
112

 
(38
)
(d)
988

Income Tax Expense
 
345

 
201

 
17

 
15

 
7

 
19

 

 
604

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
803

 
389

 
43

 
100

 
15

 
(88
)
 

 
1,262

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross Property Additions
 
1,801

 
664

 
392

 
249

 
31

 
2

 
(20
)
 
3,119

 
 
Vertically Integrated Utilities
 
Transmission and Distribution Utilities
 
AEP Transmission Holdco
 
Generation & Marketing
 
AEP River Operations
 
Corporate and Other(a)
 
Reconciling Adjustments
 
Consolidated
 
 
(in millions)
December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
 
$
39,402

 
$
13,024

 
$
2,714

 
$
8,394

 
$
700

 
$
343

 
$
(272
)
(d)
$
64,305

Accumulated Depreciation and Amortization
 
12,773

 
3,481

 
25

 
3,603

 
217

 
188

 
(99
)
(d)
20,188

Total Property, Plant and Equipment  Net
 
$
26,629

 
$
9,543

 
$
2,689

 
$
4,791

 
$
483

 
$
155

 
$
(173
)
(d)
$
44,117

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
33,750

 
$
14,495

 
$
3,575

 
$
6,329

 
$
749

 
$
21,081

 
$
(20,346
)
(d) (e)
$
59,633

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Investments in Equity Method Investees
 
26

 
1

 
548

 

 
58

 
15

 

 
648

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt Due Within One Year:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliated
 
$
111

 
$

 
$

 
$
86

 
$

 
$

 
$
(197
)
 
$

Non-Affiliated
 
1,352

 
405

 

 
740

 
3

 
3

 

 
2,503

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliated
 
20

 

 

 
32

 

 

 
(52
)
 

Non-Affiliated
 
8,634

 
5,256

 
1,153

 
217

 
80

 
841

 

 
16,181

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Long-term Debt
 
$
10,117

 
$
5,661

 
$
1,153

 
$
1,075

 
$
83

 
$
844

 
$
(249
)
 
$
18,684


122



 
 
Vertically Integrated Utilities
 
Transmission and Distribution Utilities
 
AEP Transmission Holdco
 
Generation & Marketing
 
AEP River Operations
 
Corporate and Other(a)
 
Reconciling Adjustments
 
Consolidated
 
 
(in millions)
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
 
$
37,545

 
$
12,143

 
$
1,636

 
$
8,277

 
$
638

 
$
315

 
$
(269
)
(d)
$
60,285

Accumulated Depreciation and Amortization
 
12,250

 
3,342

 
10

 
3,409

 
189

 
173

 
(85
)
(d)
19,288

Total Property, Plant and Equipment  Net
 
$
25,295

 
$
8,801

 
$
1,626

 
$
4,868

 
$
449

 
$
142

 
$
(184
)
(d)
$
40,997

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
32,791

 
$
14,165

 
$
2,245

 
$
6,426

 
$
673

 
$
19,645

 
$
(19,531
)
(d) (e)
$
56,414

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Investments in Equity Method Investees
 
24

 

 
480

 

 
54

 
11

 

 
569

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt Due Within One Year:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliated
 
$

 
$

 
$

 
$
179

 
$
5

 
$

 
$
(184
)
 
$

Non-Affiliated
 
720

 
697

 

 
126

 
2

 
4

 

 
1,549

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliated
 
151

 

 

 
118

 
10

 

 
(279
)
 

Non-Affiliated
 
9,265

 
5,360

 
620

 
664

 
83

 
836

 

 
16,828

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Long-term Debt
 
$
10,136

 
$
6,057

 
$
620

 
$
1,087

 
$
100

 
$
840

 
$
(463
)
 
$
18,377


(a)
Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
(b)
Includes the impact of the corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014.
(c)
Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio.
(d)
Includes eliminations due to an intercompany capital lease.
(e)
Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies.

123



10.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

We are exposed to certain market risks as a major power producer and marketer of wholesale electricity, natural gas, coal and emission allowances.  These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.  We manage these risks using derivative instruments.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

Our strategy surrounding the use of derivative instruments primarily focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  Our risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact.  To accomplish our objectives, we primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options.  Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.”  Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

We enter into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with our energy business.  We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio.  For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities.  We also engage in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies.  For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.”  The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.

The following table represents the gross notional volume of our outstanding derivative contracts as of December 31, 2014 and 2013:

Notional Volume of Derivative Instruments
 
 
Volume
 
 
 
 
December 31,
 
Unit of
Primary Risk Exposure
 
2014
 
2013
 
Measure
 
 
(in millions)
 
 
Commodity:
 
 
 
 
 
 
Power
 
334

 
406

 
MWhs
Coal
 
3

 
4

 
Tons
Natural Gas
 
106

 
127

 
MMBtus
Heating Oil and Gasoline
 
6

 
6

 
Gallons
Interest Rate
 
$
152

 
$
191

 
USD
 
 
 
 
 
 
 
Interest Rate and Foreign Currency
 
$
815

 
$
820

 
USD


124



Fair Value Hedging Strategies

We enter into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt.  Certain interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate.  Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.

Cash Flow Hedging Strategies

We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. We monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect profit margins for a portion of future electricity sales and energy purchases. We do not hedge all commodity price risk.

Our vehicle fleet and barge operations are exposed to gasoline and diesel fuel price volatility. We enter into financial heating oil and gasoline derivative contracts in order to mitigate price risk of our future fuel purchases. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014. During the year ended December 31, 2013, we designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. We do not hedge all fuel price risk.

We enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate. We also enter into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. Our forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure.

At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers. In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. We do not hedge all foreign currency exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS

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

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

125




According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the December 31, 2014 and 2013 balance sheets, we netted $4 million and $4 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $35 million and $13 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

The following tables represent the gross fair value impact of our derivative activity on the balance sheets as of December 31, 2014 and 2013:

Fair Value of Derivative Instruments
December 31, 2014
 
 
Risk Management
Contracts
 
Hedging Contracts
 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Interest Rate
and Foreign
Currency (a)
 
 
 
 
 
(in millions)
Current Risk Management Assets
 
$
392

 
$
30

 
$
3

 
$
425

 
$
(247
)
 
$
178

Long-term Risk Management Assets
 
367

 
3

 

 
370

 
(76
)
 
294

Total Assets
 
759

 
33

 
3

 
795

 
(323
)
 
472

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
329

 
23

 
1

 
353

 
(261
)
 
92

Long-term Risk Management Liabilities
 
208

 
8

 
9

 
225

 
(94
)
 
131

Total Liabilities
 
537

 
31

 
10

 
578

 
(355
)
 
223

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
222

 
$
2

 
$
(7
)
 
$
217

 
$
32

 
$
249


Fair Value of Derivative Instruments
December 31, 2013
 
 
Risk Management
Contracts
 
Hedging Contracts
 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Interest Rate
and Foreign
Currency (a)
 
 
 
 
 
(in millions)
Current Risk Management Assets
 
$
347

 
$
12

 
$
4

 
$
363

 
$
(203
)
 
$
160

Long-term Risk Management Assets
 
368

 
3

 

 
371

 
(74
)
 
297

Total Assets
 
715

 
15

 
4

 
734

 
(277
)
 
457

 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
292

 
11

 
1

 
304

 
(214
)
 
90

Long-term Risk Management Liabilities
 
237

 
3

 
15

 
255

 
(78
)
 
177

Total Liabilities
 
529

 
14

 
16

 
559

 
(292
)
 
267

 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 Assets (Liabilities)
 
$
186

 
$
1

 
$
(12
)
 
$
175

 
$
15

 
$
190


(a)
Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."
(b)
Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."  Amounts also include de-designated risk management contracts.
(c)
There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
 

126



The table below presents our activity of derivative risk management contracts for the years ended December 31, 2014, 2013 and 2012:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
 
 
Years Ended December 31,
Location of Gain (Loss)
 
2014
 
2013
 
2012
 
 
(in millions)
Vertically Integrated Utilities Revenues
 
$
35

 
$
15

 
$
10

Generation & Marketing Revenues
 
53

 
49

 
50

Regulatory Assets (a)
 
(11
)
 
(2
)
 
(43
)
Regulatory Liabilities (a)
 
193

 
(5
)
 
8

Total Gain on Risk Management Contracts
 
$
270

 
$
57

 
$
25


(a)
Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
   
Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.”  Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.

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

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

Accounting for Fair Value Hedging Strategies

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change.

We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income.  The following table shows the results of our hedging gains (losses) during 2014, 2013, and 2012:
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(in millions)
Gain (Loss) on Fair Value Hedging Instruments
$
4

 
$
(10
)
 
$

(a)
Gain (Loss) on Fair Value Portion of Long-term Debt
(4
)
 
10

 

(a)

(a)
The fair value changes were immaterial.

For 2014, 2013 and 2012, hedge ineffectiveness was immaterial.


127



Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income.  We recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).
 
Realized gains and losses on derivative contracts for the purchase and sale of power and natural gas designated as cash flow hedges are included in Revenues or Purchased Electricity for Resale on the statements of income, or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged.  During 2014, 2013 and 2012, we designated power and natural gas derivatives as cash flow hedges.

We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income.  During 2013 and 2012, we designated heating oil and gasoline derivatives as cash flow hedges. The impact of cash flow hedge accounting for these derivative contracts was immaterial and was discontinued effective March 31, 2014.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur.  During 2014, 2013 and 2012, we designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.  During 2014 and 2013, we did not designate any foreign currency derivatives as cash flow hedges.  During 2012, we designated foreign currency derivatives as cash flow hedges.

During 2014, 2013 and 2012, hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies disclosed above.

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges for the years ended December 31, 2014, 2013 and 2012, see Note 3.


128



Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets as of December 31, 2014 and 2013 were:
Impact of Cash Flow Hedges on the Balance Sheet
December 31, 2014
 
 
 
 
 
 
 
Commodity
 
Interest Rate
and Foreign
Currency
 
Total
 
(in millions)
Hedging Assets (a)
$
16

 
$

 
$
16

Hedging Liabilities (a)
14

 
1

 
15

AOCI Gain (Loss) Net of Tax
1

 
(19
)
 
(18
)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months
4

 
(2
)
 
2

Impact of Cash Flow Hedges on the Balance Sheet
December 31, 2013
 
 
 
 
 
 
 
Commodity
 
Interest Rate
and Foreign
Currency
 
Total
 
(in millions)
Hedging Assets (a)
$
7

 
$

 
$
7

Hedging Liabilities (a)
6

 
2

 
8

AOCI Loss Net of Tax

 
(23
)
 
(23
)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months

 
(4
)
 
(4
)

(a)
Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
  
The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.  As of December 31, 2014, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions was 72 months.

Credit Risk

We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  We use Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

When we use standardized master agreements, these agreements may include collateral requirements.  These master agreements facilitate the netting of cash flows associated with a single counterparty.  Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk.  The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold.  The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy.  In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.


129



Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs), a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, and guaranties for contractual obligations, we are obligated to post an additional amount of collateral if our credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and our total exposure. On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP and its subsidiaries have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. The following table represents our exposure if our credit ratings were to decline below a specified rating threshold as of December 31, 2014 and 2013:
 
 
December 31,
 
 
2014
 
2013
 
 
(in millions)
Fair Value of Contracts with Credit Downgrade Triggers
 
$

 
$
3

Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement
 

 

Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs
 
36

 
28

Amount of Collateral Attributable to Other Contracts (a)
 
281

 
5


(a)
Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.

In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million.  On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts.  The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of December 31, 2014 and 2013:
 
December 31,
 
2014
 
2013
 
(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements
$
235

 
$
293

Amount of Cash Collateral Posted
9

 
1

Additional Settlement Liability if Cross Default Provision is Triggered
178

 
235


130



11.  FAIR VALUE MEASUREMENTS

Fair Value Measurements of Long-term Debt

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

The book values and fair values of Long-term Debt as of December 31, 2014 and 2013 are summarized in the following table:
 
December 31,
 
2014
 
2013
 
Book Value
 
Fair Value
 
Book Value
 
Fair Value
 
(in millions)
Long-term Debt
$
18,684

 
$
21,075

 
$
18,377

 
$
19,672


Fair Value Measurements of Other Temporary Investments

Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that we intend to hold for less than one year and investments by our protected cell of EIS.  See “Other Temporary Investments” section of Note 1.

The following is a summary of Other Temporary Investments:
 
 
December 31, 2014
Other Temporary Investments
 
Cost
 
Gross
Unrealized
Gains
 
Gross
Unrealized Losses
 
Estimated Fair
Value
 
 
(in millions)
Restricted Cash (a)
 
$
280

 
$

 
$

 
$
280

Fixed Income Securities – Mutual Funds
 
81

 

 

 
81

Equity Securities  Mutual Funds
 
13

 
12

 

 
25

Total Other Temporary Investments
 
$
374

 
$
12

 
$

 
$
386

 
 
December 31, 2013
Other Temporary Investments
 
Cost
 
Gross
Unrealized
Gains
 
Gross
Unrealized Losses
 
Estimated Fair
Value
 
 
(in millions)
Restricted Cash (a)
 
$
250

 
$

 
$

 
$
250

Fixed Income Securities – Mutual Funds
 
80

 

 

 
80

Equity Securities  Mutual Funds
 
12

 
11

 

 
23

Total Other Temporary Investments
 
$
342

 
$
11

 
$

 
$
353


(a)
Primarily represents amounts held for the repayment of debt.


131



The following table provides the activity for our fixed income and equity securities within Other Temporary Investments for the years ended December 31, 2014, 2013 and 2012:
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(in millions)
Proceeds from Investment Sales
 
$

 
$

 
$

Purchases of Investments
 
2

 
17

 
2

Gross Realized Gains on Investment Sales
 

 

 

Gross Realized Losses on Investment Sales
 

 

 


As of December 31, 2014 and 2013, we had no Other Temporary Investments with an unrealized loss position.  As of December 31, 2014, fixed income securities were primarily debt based mutual funds with short and intermediate maturities.  Mutual funds may be sold and do not contain maturity dates.

For details of the reasons for changes in securities available for sale included in Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2014 and 2013, see Note 3.

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value.  See “Nuclear Trust Funds” section of Note 1.

The following is a summary of nuclear trust fund investments as of December 31, 2014 and 2013:
 
December 31,
 
2014
 
2013
 
Estimated Fair
Value
 
Gross Unrealized
Gains
 
Other-Than-Temporary
Impairments
 
Estimated Fair
Value
 
Gross Unrealized Gains
 
Other-Than-Temporary
Impairments
 
(in millions)
Cash and Cash Equivalents
$
20

 
$

 
$

 
$
19

 
$

 
$

Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
United States Government
697

 
45

 
(5
)
 
609

 
26

 
(4
)
Corporate Debt
48

 
4

 
(1
)
 
37

 
2

 
(1
)
State and Local Government
208

 
1

 

 
255

 
1

 

Subtotal Fixed Income Securities
953

 
50

 
(6
)
 
901

 
29

 
(5
)
Equity Securities  Domestic
1,123

 
599

 
(79
)
 
1,012

 
506

 
(82
)
 


 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
$
2,096

 
$
649

 
$
(85
)
 
$
1,932

 
$
535

 
$
(87
)

The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2014, 2013 and 2012:
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Proceeds from Investment Sales
$
1,032

 
$
858

 
$
988

Purchases of Investments
1,086

 
910

 
1,045

Gross Realized Gains on Investment Sales
32

 
18

 
25

Gross Realized Losses on Investment Sales
15

 
8

 
9


The adjusted cost of fixed income securities was $903 million and $872 million as of December 31, 2014 and 2013, respectively.  The adjusted cost of equity securities was $524 million and $506 million as of December 31, 2014 and 2013, respectively.


132



The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2014 was as follows:
 
Fair Value of Fixed Income Securities
 
(in millions)
Within 1 year
$
154

1 year – 5 years
376

5 years – 10 years
179

After 10 years
244

Total
$
953


133



Fair Value Measurements of Financial Assets and Liabilities

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

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in our valuation techniques.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in millions)
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
$
17

 
$
1

 
$

 
$
145

 
$
163

 
 
 
 
 
 
 
 
 
 
Other Temporary Investments
 
 
 
 
 
 
 
 
 
Restricted Cash (a)
234

 
9

 

 
37

 
280

Fixed Income Securities – Mutual Funds
81

 

 

 

 
81

Equity Securities – Mutual Funds (b)
25

 

 

 

 
25

Total Other Temporary Investments
340

 
9

 

 
37

 
386

 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (d)
37

 
528

 
190

 
(302
)
 
453

Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)

 
32

 

 
(16
)
 
16

Fair Value Hedges

 
1

 

 
2

 
3

Total Risk Management Assets
37

 
561

 
190

 
(316
)
 
472

 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (f)
9

 

 

 
11

 
20

Fixed Income Securities:
 
 
 
 
 
 
 
 
 
United States Government

 
697

 

 

 
697

Corporate Debt

 
48

 

 

 
48

State and Local Government

 
208

 

 

 
208

Subtotal Fixed Income Securities

 
953

 

 

 
953

Equity Securities – Domestic (b)
1,123

 

 

 

 
1,123

Total Spent Nuclear Fuel and Decommissioning Trusts
1,132

 
953

 

 
11

 
2,096

 
 
 
 
 
 
 
 
 
 
Total Assets
$
1,526

 
$
1,524

 
$
190

 
$
(123
)
 
$
3,117

 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (d)
$
65

 
$
432

 
$
36

 
$
(334
)
 
$
199

Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)

 
27

 
3

 
(16
)
 
14

Interest Rate/Foreign Currency Hedges

 
1

 

 

 
1

Fair Value Hedges

 
7

 

 
2

 
9

Total Risk Management Liabilities
$
65

 
$
467

 
$
39

 
$
(348
)
 
$
223


134



Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in millions)
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
$
16

 
$
1

 
$

 
$
101

 
$
118

 
 
 
 
 
 
 
 
 
 
Other Temporary Investments
 
 
 
 
 
 
 
 
 
Restricted Cash (a)
231

 
8

 

 
11

 
250

Fixed Income Securities – Mutual Funds
80

 

 

 

 
80

Equity Securities – Mutual Funds (b)
23

 

 

 

 
23

Total Other Temporary Investments
334

 
8

 

 
11

 
353

 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (g)
22

 
549

 
142

 
(273
)
 
440

Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)

 
15

 

 
(8
)
 
7

Fair Value Hedges

 
1

 

 
3

 
4

De-designated Risk Management Contracts (e)

 

 

 
6

 
6

Total Risk Management Assets
22

 
565

 
142

 
(272
)
 
457

 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (f)
8

 

 

 
11

 
19

Fixed Income Securities:
 
 
 
 
 
 
 
 
 
United States Government

 
609

 

 

 
609

Corporate Debt

 
37

 

 

 
37

State and Local Government

 
255

 

 

 
255

Subtotal Fixed Income Securities

 
901

 

 

 
901

Equity Securities – Domestic (b)
1,012

 

 

 

 
1,012

Total Spent Nuclear Fuel and Decommissioning Trusts
1,020

 
901

 

 
11

 
1,932

 
 
 
 
 
 
 
 
 
 
Total Assets
$
1,392

 
$
1,475

 
$
142

 
$
(149
)
 
$
2,860

 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (g)
$
30

 
$
475

 
$
22

 
$
(282
)
 
$
245

Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)

 
11

 
3

 
(8
)
 
6

Interest Rate/Foreign Currency Hedges

 
2

 

 

 
2

Fair Value Hedges

 
11

 

 
3

 
14

Total Risk Management Liabilities
$
30

 
$
499

 
$
25

 
$
(287
)
 
$
267


(a)
Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties.  Level 1 and Level 2 amounts primarily represent investments in money market funds.
(b)
Amounts represent publicly traded equity securities and equity-based mutual funds.
(c)
Amounts in "Other" column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for "Derivatives and Hedging."
(d)
The December 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018;  Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030;  Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030.  Risk management commodity contracts are substantially comprised of power contracts.
(e)
Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for "Derivatives and Hedging."  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This MTM value will be amortized into revenues over the remaining life of the contracts.
(f)
Amounts in "Other" column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(g)
The December 31, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $4 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019;   Level 2 matures $25 million in 2014, $37 million in periods 2015-2017, $7 million in periods 2018-2019 and $5 million in periods 2020-2030;  Level 3 matures $27 million in 2014, $60 million in periods 2015-2017, $14 million in periods 2018-2019 and $19 million in periods 2020-2030.  Risk management commodity contracts are substantially comprised of power contracts.

There have been no transfers between Level 1 and Level 2 during the years ended December 31, 2014, 2013 and 2012.
 

135



The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as Level 3 in the fair value hierarchy:
Year Ended December 31, 2014
 
Net Risk Management
Assets (Liabilities)
 
 
(in millions)
Balance as of December 31, 2013
 
$
117

Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
90

Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
6

Purchases, Issuances and Settlements (c)
 
(108
)
Transfers into Level 3 (d) (e)
 
(8
)
Transfers out of Level 3 (e) (f)
 
(21
)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
75

Balance as of December 31, 2014
 
$
151

Year Ended December 31, 2013
 
Net Risk Management
Assets (Liabilities)
 
 
(in millions)
Balance as of December 31, 2012
 
$
86

Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
(9
)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date (a)
 
37

Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
(3
)
Purchases, Issuances and Settlements (c)
 
(16
)
Transfers into Level 3 (d) (e)
 
19

Transfers out of Level 3 (e) (f)
 
(4
)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
7

Balance as of December 31, 2013
 
$
117

Year Ended December 31, 2012
 
Net Risk Management
Assets (Liabilities)
 
 
(in millions)
Balance as of December 31, 2011
 
$
69

Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
(15
)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date (a)
 
29

Purchases, Issuances and Settlements (c)
 
32

Transfers into Level 3 (d) (e)
 
1

Transfers out of Level 3 (e) (f)
 
(35
)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
5

Balance as of December 31, 2012
 
$
86


(a)
Included in revenues on the statements of income.
(b)
Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)
Represents the settlement of risk management commodity contracts for the reporting period.
(d)
Represents existing assets or liabilities that were previously categorized as Level 2.
(e)
Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(f)
Represents existing assets or liabilities that were previously categorized as Level 3.
(g)
Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets.
 

136



The following tables quantify the significant unobservable inputs used in developing the fair value of our Level 3 positions as of December 31, 2014 and 2013:

Significant Unobservable Inputs
December 31, 2014
 
 
 
 
 
Significant
 
Input/Range
 
Fair Value
 
Valuation
 
Unobservable
 
 
 
 
 
Weighted
 
Assets
 
Liabilities
 
Technique
 
Input
 
Low
 
High
 
Average
 
(in millions)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
$
157

 
$
37

 
Discounted Cash Flow
 
Forward Market Price (a)
 
$
11.37

 
$
159.92

 
$
57.18

 
 
 
 
 
 
 
Counterparty Credit Risk (b)
 
303
FTRs
33

 
2

 
Discounted Cash Flow
 
Forward Market Price (a)
 
(14.63
)
 
20.02

 
0.96

Total
$
190

 
$
39

 
 
 
 
 
 
 
 
 
 

Significant Unobservable Inputs
December 31, 2013
 
 
 
 
 
 
 
Significant
 
 
 
 
 
Fair Value
 
Valuation
 
Unobservable
 
Input/Range
 
Assets
 
Liabilities
 
Technique
 
Input
 
Low
 
High
 
(in millions)
 
 
 
 
 
 
 
 
Energy Contracts
$
132

 
$
22

 
Discounted Cash Flow
 
Forward Market Price (a)
 
$
11.42

 
$
120.72

 
 
 
 
 
 
 
Counterparty Credit Risk (b)
 
316
FTRs
10

 
3

 
Discounted Cash Flow
 
Forward Market Price (a)
 
(5.10
)
 
10.44

Total
$
142

 
$
25

 
 
 
 
 
 
 
 

(a)
Represents market prices in dollars per MWh.
(b)
Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.

The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs as of December 31, 2014:

Sensitivity of Fair Value Measurements
December 31, 2014
Significant Unobservable Input
 
Position
 
Change in Input
 
Impact on Fair Value
Measurement
Forward Market Price
 
Buy
 
Increase (Decrease)
 
Higher (Lower)
Forward Market Price
 
Sell
 
Increase (Decrease)
 
Lower (Higher)
Counterparty Credit Risk
 
Loss
 
Increase (Decrease)
 
Higher (Lower)
Counterparty Credit Risk
 
Gain
 
Increase (Decrease)
 
Lower (Higher)


137



12.  INCOME TAXES

The details of our consolidated income taxes as reported are as follows:
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Federal:
 
 
 
 
 
Current
$
51

 
$
(45
)
 
$
(52
)
Deferred
796

 
676

 
698

Total Federal
847

 
631

 
646

 
 
 
 
 
 
State and Local:
 
 
 
 
 
Current
25

 
29

 
35

Deferred
70

 
24

 
(77
)
Total State and Local
95

 
53

 
(42
)
 
 
 
 
 
 
Income Tax Expense
$
942

 
$
684

 
$
604


The following is a reconciliation of our consolidated difference between the amount of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported:
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Net Income
$
1,638
 
 
$
1,484
 
 
$
1,262
 
Income Tax Expense
942
 
 
684
 
 
604
 
Pretax Income
$
2,580
 

$
2,168
 

$
1,866
 
 
 
 
 
 
 
Income Taxes on Pretax Income at Statutory Rate (35%)
$
903
 
 
$
759
 
 
$
653
 
Increase (Decrease) in Income Taxes resulting from the following items:
 
 
 
 
 
Depreciation
54
 
 
47
 
 
39
 
Investment Tax Credits, Net
(13
)
 
(14
)
 
(14
)
State and Local Income Taxes, Net
64
 
 
29
 
 
(33
)
Removal Costs
(24
)
 
(21
)
 
(18
)
AFUDC
(42
)
 
(31
)
 
(39
)
Valuation Allowance
(2
)
 
5
 
 
6
 
U.K. Windfall Tax
 
 
(80
)
 
15
 
Other
2
 
 
(10
)
 
(5
)
Income Tax Expense
$
942
 

$
684
 

$
604
 
 
 
 
 
 
 
Effective Income Tax Rate
36.5

%


31.5

%


32.4

%



138



The following table shows elements of the net deferred tax liability and significant temporary differences:
 
December 31,
 
2014
 
2013
 
(in millions)
Deferred Tax Assets
$
2,653

 
$
2,900

Deferred Tax Liabilities
(13,599
)
 
(13,088
)
Net Deferred Tax Liabilities
$
(10,946
)
 
$
(10,188
)
 
 
 
 
Property Related Temporary Differences
$
(7,968
)
 
$
(7,508
)
Amounts Due from Customers for Future Federal Income Taxes
(255
)
 
(273
)
Deferred State Income Taxes
(811
)
 
(765
)
Securitized Assets
(753
)
 
(870
)
Regulatory Assets
(694
)
 
(609
)
Deferred Income Taxes on Other Comprehensive Loss
60

 
66

Accrued Nuclear Decommissioning
(611
)
 
(554
)
Net Operating Loss Carryforward
47

 
233

Tax Credit Carryforward
144

 
109

Valuation Allowance
(56
)
 
(97
)
All Other, Net
(49
)
 
80

Net Deferred Tax Liabilities
$
(10,946
)
 
$
(10,188
)

AEP System Tax Allocation Agreement

We, along with our subsidiaries, file a consolidated federal income tax return.  The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense.  The tax benefit of the Parent is allocated to our subsidiaries with taxable income.  With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Federal and State Income Tax Audit Status

We are no longer subject to U.S. federal examination for years before 2011.  The IRS examination of years 2011, 2012 and 2013 started in April 2014.  Although the outcome of tax audits is uncertain, in our opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, we accrue interest on these uncertain tax positions.  We are not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.

We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions.  These taxing authorities routinely examine our tax returns and we are currently under examination in several state and local jurisdictions.  However, it is possible that we have filed tax returns with positions that may be challenged by these tax authorities.  We believe that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and the ultimate resolution of these audits will not materially impact net income.  We are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.


139



Net Income Tax Operating Loss Carryforward

In 2012 and 2011, we recognized federal net income tax operating losses of $366 million and $226 million, respectively, driven primarily by bonus depreciation, pension plan contributions and other book-versus-tax temporary differences.  As of December 31, 2013, we had $156 million of unrealized federal net operating loss carryforward tax benefits.  Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full. We recognized deferred state and local income tax benefits in 2012 and 2011. The state net income tax operating loss carryforwards as of December 31, 2014 are indicated in the table below:
State
 
State Net Income
Tax Operating
Loss
Carryforward
 
Year of
Expiration
 
 
(in millions)
 
 
Louisiana
 
$
431

 
2029
Missouri
 
9

 
2034
Oklahoma
 
322

 
2034
Tennessee
 
3

 
2026
West Virginia
 
286

 
2032

We anticipate future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state.

As of December 31, 2013 we had $121 million of uncertain tax positions netted against the federal net income tax operating loss carryforward tax benefits. Due to the utilization of the net operating loss carryforward in 2014, $69 million is presented as a non-current uncertain tax position. As of December 31, 2014, we have $52 million of uncertain tax positions netted against tax credit and alternative minimum tax carryforward tax benefits.

Tax Credit Carryforward

Federal and state net income tax operating losses sustained in 2012, 2011 and 2009, along with lower federal and state taxable income in 2010, resulted in unused federal and state income tax credits.  As of December 31, 2014, we have total federal tax credit carryforwards of $144 million and total state tax credit carryforwards of $22 million, not all of which are subject to an expiration date.  If these credits are not utilized, the federal general business tax credits of $74 million will expire in the years 2028 through 2033.

We anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused.  

In November 2014, APCo received an order from the Virginia SCC for its 2014 Virginia Biennial Base Rate Case (see Note 4). As a result of the final determination pertaining to the ability to realize future tax benefits for certain state net income tax operating loss and credit carryforwards, we determined that APCo is subject to the Virginia Minimum Tax on electric suppliers and the Virginia State Income Tax is no longer applicable. As a result, we derecognized the related state income tax benefits, which had been subject to valuation allowances.

Valuation Allowance

We assess past results and future operations to estimate and evaluate available positive and negative evidence to evaluate whether sufficient future taxable income will be generated to use existing deferred tax assets.  The positive evidence we considered is the history of positive pretax income and the fact that the tax losses resulted from temporary differences that will reverse in future periods.  On the basis of the evaluation of all available positive and negative evidence, as of December 31, 2014, a valuation allowance of $56 million for an unrealized capital loss has been recorded in order to recognize only the portion of the deferred tax assets that, more likely than not, will be realized. The amount of the deferred tax assets realizable, however, could be adjusted if estimates of future taxable income during the carryforward period are materially impacted.

140



Uncertain Tax Positions

In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes.  We filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case.  As a result of the favorable U.S. Supreme Court decision, we recognized a tax benefit of $80 million, plus $43 million of pretax interest income in the second quarter of 2013.  The tax benefit and interest income resulted in an increase in net income of $108 million, but did not result in the receipt of cash as of December 31, 2014. Due to the timing of the IRS audit cycle, receipt of cash is not expected within the next 12 months.

We recognize interest accruals related to uncertain tax positions in interest income or expense, as applicable, and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.”

The following table shows amounts reported for interest expense, interest income and reversal of prior period interest expense:
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Interest Expense
$
3

 
$
1

 
$
11

Interest Income
1

 
51

 

Reversal of Prior Period Interest Expense
2

 

 
1


The following table shows balances for amounts accrued for the receipt of interest and the payment of interest and penalties:
 
December 31,
 
2014
 
2013
 
(in millions)
Accrual for Receipt of Interest
$
44

 
$
43

Accrual for Payment of Interest and Penalties
6

 
5


The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows:
 
2014
 
2013
 
2012
 
(in millions)
Balance as of January 1,
$
175

 
$
267

 
$
168

Increase  Tax Positions Taken During a Prior Period
18

 

 
23

Decrease  Tax Positions Taken During a Prior Period
(1
)
 
(94
)
 
(16
)
Increase  Tax Positions Taken During the Current Year

 
2

 
121

Decrease  Tax Positions Taken During the Current Year

 

 

Decrease  Settlements with Taxing Authorities
(1
)
 

 
(25
)
Decrease  Lapse of the Applicable Statute of Limitations
(9
)
 

 
(4
)
Balance as of December 31,
$
182


$
175


$
267


The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $97 million, $87 million and $149 million for 2014, 2013 and 2012, respectively.  We believe there will be no significant net increase or decrease in unrecognized tax benefits within 12 months of the reporting date.

Federal Tax Legislation

The American Taxpayer Relief Act of 2012 (the 2012 Act) was enacted in January 2013.  Included in the 2012 Act was a one-year extension of 50% bonus depreciation.  The 2012 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2011.  The enacted provisions did not materially impact net income or financial condition but did have a favorable impact on cash flows in 2013.


141



The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact net income or financial condition but will have a favorable impact on future cash flows.

Federal Tax Regulations

In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014.  In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry.  These final regulations did not materially impact net income, cash flows or financial condition.

State Tax Legislation

Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5%.  The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012 with the final reduction occurring in years beginning after June 30, 2015.

In May 2011, Michigan repealed its Business Tax regime and replaced it with a traditional corporate net income tax rate of 6%, effective January 1, 2012.

During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds.  As a result, the West Virginia corporate income tax rate was reduced from 7% to 6.5% in 2014.  

The enacted provisions did not materially impact net income, cash flows or financial condition.

142



13.   LEASES

Leases of property, plant and equipment are for remaining periods up to 35 years and require payments of related property taxes, maintenance and operating costs.  The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.

Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations.  Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period.  Capital leases for nonregulated property are accounted for as if the assets were owned and financed.  The components of rental costs are as follows:
 
 
Years Ended December 31,
Lease Rental Costs
 
2014
 
2013
 
2012
 
 
(in millions)
Net Lease Expense on Operating Leases
 
$
304

 
$
327

 
$
346

Amortization of Capital Leases
 
109

 
74

 
73

Interest on Capital Leases
 
26

 
28

 
29

Total Lease Rental Costs
 
$
439

 
$
429

 
$
448


The following table shows the property, plant and equipment under capital leases and related obligations recorded on the balance sheets.  Capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on the balance sheets.
 
 
December 31,
Property, Plant and Equipment Under Capital Leases
 
2014
 
2013
 
 
(in millions)
Generation
 
$
104

 
$
103

Other Property, Plant and Equipment
 
683

 
627

Total Property, Plant and Equipment Under Capital Leases
 
787

 
730

Accumulated Amortization
 
240

 
197

Net Property, Plant and Equipment Under Capital Leases
 
$
547

 
$
533

 
 
 
 
 
Obligations Under Capital Leases
 
 
 
 
Noncurrent Liability
 
$
441

 
$
428

Liability Due Within One Year
 
111

 
110

Total Obligations Under Capital Leases
 
$
552

 
$
538



143



Future minimum lease payments consisted of the following as of December 31, 2014:
Future Minimum Lease Payments
 
Capital Leases
 
Noncancelable
Operating Leases
 
 
(in millions)
2015
 
$
134

 
$
293

2016
 
120

 
267

2017
 
98

 
253

2018
 
63

 
239

2019
 
46

 
223

Later Years
 
239

 
693

Total Future Minimum Lease Payments
 
700

 
$
1,968

Less Estimated Interest Element
 
148

 
 
Estimated Present Value of Future Minimum Lease Payments
 
$
552

 
 

Master Lease Agreements

We lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, we are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term, the fair value has been in excess of the unamortized balance.  As of December 31, 2014, the maximum potential loss for these lease agreements was approximately $26 million assuming the fair value of the equipment is zero at the end of the lease term.

Rockport Lease

AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant).  The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022.  The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M.  The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note.  The lease term is for 33 years with potential renewal options.  At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant.  AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt.  The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2014 are as follows:
Future Minimum Lease Payments
 
AEGCo
 
I&M
 
 
(in millions)
2015
 
$
74

 
$
74

2016
 
74

 
74

2017
 
74

 
74

2018
 
74

 
74

2019
 
74

 
74

Later Years
 
222

 
222

Total Future Minimum Lease Payments
 
$
592

 
$
592



144



Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignment is accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $11 million and $13 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2014.  These obligations are included in the future minimum lease payments schedule earlier in this note.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 83% of the projected fair value of the equipment under the current five-year lease term to 77% at the end of the 20-year term.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  The maximum potential losses related to the guarantee are approximately $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, we believe that the fair value would produce a sufficient sales price to avoid any loss.

Sabine Dragline Lease

During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million.  The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational.  These capital lease assets are included in Other Property, Plant and Equipment on our December 31, 2014 and 2013 balance sheets.  The short-term and long-term capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on our December 31, 2014 and 2013 balance sheets.  The future payment obligations are included in our future minimum lease payments schedule earlier in this note.

I&M Nuclear Fuel Lease

In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio Trust, to lease nuclear fuel for I&M’s Cook Plant.  In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million.  The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months. The future payment obligations of $67 million are included in our future minimum lease payments schedule earlier in this note.  The net capital lease asset is included in Other Property, Plant and Equipment and the short-term and long-term capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities, respectively, on our December 31, 2014 balance sheet.  The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2014 are as follows, based on estimated fuel burn:
Future Minimum Lease Payments
 
I&M
 
 
(in millions)
2015
 
$
32

2016
 
27

2017
 
6

2018
 
2

Total Future Minimum Lease Payments
 
$
67


145



14.  FINANCING ACTIVITIES

AEP Common Stock

Listed below is a reconciliation of common stock share activity for the years ended December 31, 2014, 2013 and 2012:
Shares of AEP Common Stock
 
Issued
 
Held in
Treasury
Balance, December 31, 2011
 
503,759,460

 
20,336,592

Issued
 
2,245,502

 

Balance, December 31, 2012
 
506,004,962

 
20,336,592

Issued
 
2,109,002

 

Balance, December 31, 2013
 
508,113,964

 
20,336,592

Issued
 
1,625,195

 

Balance, December 31, 2014
 
509,739,159

 
20,336,592



146



Long-term Debt

The following details long-term debt outstanding as of December 31, 2014 and 2013:
 
 
Weighted
 
 
 
 
 
 
Average
 
 
 
 
 
 
Interest
 
 
 
 
 
 
 
 
 
 
Rate as of
 
Interest Rate Ranges as of
 
Outstanding as of
 
 
December 31,
 
December 31,
 
December 31,
Type of Debt and Maturity
 
2014
 
2014
 
2013
 
2014
 
2013
 
 
 
 
 
 
 
 
(in millions)
Senior Unsecured Notes
 
 
 
 
 
 
 
 
 
 
2014-2044
 
5.34%
 
1.65%-8.13%
 
1.65%-8.13%
 
$
12,647

 
$
11,799

 
 
 
 
 
 
 
 
 
 
 
Pollution Control Bonds (a)
 
 
 
 
 
 
 
 
 
 
2014-2038 (b)
 
2.66%
 
0.04%-6.30%
 
0.02%-6.30%
 
1,963

 
1,932

 
 
 
 
 
 
 
 
 
 
 
Notes Payable (c)
 
 
 
 
 
 
 
 
 
 
2014-2032
 
3.84%
 
0.983%-8.03%
 
1.164%-8.03%
 
357

 
369

 
 
 
 
 
 
 
 
 
 
 
Securitization Bonds
 
 
 
 
 
 
 
 
 
 
2015-2031
 
3.69%
 
0.88%-6.25%
 
0.88%-6.25%
 
2,380

 
2,686

 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel Obligation (d)
 
 
 
 
 
 
 
266

 
265

 
 
 
 
 
 
 
 
 
 
 
Other Long-term Debt
 
 
 
 
 
 
 
 
 
 
2015-2059
 
1.67%
 
1.15%-13.718%
 
1.15%-13.718%
 
1,101

 
1,360

 
 
 
 
 
 
 
 
 
 
 
Fair Value of Interest Rate Hedges
 
 
 
 
 
 
 
(6
)
 
(9
)
Unamortized Discount, Net
 
 
 
 
 
 
 
(24
)
 
(25
)
Total Long-term Debt Outstanding
 
 
 
 
 
 
 
18,684

 
18,377

Long-term Debt Due Within One Year
 
 
 
 
 
 
 
2,503

 
1,549

Long-term Debt
 
 
 
 
 
 
 
$
16,181

 
$
16,828


(a)
For certain series of pollution control bonds, interest rates are subject to periodic adjustment.  Certain series may be purchased on demand at periodic interest adjustment dates.  Letters of credit from banks and insurance policies support certain series.
(b)
Certain pollution control bonds are subject to redemption earlier than the maturity date.  Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year on the balance sheets.
(c)
Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions.  At expiration, all notes then issued and outstanding are due and payable.  Interest rates are both fixed and variable.  Variable rates generally relate to specified short-term interest rates.
(d)
Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see "SNF Disposal" section of Note 6).

Long-term debt outstanding as of December 31, 2014 is payable as follows:
 
2015
 
2016
 
2017
 
2018
 
2019
 
After 2019
 
Total
 
(in millions)
Principal Amount
$
2,503

 
$
1,306

 
$
1,871

 
$
1,417

 
$
1,673

 
$
9,938

 
$
18,708

Unamortized Discount, Net
 
 
 
 
 
 
 
 
 
 
 
 
(24
)
Total Long-term Debt Outstanding
 
 
 
 
 
 
 
 
 
 
 
 
$
18,684


In January 2015 and February 2015, I&M retired $15 million and $8 million, respectively, of Notes Payable related to DCC Fuel.

147




In January 2015, OPCo retired $22 million of Securitization Bonds.

In January 2015, PSO issued $87.5 million of 3.17% and $87.5 million of 4.09% Senior Unsecured Notes due in 2025 and 2045, respectively.

In January 2015, SWEPCo remarketed $54 million of 1.6% Pollution Control Bonds due in 2019.

In January 2015, TCC retired $120 million of Securitization Bonds.

In February 2015, APCo retired $11 million of Securitization Bonds.

As of December 31, 2014, trustees held, on our behalf, $385 million of our reacquired Pollution Control Bonds.

Dividend Restrictions

Parent Restrictions

The holders of our common stock are entitled to receive the dividends declared by our Board of Directors provided funds are legally available for such dividends.  Our income derives from our common stock equity in the earnings of our utility subsidiaries.

Pursuant to the leverage restrictions in our credit agreements, we must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.  The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend.  The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements.  None of AEP’s retained earnings were restricted for the purpose of the payment of dividends.

Utility Subsidiaries’ Restrictions

Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.  Specifically, several of our public utility subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%.  As of December 31, 2014, the amount of restricted net assets of AEP’s subsidiaries that may not be distributed to Parent in the form of a loan, advance or dividend was approximately $7 billion.

The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.”  The term “capital account” is not defined in the Federal Power Act or its regulations.  Management understands “capital account” to mean the book value of the common stock.  This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings. 


148



Lines of Credit and Short-term Debt

We use our commercial paper program to meet the short-term borrowing needs of our subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  As of December 31, 2014, we had credit facilities totaling $3.5 billion to support our commercial paper program.  The maximum amount of commercial paper outstanding during 2014 was $877 million and the weighted average interest rate of commercial paper outstanding during 2014 was 0.29%.  Our outstanding short-term debt was as follows:
 
 
December 31,
 
 
2014
 
2013
Type of Debt
 
Outstanding
Amount
 
Interest
Rate (a)
 
Outstanding
Amount
 
Interest
Rate (a)
 
 
(in millions)
 
 
 
(in millions)
 
 
Securitized Debt for Receivables (b)
 
$
744

 
0.22
%
 
$
700

 
0.23
%
Commercial Paper
 
602

 
0.59
%
 
57

 
0.29
%
Total Short-term Debt
 
$
1,346

 
 
 
$
757

 
 

(a)
Weighted average rate.
(b)
Amount of securitized debt for receivables as accounted for under the "Transfers and Servicing" accounting guidance.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 6.

Securitized Accounts Receivable – AEP Credit

AEP Credit has a receivables securitization agreement with bank conduits.  Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries.  AEP Credit continues to service the receivables.  These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables and accelerate AEP Credit’s cash collections.

Our receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables.  The agreement was increased in June 2014 from $700 million and expires in June 2016.

Accounts receivable information for AEP Credit is as follows:
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable
0.22
%
 
0.23
%
 
0.26
%
Net Uncollectible Accounts Receivable Written Off
$
40

 
$
35

 
$
29


149



 
 
December 31,
 
 
2014
 
2013
 
 
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts
 
$
975

 
$
929

Total Principal Outstanding
 
744

 
700

Delinquent Securitized Accounts Receivable
 
44

 
45

Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable
 
13

 
16

Unbilled Receivables Related to Securitization/Sale of Accounts Receivable
 
335

 
331


Customer accounts receivable retained and securitized for our operating companies are managed by AEP Credit.  AEP Credit’s delinquent customer accounts receivable represents accounts greater than 30 days past due.


150



15.  STOCK-BASED COMPENSATION

As approved by shareholder vote, the Amended and Restated American Electric Power System Long-Term Incentive Plan (LTIP) authorizes the use of 20 million shares of AEP common stock for various types of stock-based compensation awards to employees.  A maximum of 10 million shares may be used under this plan for full value share awards, which includes performance units, restricted shares and restricted stock units.  As of December 31, 2014, 15,825,643 shares remained available for issuance under the LTIP plan.  The AEP Board of Directors and shareholders last approved the LTIP in 2010.  The following sections provide further information regarding each type of stock-based compensation award granted by the Human Resources Committee of our Board of Directors (HR Committee).

Stock Options

We did not grant stock options in 2014, 2013 or 2012. We did have outstanding stock options from grants in earlier periods that were exercised in 2013 and 2012.  As of December 31, 2014, we have no outstanding stock options.  We recorded compensation cost for stock options over the vesting period based on the fair value on the grant date.  The LTIP does not specify a maximum contractual term for stock options.

The total intrinsic value of options exercised is as follows:
 
 
Years Ended December 31,
Stock Options
 
2014
 
2013
 
2012
 
 
(in thousands)
Intrinsic Value of Options Exercised (a)
 
$

 
$
3,105

 
$
1,699


(a)
Intrinsic value is calculated as market price at exercise dates less the option exercise price.

A summary of AEP stock option transactions during the years ended December 31, 2014, 2013 and 2012 is as follows:
 
2014
 
2013
 
2012
 
Options
 
Weighted
Average
Exercise
Price
 
Options
 
Weighted
Average
Exercise
Price
 
Options
 
Weighted
Average
Exercise
Price
 
(in thousands)
 
 
 
(in thousands)
 
 
 
(in thousands)
 
 
Outstanding as of January 1,

 
NA
 
188

 
$
30.17

 
321

 
$
29.35

Granted

 
NA
 

 
NA

 

 
NA

Exercised/Converted

 
NA
 
(187
)
 
30.18

 
(128
)
 
28.21

Forfeited/Expired

 
NA
 
(1
)
 
27.95

 
(5
)
 
27.26

Outstanding as of December 31,

 
NA
 

 
NA

 
188

 
30.17

 
 
 
 
 
 
 
 
 
 
 
 
Options Exercisable as of December 31,

 
NA
 

 
NA

 
188

 
$
30.17

 
 
 
 
 
 
 
 
 
 
 
 
NA   Not applicable.
 
 
 
 
 
 
 
 
 
 
 

We include the proceeds received from exercised stock options in common stock and paid-in capital.

Performance Units

Our performance units have a fair value upon vesting equal to the average closing market price of AEP common stock for the last 20 trading days of the performance period.  The number of performance units held is multiplied by the performance score to determine the actual number of performance units realized.  The performance score can range from 0% to 200% and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the HR Committee.  Performance units are paid in cash, unless they are needed to satisfy a participant’s stock ownership requirement.  In that case, the number of units needed to satisfy the participant’s largest stock ownership requirement is mandatorily deferred as AEP Career Shares until after the end of the participant’s AEP career.  AEP

151



Career Shares are a form of non-qualified deferred compensation that has a value equivalent to shares of AEP common stock.  AEP Career Shares are paid in cash after the participant’s termination of employment.  Amounts equivalent to cash dividends on both performance units and AEP Career Shares accrue as additional units.  We record compensation cost for performance units over a three-year vesting period.  The liability for both the performance units and AEP Career Shares, recorded in Employee Benefits and Pension Obligations on the balance sheets, is adjusted for changes in value.  The fair value of performance unit awards is based on the estimated performance score and the current 20-day average closing price of AEP common stock at the date of valuation.

The HR Committee awarded performance units and reinvested dividends on outstanding performance units and AEP Career Shares for the years ended December 31, 2014, 2013 and 2012 as follows:
 
 
Years Ended December 31,
Performance Units
 
2014
 
2013
 
2012
Awarded Units (in thousands)
 
17

 
1,284

 
546

Weighted Average Unit Fair Value at Grant Date
 
$
49.73

 
$
46.23

 
$
41.38

Vesting Period (in years)
 
3

 
3

 
3

Performance Units and AEP Career Shares
(Reinvested Dividends Portion)
 
Years Ended December 31,
 
2014
 
2013
 
2012
Awarded Units (in thousands)
 
99

 
101

 
138

Weighted Average Fair Value at Grant Date
 
$
53.35

 
$
45.42

 
$
40.97

Vesting Period (in years)
 
(a)

 
(a)

 
(a)


(a)
The vesting period for the reinvested dividends on performance units is equal to the remaining life of the related performance units.  Dividends on AEP Career Shares vest immediately upon grant but are not paid in cash until after the participant’s termination of employment.
 
Performance scores and final awards are determined and certified by the HR Committee in accordance with the pre-established performance measures within approximately a month after the end of the performance period.  The HR Committee has discretion to reduce or eliminate the number of performance units earned but may not increase the number earned.  The performance scores for all open performance periods are dependent on two equally-weighted performance measures: (a) three-year total shareholder return measured relative to the Electric Utilities Industry Standard and Poor’s 500 Index and (b) three-year cumulative earnings per share measured relative to an AEP Board of Directors approved target.  

The certified performance scores and units earned for the three-year periods ended December 31, 2014, 2013 and 2012 were as follows:
 
 
Years Ended December 31,
Performance Units
 
2014
 
2013
 
2012
Certified Performance Score
 
147.8
%
 
118.8
%
 
99.7
%
Performance Units Earned
 
889,697

 
749,219

 
1,096,572

Performance Units Mandatorily Deferred as AEP Career Shares
 
40,831

 
72,883

 
51,056

Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program
 
39,526

 
39,691

 
26,337

Performance Units to be Paid in Cash
 
809,340

 
636,645

 
1,019,179


The cash payouts for the years ended December 31, 2014, 2013 and 2012 were as follows:
 
 
Years Ended December 31,
Performance Units and AEP Career Shares
 
2014
 
2013
 
2012
 
 
(in thousands)
Cash Payouts for Performance Units
 
$
29,263

 
$
43,925

 
$
44,968

Cash Payouts for AEP Career Share Distributions
 
4,324

 
3,675

 
11,027


152



Restricted Stock Units

The HR Committee grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments.  Additional RSUs granted as dividends vest on the same date as the underlying RSUs on which the dividends were awarded.  Upon vesting, RSUs are converted into a share of AEP common stock, with the exception of participants subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934, who are paid in cash.  In 2014, there were no RSUs granted to Section 16 participants as AEP deferred granting these and other awards until February 2015. For awards that are settled with shares, compensation cost is measured at fair value on the grant date and recorded over the vesting period.  Fair value is determined by multiplying the number of units granted by the grant date market closing price.  For awards that are paid in cash, compensation cost is recorded over the vesting period and adjusted for changes in fair value until vested.  The fair value at vesting is determined by multiplying the number of units vested by the 20-day average closing price of AEP common stock.  The maximum contractual term of outstanding RSUs is six years from the grant date.

In 2010, the HR Committee granted a total of 165,520 RSUs to four Chief Executive Officer succession candidates as a retention incentive for these candidates.  These grants vest, subject to the candidates’ continuous employment, in three approximately equal installments on August 3, 2013, August 3, 2014 and August 3, 2015.  Of these RSUs, 55,172 vested on August 3, 2013, 55,172 vested on August 3, 2014 and 55,176 remain outstanding, excluding dividends.

The HR Committee awarded RSUs, including units awarded for dividends, for the years ended December 31, 2014, 2013 and 2012 as follows:
 
 
Years Ended December 31,
Restricted Stock Units
 
2014
 
2013
 
2012
Awarded Units (in thousands)
 
64

 
644

 
497

Weighted Average Grant Date Fair Value
 
$
50.36

 
$
46.24

 
$
40.69


The total fair value and total intrinsic value of restricted stock units vested during the years ended December 31, 2014, 2013 and 2012 were as follows:
 
 
Years Ended December 31,
Restricted Stock Units
 
2014
 
2013
 
2012
 
 
(in thousands)
Fair Value of Restricted Stock Units Vested
 
$
18,654

 
$
15,325

 
$
10,608

Intrinsic Value of Restricted Stock Units Vested (a)
 
24,894

 
20,378

 
12,157


(a)
Intrinsic value is calculated as market price at exercise date.

A summary of the status of our nonvested RSUs as of December 31, 2014 and changes during the year ended December 31, 2014 are as follows:
Nonvested Restricted Stock Units
 
Shares/Units
 
Weighted
Average
Grant Date
Fair Value
 
 
(in thousands)
 
 
Nonvested as of January 1, 2014
 
1,205

 
$
42.64

Granted
 
64

 
50.36

Vested
 
(467
)
 
39.97

Forfeited
 
(19
)
 
44.57

Nonvested as of December 31, 2014
 
783

 
44.59


The total aggregate intrinsic value of nonvested RSUs as of December 31, 2014 was $48 million and the weighted average remaining contractual life was 1.61 years.

153



Other Stock-Based Plans

We also have a Stock Unit Accumulation Plan for Non-employee Directors providing each non-employee director with AEP stock units as a substantial portion of their quarterly compensation for their services as a director.  The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned.  Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units.  The stock units granted to Non-employee Directors are fully vested upon grant date.  Stock units are paid in cash upon termination of board service or up to 10 years later if the participant so elects.  Cash payments for stock units are calculated based on the average closing price of AEP common stock for the last 20 trading days prior to the distribution date.

We record compensation cost for stock units when the units are awarded and adjust the liability for changes in value based on the current 20-day average closing price of AEP common stock on the valuation date.

The cash payout for stock unit distributions was $5 million for the year ended December 31, 2014. We had no material cash payouts for stock unit distributions for the years ended December 31, 2013 and 2012.

The Board of Directors awarded stock units, including units awarded for dividends, for the years ended December 31, 2014, 2013 and 2012 as follows:
 
 
Years Ended December 31,
Stock Unit Accumulation Plan for Non-Employee Directors
 
2014
 
2013
 
2012
Awarded Units (in thousands)
 
25

 
33

 
52

Weighted Average Grant Date Fair Value
 
$
54.08

 
$
45.81

 
$
41.20


Share-based Compensation Plans

Compensation cost and the actual tax benefit realized for the tax deductions from compensation cost for share-based payment arrangements recognized in income and total compensation cost capitalized in relation to the cost of an asset for the years ended December 31, 2014, 2013 and 2012 were as follows:
 
 
Years Ended December 31,
Share-based Compensation Plans
 
2014
 
2013
 
2012
 
 
(in thousands)
Compensation Cost for Share-based Payment Arrangements (a)
 
$
85,414

 
$
56,352

 
$
51,767

Actual Tax Benefit Realized
 
29,895

 
19,723

 
18,119

Total Compensation Cost Capitalized
 
23,063

 
13,165

 
10,707


(a)
Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.

During the years ended December 31, 2014, 2013 and 2012, there were no significant modifications affecting any of our share-based payment arrangements.

As of December 31, 2014, there was $79 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the LTIP.  Unrecognized compensation cost related to the performance units and AEP Career Shares will change as the fair value is adjusted each period and forfeitures for all award types are realized.  Our unrecognized compensation cost will be recognized over a weighted-average period of 1.35 years.


154



Cash received from stock options exercised and actual tax benefit realized for the tax deductions from stock options exercised during the years ended December 31, 2014, 2013 and 2012 were as follows:
 
 
Years Ended December 31,
Share-based Compensation Plans
 
2014
 
2013
 
2012
 
 
(in thousands)
Cash Received from Stock Options Exercised
 
$

 
$
5,659

 
$
3,598

Actual Tax Benefit Realized for the Tax Deductions from Stock Options Exercised
 

 
1,040

 
618


Our practice is to use authorized but unissued shares to fulfill share commitments for stock option exercises and RSU vesting.  Although we do not currently anticipate any changes to this practice, we are permitted to use treasury shares, shares acquired in the open market specifically for distribution under the LTIP or any combination thereof for this purpose.  The number of new shares issued to fulfill vesting RSUs is generally reduced to offset our tax withholding obligation.

155



16.  VARIABLE INTEREST ENTITIES

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE.  A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.  Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.”  In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE’s variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors.  We believe that significant assumptions and judgments were applied consistently.

We are the primary beneficiary of Sabine, DCC Fuel, AEP Credit, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, a protected cell of EIS and Transource Energy.  In addition, we have not provided material financial or other support to any of these entities that was not previously contractually required.  We hold a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series).

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the years ended December 31, 2014, 2013 and 2012 were $151 million, $155 million and $147 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on the balance sheets.

I&M has nuclear fuel lease agreements with DCC Fuel IV LLC, DCC Fuel V LLC, DCC Fuel VI LLC and DCC Fuel VII (collectively DCC Fuel).  DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the leases for the years ended December 31, 2014, 2013 and 2012 were $109 million, $153 million and $127 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months.  Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  The lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC in October 2013 and for DCC Fuel II LLC in October 2014.  See the tables below for the classification of DCC Fuel’s assets and liabilities on the balance sheets.

AEP Credit is a wholly-owned subsidiary of AEP.  AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements.  AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings.  Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing.  Based on our control of AEP Credit, management concluded that we are the primary beneficiary and are required to consolidate AEP Credit.  See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets.  See “Securitized Accounts Receivables – AEP Credit” section of Note 14.


156



Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.  Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant.  Therefore, TCC is required to consolidate Transition Funding.  The securitized bonds totaled $1.8 billion and $2.0 billion as of December 31, 2014 and 2013, respectively.  Transition Funding has securitized transition assets of $1.6 billion and $1.9 billion as of December 31, 2014 and 2013, respectively.  The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT.  The securitization bonds are payable only from and secured by the securitized transition assets.  The bondholders have no recourse to TCC or any other AEP entity.  TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs.  See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets.

Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property.  Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant.  Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding.  The securitized bonds totaled $232 million and $267 million as of December 31, 2014 and 2013, respectively.  Ohio Phase-in-Recovery Funding has securitized assets of $110 million and $132 million as of December 31, 2014 and 2013, respectively.  The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO.  In August 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to OPCo or any other AEP entity.  OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs.  See the table below for the classification of Ohio Phase-in-Recovery Funding's assets and liabilities on the balance sheets.

Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance.  Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant.  Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding.  The securitized bonds totaled $368 million and $380 million as of December 31, 2014 and 2013, respectively.   Appalachian Consumer Rate Relief Funding has securitized assets of $350 million and $369 million as of December 31, 2014 and 2013, respectively.  The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC.  In November 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to APCo or any other AEP entity.  APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs.  See the table below for the classification of Appalachian Consumer Rate Relief Funding's assets and liabilities on the balance sheets.

The securitized bonds of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in current and long-term debt on the balance sheets.  The securitized assets of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in securitized assets on the balance sheets.

Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance.  EIS has multiple protected cells.  Neither AEP nor its subsidiaries have an equity investment in EIS.  The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance.  Our subsidiaries and any allowed

157



third parties share in the insurance coverage, premiums and risk of loss from claims.  Based on our control and the structure of the protected cell of EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate the protected cell of EIS.  Our insurance premium expense to the protected cell for the years ended December 31, 2014, 2013 and 2012 were $32 million, $31 million and $32 million, respectively.  See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets.

Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity. Therefore, AEP is required to consolidate Transource Energy. AEP’s equity interest could potentially be significant. In January 2014, Transource Missouri (a wholly-owned subsidiary of Transource Energy) acquired transmission assets from the non-controlling owner and issued debt and received a capital contribution to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, construction projects, debt issuance and capital contribution. AEP has provided capital contributions to Transource Energy of $23 million and $3 million, in 2014 and 2013, respectively. In the event a Transource Missouri project is abandoned by the RTO, AEP would be required to fund additional capital. See the tables below for the classification of Transource Energy’s assets and liabilities on the balance sheets.

The balances below represent the assets and liabilities of the VIEs that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2014
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
Sabine
 
I&M
DCC Fuel
 
AEP
Credit
 
TCC Transition
Funding
 
OPCo
Ohio
Phase-in-
Recovery Funding
 
APCo
Appalachian
Consumer
Rate
Relief Funding
 
Protected
Cell
of EIS
 
Transource Energy
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Assets
$
68

 
$
97

 
$
980

 
$
239

 
$
33

 
$
18

 
$
149

 
$
2

Net Property, Plant and Equipment
145

 
158

 

 

 

 

 

 
98

Other Noncurrent Assets
52

 
80

 

 
1,654

(a)
210

(b)
358

(c)
2

 
4

Total Assets
$
265


$
335


$
980


$
1,893

 
$
243

 
$
376

 
$
151

 
$
104

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
$
36

 
$
86

 
$
894

 
$
322

 
$
47

 
$
27

 
$
44

 
$
21

Noncurrent Liabilities
228

 
249

 

 
1,553

 
195

 
347

 
62

 
55

Equity
1

 

 
86

 
18

 
1

 
2

 
45

 
28

Total Liabilities and Equity
$
265


$
335


$
980


$
1,893


$
243


$
376


$
151

 
$
104


(a)
Includes an intercompany item eliminated in consolidation of $75 million.
(b)
Includes an intercompany item eliminated in consolidation of $97 million.
(c)
Includes an intercompany item eliminated in consolidation of $4 million.

158



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2013
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
Sabine
 
I&M
DCC Fuel
 
AEP
Credit
 
TCC Transition
Funding
 
OPCo
Ohio
Phase-in-
Recovery Funding
 
APCo
Appalachian
Consumer
Rate
Relief
 
Protected
Cell
of EIS
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Assets
$
67

 
$
118

 
$
935

 
$
232

 
$
23

 
$
6

 
$
143

Net Property, Plant and Equipment
157

 
157

 

 

 

 

 

Other Noncurrent Assets
51

 
60

 
1

 
1,918

(a)
252

(b)
378

(c)
3

Total Assets
$
275

 
$
335

 
$
936

 
$
2,150

 
$
275

 
$
384

 
$
146

 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
$
33

 
$
108

 
$
827

 
$
312

 
$
37

 
$
14

 
$
39

Noncurrent Liabilities
242

 
227

 
1

 
1,820

 
237

 
368

 
66

Equity

 

 
108

 
18

 
1

 
2

 
41

Total Liabilities and Equity
$
275

 
$
335

 
$
936

 
$
2,150

 
$
275

 
$
384

 
$
146


(a)
Includes an intercompany item eliminated in consolidation of $82 million.
(b)
Includes an intercompany item eliminated in consolidation of $116 million.
(c)
Includes an intercompany item eliminated in consolidation of $4 million.

DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and voting rights equally.  Each entity guarantees 50% of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  SWEPCo’s total billings from DHLC for the years ended December 31, 2014, 2013 and 2012 were $56 million, $60 million and $77 million, respectively.  We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC.  Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on the balance sheets.

Our investment in DHLC was:
 
2014
 
2013
 
As Reported on
the Balance Sheet
 
Maximum
Exposure
 
As Reported on
the Balance Sheet
 
Maximum
Exposure
 
(in millions)
Capital Contribution from SWEPCo
$
8

 
$
8

 
$
8

 
$
8

Retained Earnings
4

 
4

 
1

 
1

Advance Due to Parent
56

 
56

 

 

Guarantee of Debt

 
48

 

 
61

 
 
 
 
 
 
 
 
Total Investment in DHLC
$
68


$
116


$
9


$
70



159



We and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH).  PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region.  PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy.  Provisions exist within the PATH-WV agreement that make it a VIE.  The “Allegheny Series” is not considered a VIE.  We are not required to consolidate PATH-WV as we are not the primary beneficiary, although we hold a significant variable interest in PATH-WV.  Our equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the balance sheets.  We and FirstEnergy share the returns and losses equally in PATH-WV.  Our subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements.  The entities recover costs through regulated rates.

In August 2012, the PJM board cancelled the PATH Project, the transmission project that PATH was intended to develop, and removed it from the 2012 Regional Transmission Expansion Plan.  In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project.  In November 2012, the FERC issued an order accepting the PATH Project’s abandonment cost recovery application, subject to settlement procedures and hearing.  The parties to the case have been unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated.  Litigation is ongoing and a hearing at the FERC is scheduled for March 2015.

Our investment in PATH-WV was:
 
December 31,
 
2014
 
2013
 
As Reported on
the Balance Sheet
 
Maximum
Exposure
 
As Reported on
the Balance Sheet
 
Maximum Exposure
 
(in millions)
Capital Contribution from AEP
$
19

 
$
19

 
$
19

 
$
19

Retained Earnings
2

 
2

 
6

 
6

 
 
 
 
 
 
 
 
Total Investment in PATH-WV
$
21


$
21


$
25


$
25


As of December 31, 2014, our $21 million investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the balance sheet.  If we cannot ultimately recover our investment related to PATH-WV, it could reduce future net income and cash flows.

160



17.  PROPERTY, PLANT AND EQUIPMENT

Depreciation, Depletion and Amortization

We provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.  The following tables provide the annual property information:
2014
 
Regulated
 
Nonregulated
Functional
Class of
Property
 
Property,
Plant and
Equipment
 
Accumulated
Depreciation
 
Annual
Composite
Depreciation
Rate Ranges
 
Depreciable
Life Ranges
 
Property,
Plant and
Equipment
 
Accumulated
Depreciation
 
Annual
Composite
Depreciation
Rate Ranges
 
Depreciable
Life Ranges
 
 
(in millions)
 
 
 
(in years)
 
(in millions)
 
 
 
(in years)
Generation
 
$
18,394


$
7,313


1.7 - 3.5%

31 - 132

$
7,333


$
3,135


2.6 - 3.4%

35 - 66
Transmission
 
12,395


2,877


1.4 - 2.7%

15 - 87

38


17


2.3%

43 - 55
Distribution
 
17,157


4,145


2.4 - 3.7%

7 - 75





NA

NA
CWIP
 
3,088


(126
)

NM

NM

130


1


NM

NM
Other
 
4,361


2,254


2.1 - 8.6%

5 - 75

1,409


572


17.1%

25 - 50
Total
 
$
55,395

 
$
16,463

 
 
 
 
 
$
8,910

 
$
3,725

 
 
 
 
2013
 
Regulated
 
Nonregulated
Functional
Class of
Property
 
Property,
Plant and
Equipment
 
Accumulated
Depreciation
 
Annual
Composite
Depreciation
Rate Ranges
 
Depreciable
Life Ranges
 
Property,
Plant and
Equipment
 
Accumulated
Depreciation
 
Annual
Composite
Depreciation
Rate Ranges
 
Depreciable
Life Ranges
 
 
(in millions)
 
 
 
(in years)
 
(in millions)
 
 
 
(in years)
Generation
 
$
17,873

 
$
7,168

 
1.7 - 3.7%
 
31 - 132
 
$
7,201

 
$
2,969

 
2.6 - 3.3%
 
35 - 66
Transmission
 
10,854

 
2,805

 
1.1 - 2.7%
 
25 - 87
 
39

 
16

 
2.5%
 
43 - 55
Distribution
 
16,377

 
3,988

 
2.3 - 3.8%
 
11 - 75
 

 

 
NA
 
NA
CWIP
 
2,326

 
(121
)
 
NM
 
NM
 
145

 
1

 
NM
 
NM
Other
 
4,116

 
1,931

 
2.0 - 7.9%
 
5 - 75
 
1,354

 
531

 
NM
 
NM
Total
 
$
51,546

 
$
15,771

 
 
 
 
 
$
8,739

 
$
3,517

 
 
 
 
2012
 
Regulated
 
Nonregulated
Functional Class of Property
 
Annual
Composite
Depreciation
Rate Ranges
 
Depreciable
Life Ranges
 
Annual
Composite
Depreciation
Rate Ranges
 
Depreciable
Life Ranges
 
 
 
 
(in years)
 
 
 
(in years)
Generation
 
1.7 - 3.8%
 
31 - 132
 
2.6 - 3.3%
 
35 - 66
Transmission
 
1.2 - 2.8%
 
25 - 87
 
NA
 
NA
Distribution
 
2.4 - 3.9%
 
11 - 75
 
NA
 
NA
CWIP
 
NM
 
NM
 
NM
 
NM
Other
 
1.8 - 9.6%
 
5 - 75
 
NM
 
NM

NA    Not applicable.
NM    Not meaningful.

We provide for depreciation, depletion and amortization of coal-mining assets over each asset's estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment.  We use either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages.  We include these costs in the cost of coal charged to fuel expense.

For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization.  Actual removal costs incurred are charged to Accumulated Depreciation and Amortization.  Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability.  For nonregulated operations, non-ARO removal costs are expensed as incurred.


161



Asset Retirement Obligations (ARO)

We record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for our legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities, as well as for nuclear decommissioning of our Cook Plant.  We have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which we have assets.  Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property’s use.  We do not estimate the retirement for such easements because we plan to use our facilities indefinitely.  The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements, which is not expected.

The following is a reconciliation of the 2014 and 2013 aggregate carrying amounts of ARO:
 
Carrying
Amount
of ARO
 
(in millions)
ARO as of December 31, 2012
$
1,696

Accretion Expense
103

Liabilities Incurred
4

Liabilities Settled
(22
)
Revisions in Cash Flow Estimates
54

ARO as of December 31, 2013
1,835

Accretion Expense
95

Liabilities Incurred
42

Liabilities Settled
(34
)
Revisions in Cash Flow Estimates
81

ARO as of December 31, 2014
$
2,019


As of December 31, 2014 and 2013, our ARO liability included $1.3 billion and $1.2 billion, respectively, for nuclear decommissioning of the Cook Plant.  As of December 31, 2014 and 2013, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $1.8 billion and $1.6 billion, respectively, and are recorded in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

Our amounts of allowance for borrowed, including interest capitalized, and equity funds used during construction is summarized in the following table:
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Allowance for Equity Funds Used During Construction
$
103

 
$
73

 
$
93

Allowance for Borrowed Funds Used During Construction
44

 
40

 
69



162



Jointly-owned Electric Facilities

We have electric facilities that are jointly-owned with nonaffiliated companies.  Using our own financing, we are obligated to pay a share of the costs of these jointly-owned facilities in the same proportion as our ownership interest.  Our proportionate share of the operating costs associated with such facilities is included on the statements of income and the investments and accumulated depreciation are reflected on the balance sheets under Property, Plant and Equipment as follows:
 
 
 
 
 
Company’s Share as of December 31, 2014
 
Fuel
Type
 
Percent of
Ownership
 
Utility Plant
in Service
 
Construction
Work in
Progress
 
Accumulated
Depreciation
 
 
 
 
 
(in millions)
W.C. Beckjord Generating Station, Unit 6 (a)
Coal
 
12.5
%
 
$


$


$

Conesville Generating Station, Unit 4 (b)
Coal
 
43.5
%
 
336


2


66

J.M. Stuart Generating Station (c)
Coal
 
26.0
%
 
553


12


206

Wm. H. Zimmer Generating Station (a)
Coal
 
25.4
%
 
812


4


410

Dolet Hills Generating Station, Unit 1 (d)
Lignite
 
40.2
%
 
330


4


201

Flint Creek Generating Station, Unit 1 (e)
Coal
 
50.0
%
 
125


120


68

Pirkey Generating Station, Unit 1 (e)
Lignite
 
85.9
%
 
531


36


381

Oklaunion Generating Station, Unit 1 (f)
Coal
 
70.3
%
 
409


10


228

Turk Generating Plant (e)
Coal
 
73.33
%
 
1,647


1


70

Transmission
NA
 
(g)

 
82


1


49

Total
 
 
 
 
$
4,825

 
$
190

 
$
1,679

 
 
 
 
 
Company’s Share as of December 31, 2013
 
Fuel
Type
 
Percent of
Ownership
 
Utility Plant
in Service
 
Construction
Work in
Progress
 
Accumulated
Depreciation
 
 
 
 
 
(in millions)
W.C. Beckjord Generating Station, Unit 6 (a)
Coal
 
12.5
%
 
$

 
$

 
$

Conesville Generating Station, Unit 4 (b)
Coal
 
43.5
%
 
335

 
2

 
55

J.M. Stuart Generating Station (c)
Coal
 
26.0
%
 
544

 
11

 
190

Wm. H. Zimmer Generating Station (a)
Coal
 
25.4
%
 
809

 
2

 
399

Dolet Hills Generating Station, Unit 1 (d)
Lignite
 
40.2
%
 
262

 
47

 
198

Flint Creek Generating Station, Unit 1 (e)
Coal
 
50.0
%
 
123

 
54

 
66

Pirkey Generating Station, Unit 1 (e)
Lignite
 
85.9
%
 
519

 
29

 
376

Oklaunion Generating Station, Unit 1 (f)
Coal
 
70.3
%
 
404

 
7

 
223

Turk Generating Plant (e)
Coal
 
73.33
%
 
1,638

 
13

 
35

Transmission
NA
 
(g)

 
78

 

 
50

Total
 
 
 
 
$
4,712

 
$
165

 
$
1,592


(a)
Operated by Duke Energy Corporation, a nonaffiliated company.  AEP's portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012.  See "Impairments" section of Note 7.
(b)
Operated by AGR.
(c)
Operated by The Dayton Power & Light Company, a nonaffiliated company.
(d)
Operated by CLECO, a nonaffiliated company.
(e)
Operated by SWEPCo.
(f)
Operated by PSO and also jointly-owned (54.7%) by TNC.
(g)
Varying percentages of ownership.
NA
Not applicable.

163



18.  COST REDUCTION PROGRAMS

2014 Disposition Plant Severance

AEP intends to retire several generation plants or units of plants during 2015. The plant closures will result in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits.

We recorded a charge to Other Operation expense in December 2014 primarily related to employees at the disposition plants.
 
 
Disposition Plant
Severance Activity
 
 
(in millions)
Incurred
 
$
29

Settled
 

Adjustments
 

Balance as of December 31, 2014
 
$
29


These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the statements of income.  Of the current period expense, approximately 32% was within the Generation & Marketing segment and 68% was within the Vertically Integrated Utilities segment.   The remaining liability is included in Other Current Liabilities on the balance sheets.  We do not expect additional severance costs to be incurred related to this initiative.

2012 Sustainable Cost Reductions

In April 2012, we initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings.  We selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate our current employee benefit programs.  The process resulted in involuntary severances and was completed by the end of the first quarter of 2013.  The severance program provides two weeks of base pay for every year of service along with other severance benefits.

We recorded charges to Other Operation expense of $7 million and $47 million for the years ended December 31, 2013 and 2012, respectively, primarily related to severance benefits as a result of the sustainable cost reductions initiative.  



164



19.  UNAUDITED QUARTERLY FINANCIAL INFORMATION

In our opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of our results of operations for interim periods.  Quarterly results are not necessarily indicative of a full year’s operations because of various factors.  Our unaudited quarterly financial information is as follows:
 
2014 Quarterly Periods Ended
 
March 31
 
June 30
 
September 30
 
December 31
 
 
(in millions  except per share amounts)
Total Revenues
$
4,648

 
$
4,044

 
$
4,302

 
$
4,026

 
Operating Income
1,041

 
767

 
925

 
499

(a)
Net Income
561

 
391

 
494

 
192

(a)
 
 
 
 
 
 
 
 
 
Earnings Attributable to AEP Common Shareholders
560

 
390

 
493

 
191

 
 
 
 
 
 
 
 
 
 
Total Basic Earnings per Share Attributable to AEP Common Shareholders (b)
1.15

 
0.80

 
1.01

 
0.39

 
 
 
 
 
 
 
 
 
 
Total Diluted Earnings per Share Attributable to AEP Common Shareholders (b)
1.15

 
0.80

 
1.01

 
0.39

 
 
2013 Quarterly Periods Ended
 
March 31
 
June 30
 
September 30
 
December 31
 
 
(in millions  except per share amounts)
Total Revenues
$
3,826

 
$
3,582

 
$
4,176

 
$
3,773

 
Operating Income
755

 
547

(c)
875

(e)
678

(f)(g)
Net Income
364

 
339

(c)(d)
434

(e)
347

(f)(g)
 
 
 
 
 
 
 
 
 
Earnings Attributable to AEP Common Shareholders
363

 
338

(c)(d)
433

(e)
346

(f)(g)
 
 
 
 
 
 
 
 
 
Total Basic Earnings per Share Attributable to AEP Common Shareholders (b)
0.75

 
0.69

 
0.89

 
0.71

 
 
 
 
 
 
 
 
 
 
Total Diluted Earnings per Share Attributable to AEP Common Shareholders (b)
0.75

 
0.69

 
0.89

 
0.71

 

(a)
Includes termination of a coal contract and a KPCo regulatory disallowance (see Note 4).
(b)
Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding.
(c)
Includes an impairment for Muskingum River Plant, Unit 5 (see Note 7).
(d)
Includes U.K. Windfall Tax benefit (see Note 12).
(e)
Includes regulatory disallowances for the Turk Plant (see Note 4) and for Big Sandy Plant, Unit 2 (see Note 7).
(f)
Includes a regulatory disallowance for Amos Plant, Unit 3 (see Note 7).
(g)
Includes the reversal of regulatory disallowance for the Turk Plant (see Note 4).


165



20.  GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

The changes in our carrying amount of goodwill for the years ended December 31, 2014 and 2013 by operating segment are as follows:
 
Vertically
Integrated
Utilities
 
AEP River
Operations
 
Generation
and
Marketing
 
AEP
Consolidated
 
(in millions)
Balance as of December 31, 2012
$
37

 
$
39

 
$
15

 
$
91

Impairment Losses

 

 

 

Balance as of December 31, 2013
37

 
39

 
15

 
91

Impairment Losses

 

 

 

Balance as of December 31, 2014
$
37

 
$
39

 
$
15

 
$
91


In the fourth quarters of 2014 and 2013, we performed our annual impairment tests.  The fair values of the operations with goodwill were estimated using cash flow projections and other market value indicators.  There were no goodwill impairment losses.  We do not have any accumulated impairment on existing goodwill.

Other Intangible Assets

Acquired intangible assets subject to amortization were $5 million and $10 million as of December 31, 2014 and 2013, respectively, net of accumulated amortization and are included in Deferred Charges and Other Noncurrent Assets on the balance sheets.  The amortization life, gross carrying amount and accumulated amortization by major asset class are as follows:
 
 
 
December 31,
 
 
 
2014
 
2013
 
Amortization
Life
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
(in years)
 
(in millions)
Acquired Customer Contracts
5
 
$
58

 
$
53

 
$
58

 
$
48


Amortization of intangible assets was $5 million, $14 million and $34 million for the years ended December 31, 2014, 2013 and 2012, respectively.  Our estimated total amortization is $3 million and $2 million for 2015 and 2016, respectively.

166



CORPORATE AND SHAREHOLDER INFORMATION

Corporate Headquarters
1 Riverside Plaza
Columbus, OH 43215-2373
614-716-1000
AEP is incorporated in the State of New York.

Stock Exchange Listing - The Company’s common stock is traded principally on the New York Stock Exchange under the ticker symbol AEP.

Internet Home Page - Information about AEP, including financial documents, Securities and Exchange Commission (SEC) filings, news releases, investor presentations, shareholder information and customer service information, is available on the Company’s home page on the Internet at www.AEP.com/investors.

Inquiries Regarding Your Stock Holdings - Registered shareholders (shares that you own, in your name) should contact the Company’s transfer agent, listed below, if you have questions about your account, address changes, stock transfer, lost certificates, direct deposits, dividend checks and other administrative matters. You should have your Social Security number or account number ready; the transfer agent will not speak to third parties about an account without the shareholder’s approval or appropriate documents.

Transfer Agent & Registrar
Computershare Trust Company, N.A.
P.O. Box 43078
Providence, RI 02940-3078
For overnight deliveries:
Computershare Trust Company, N.A.
250 Royall Street
Canton, MA 02021-1011
Telephone Response Group:1-800-328-6955
Internet address: www.computershare.com/investor
Hearing Impaired #: TDD: 1-800-952-9245

Beneficial Holders - (Stock held in a bank or brokerage account) - When you purchase stock and it is held for you by your broker, it is listed with the Company in the broker’s name, and this is sometimes referred to as “street name” or a “beneficial owner.” AEP does not know the identity of individual shareholders who hold their shares in this manner; we simply know that a broker holds a certain number of shares which may be for any number of customers. If you hold your stock in street name, you receive all dividend payments, annual reports and proxy materials through your broker. Therefore, questions about your account should be directed to your broker.

Dividend Reinvestment and Direct Stock Purchase Plan - A Dividend Reinvestment and Direct Stock Purchase Plan is available to all investors. It is an economical and convenient method of purchasing shares of AEP common stock, through initial cash investments, cash dividends and/or additional optional cash purchases. You may obtain the Plan prospectus and enrollment authorization form by contacting the transfer agent or by visiting www.AEP.com/investors/buyandmanagestock.

Financial Community Inquiries - Institutional investors or securities analysts who have questions about the Company should direct inquiries to Bette Jo Rozsa, 614-716-2840, bjrozsa@AEP.com; Individual shareholders should contact Kathleen Kozero, 614-716-2819, klkozero@AEP.com.

Number of Shareholders - As of February 23, 2015, there were approximately 73,000 registered shareholders and approximately 500,000 shareholders holding stock in street name through a bank or broker. There were 489,620,548 shares outstanding as of February 23, 2015.

Form 10-K - Upon request, we will provide without charge a copy of our Form 10-K for the fiscal year ended December 31, 2014. A copy can be obtained via mail with a written request to AEP Investor Relations, by telephone at 1-800-237-2667 or electronically at klkozero@AEP.com.


167



Executive Leadership Team
Name
 
Age
 
Office
Nicholas K. Akins
 
54
 
Chairman of the Board, President and Chief Executive Officer
Lisa M. Barton
 
49
 
Executive Vice President - Transmission
David M. Feinberg
 
45
 
Executive Vice President, General Counsel and Secretary
Lana L. Hillebrand
 
54
 
Senior Vice President and Chief Administrative Officer
Mark C. McCullough
 
55
 
Executive Vice President - Generation
Robert P. Powers
 
61
 
Executive Vice President and Chief Operating Officer
Brian X. Tierney
 
47
 
Executive Vice President and Chief Financial Officer
Dennis E. Welch
 
63
 
Executive Vice President and Chief External Officer
Charles E. Zebula
 
54
 
Executive Vice President - Energy Supply


168