DEF 14A

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. )

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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)

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Notice of 2012 Annual Meeting • Proxy Statement

	American Electric Power 1 Riverside Plaza Columbus, OH 43215
	Michael G. Morris Chairman of the Board

March 14, 2012

Dear Shareholder:

This year’s annual meeting of shareholders will be held at The Renaissance Tulsa Hotel and Convention Center, 6808 South 107^th East Avenue, Tulsa, Oklahoma, on Tuesday, April 24, 2012, at 9:30 a.m. Central 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 27, 2012, 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.

This year, we again are pleased to be using the U.S. Securities and Exchange Commission rule that allows companies to furnish their proxy materials over the Internet. As a result, we are mailing to many of our shareholders a notice instead of a paper copy of this proxy statement and our 2011 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 2011 Annual Report and a form of proxy card or voting instruction card. We believe that this process will conserve natural resources and reduce the costs of printing and distributing our proxy materials.

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,

/s/ Michael G. Morris

NOTICE OF 2012 ANNUAL MEETING

American Electric Power Company, Inc.

1 Riverside Plaza

Columbus, Ohio 43215

TIME	9:30 a.m. Central Time on Tuesday, April 24, 2012
PLACE	The Renaissance Tulsa Hotel and Convention Center 6808 South 107th East Avenue Tulsa, Oklahoma
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 approve the American Electric Power System Senior Officer Incentive Plan.
	(3)    To ratify the appointment of Deloitte & Touche LLP as independent registered public accounting firm for the year 2012.
	(4)    To hold an advisory vote on executive compensation.
	(5)    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 27, 2012, 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.
	Any proxy may be revoked at any time before your shares are voted at the meeting.

March 14, 2012 David M. Feinberg
Secretary

Our annual meeting of shareholders also will be webcast at http://www.AEP.com/go/webcasts at 9:30 a.m. Central Time on April 24, 2012.

TABLE OF CONTENTS

Proxy and Voting Information	1
Item 1: Election of Directors	3
AEP’s Board of Directors and Committees	6
Director Compensation for 2011	18
Item 2: Proposal to Approve the Company’s Senior Officer Incentive Plan	21
Item 3: Proposal to Ratify Appointment of Independent Registered Public Accounting Firm	23
Item 4: Advisory Vote on Executive Compensation	26
Compensation Discussion and Analysis	27
Executive Compensation	50
Summary Compensation Table	50
Grants of Plan-Based Awards	52
Outstanding Equity Awards at Fiscal Year-End for 2011	56
Option Exercises and Stock Vested for 2011	58
Pension Benefits for 2011	59
Nonqualified Deferred Compensation for 2011	62
Potential Payments Upon Termination or Change of Control	64
Share Ownership of Directors and Executive Officers	76
Section 16(a) Beneficial Ownership Reporting Compliance	76
Share Ownership of Certain Beneficial Owners	77
Shareholder Proposals and Nominations	77
Solicitation Expenses	78
Exhibit A: American Electric Power Company, Inc. Senior Officer Incentive Plan	A-1
Exhibit B: Reconciliation of Ongoing to GAAP Reported Earnings	B-1

Proxy Statement

March 14, 2012

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 14, 2012, 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 24, 2012 in Tulsa, Oklahoma.

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 27, 2012, 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 483,895,440 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 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 27, 2012.

Revocation of Proxies.    A shareholder giving a proxy may revoke it at any time before it is voted at the meeting by executing another proxy dated after the proxy to be 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 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, to approve the Company’s Senior Officer Incentive Plan and the advisory vote on executive compensation are “non-discretionary” matters, which means that brokerage firms may not use their discretion to vote on such matters without express voting instructions from their clients.

In 2009, the Company 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. If a nominee is not elected because he or she did 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 each of the other proposals (Item 2: Proposal to Approve the Company’s Senior Officer Incentive Plan; Item 3: Proposal to Ratify Appointment of Independent Registered Public Accounting Firm; and Item 4: Advisory Vote on Executive Compensation) requires 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. Abstentions and broker non-votes are not counted as votes “for” or “against” Item 2 (Proposal to Approve the Company’s Senior Officer Incentive Plan) or Item 4 (Advisory Vote on Executive Compensation) and therefore will have no effect on the outcome of the votes with respect to such proposals.

Abstentions are not counted as votes “for” or “against” Item 3 (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 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 write 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.

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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 in 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, 2011 are available at www.edocumentview.com/aep.

Item 1. Election of Directors

Currently, AEP’s Board of Directors consists of 13 members. Dr. Hudson will end his service as a member of the Board effective as of the date of the annual meeting; therefore the Board of Directors has authorized a reduction in the size of the Board to 12 members, effective as of April 24, 2012, as permitted by the Bylaws.

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 6 were nominated by the Board on the recommendation of the Committee on Directors and Corporate Governance of the Board, following individual evaluation of each incumbent nominee’s qualifications and 2011 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 2011 annual meeting, except Mr. Akins, who was appointed as a director in November 2011 upon his appointment as chief executive officer of the Company. 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 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, options exercisable within 60 days and stock-based units beneficially owned by each of them appear on page 76.

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Nominees For Director

	Nicholas K. Akins Dublin, Ohio Age 51 Director since 2011	Chief executive officer of AEP since November 2011, and chairman and chief executive officer of all of its major subsidiaries since November 2011. President of AEP from January 2011 to October 2011 and executive vice president of AEP from 2006 to 2011.
	David J. Anderson Morristown, New Jersey Age 62 Director since 2011	Senior vice president and chief financial officer of Honeywell International, a diversified technology and manufacturing company, since 2003.
	James F. Cordes The Woodlands, Texas Age 71 Director since 2009	Retired executive vice president of The Coastal Corporation (1985-1997), a diversified energy company. Retired chairman and chief executive officer of ANR Pipeline Company (1985-1997), an interstate natural gas pipeline company. Mr. Cordes was formerly a director of Northeast Utilities (2001-2010) and Comerica, Inc. (1984 - 2011)
	Ralph D. Crosby, Jr. McLean, Virginia Age 64 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 Ducommun Incorporated and Serco Group PLC.
	Linda A. Goodspeed Memphis, Tennessee Age 50 Director since 2005	Senior vice president and Chief Information officer of The ServiceMaster Company since 2011. Managing partner of Wealthstrategies Financial Advisors, LLC since 2008. From 2008 to 2011, vice president of information systems of Nissan North America, Inc., an automobile manufacturer. From 2001 to 2007, executive vice president and chief supply chain logistics and technology officer of Lennox International, Inc, a provider of climate control solutions. A director of Columbus McKinnon Corp.

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Nominees For Director — continued

	Thomas E. Hoaglin Columbus, Ohio Age 62 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.
	Michael G. Morris Northville, Michigan Age 65 Director since 2004	Chairman of AEP, and former chief executive officer of AEP and all of its major subsidiaries (2004 to 2011). A director of Alcoa Inc. and The Hartford Financial Services Group, Inc. Mr. Morris was formerly a director of Cincinnati Bell, Inc. (2005-2008).
	Richard C. Notebaert Chicago, Illinois Age 65 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 was formerly a director of Qwest Communications International Inc. (2002-2007).
	Lionel L. Nowell III Cos Cob, Connecticut Age 57 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. Mr. Nowell was formerly a director of Church & Dwight, Inc. (2005-2007).

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Nominees For Director — continued

	Richard L. Sandor Chicago, Illinois Age 70 Director since 2000	Chairman and CEO Environmental Financial Products LLC (intermittently 1998 – present). Lecturer, University of Chicago Law School. Distinguished Adjunct Professor of Environmental Finance of Guanghua School of Management at Peking University. Founder and former Chairman of Chicago Climate Exchange, Inc. (CCX), an environmental commodity trading exchange (2002-2010). Former chief executive officer of CCX (2002-2009). Former Chairman of the Chicago Climate Futures Exchange (CCFE), an environmental derivatives trading exchange (2004-2010). Former chief executive officer of CCFE (2004-2009). Former Chairman of Climate Exchange PLC, the parent of CCX and CCFE (2003-2010). Former member of the design committee of the Dow Jones Sustainability Index. Dr. Sandor was formerly a director of Intercontinental Exchange, Inc. (2002-2008). Director of the Volatility Exchange (VoIX).
	Sara Martinez Tucker San Francisco, California Age 56 Director since 2009	Independent consultant since 2009. 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.
	John F. Turner Moose, Wyoming Age 70 Director since 2008	Managing partner of Triangle X Ranch, a guest ranch in Jackson Hole, Wyoming, since 1960. Assistant Secretary of State of U.S. State Department’s Bureau of Oceans and International Environmental and Scientific Affairs from 2001 to 2005. Former director of the U.S. Fish and Wildlife Service from 1989 to 1993. A director of Ashland, Inc., International Paper Company and Peabody Energy Corporation.

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 2011, the Board held eight regular 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.

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 2011 by each committee and the directors who currently serve on these committees. During 2011, no director attended fewer than 82 percent of the aggregate of the total number of meetings of the Board and the total number of meetings held by all committees during the period on which he or she served during the period that he or she served.

DIRECTOR	BOARD COMMITTEES
	Audit	Directors and Corporate Governance	Policy	Executive	Finance	Human Resources	Nuclear Oversight
Mr. Akins			X	X
Mr. Anderson	X		X		X
Mr. Cordes			X			X	X
Mr. Crosby			X			X	X (Chair)
Ms. Goodspeed	X		X (Chair)				X
Mr. Hoaglin		X (Chair)	X	X		X
Dr. Hudson		X	X	X		X (Chair)
Mr. Morris			X	X (Chair)
Mr. Notebaert		X	X			X
Mr. Nowell	X (Chair)	X	X	X	X
Dr. Sandor			X	X	X (Chair)
Ms. Tucker	X	X	X
Mr. Turner	X		X				X
2011 Meetings	9	6	2	0	4	9	5

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. Reviewing annually the performance of individual directors.

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

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

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 the SEC 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 any AEP System company. 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 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 47.

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 the SEC and our Director Independence Standards, all members of the Audit Committee are independent. The Board has determined that Mr. Nowell is an audit committee financial expert as defined by the SEC.

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 the short and long-term financing plans and programs of AEP and its subsidiaries. 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. The Board is also responsible, therefore, 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.

Our 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. Management prepared and categorized a list of the Company’s major types of risks. The Audit Committee and the Directors and Corporate Governance Committee reviewed that list and proposed 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 Risk Officer, Chief Accounting Officer and General Counsel attend all 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. For example, 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 Risk Officer and General Counsel attend all 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 senior human resources officers attend all of the HR Committee meetings.

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

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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 the executive compensation programs do not encourage excessive risk taking. The base salary component, which represents approximately 16 percent of our CEO’s total compensation opportunity, discourages risk-taking because its value and payment is contingent only upon the CEO’s continued employment with the Company. The Company also provides annual and long-term incentive compensation in amounts that represent approximately 18 percent and 67 percent of our CEO’s total compensation opportunity, respectively. The HR Committee believes this appropriately allocates 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 investments required in our business;

• Annual incentive compensation funding for nearly all employees, including all executive officers, is based on AEP’s ongoing earnings per share (EPS), other than plus or minus 10 percent, which is based on a fatality adjustment. These conditions align the interests of executives with those of shareholders. This mitigates risk by ensuring that no annual incentive compensation is paid to executive officers unless the Company’s ongoing EPS exceeds a threshold set by the HR Committee. It also ensures 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 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 all incentive award payouts to 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 they retain the discretion to reduce 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 43;

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• AEP has primarily granted long-term incentive awards in the form of performance units with a three-year performance and vesting period, which aligns the interests of employees to the long-term interests of shareholders and serves as a retention tool;

• Executives (currently 48) are subject to our executive stock ownership requirements as described in Compensation Discussion and Analysis on page 41; and

• We have not issued stock options to any executive officers since 2003.

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, Director Independence Standards, and charters for the Audit, Directors and Corporate Governance and Human Resources Committees of the Board. The corporate governance page can be found at www.aep.com/investors/corporateleadersandgovernance. Printed copies of all of these materials also are available 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 but two of its Board members (the CEO and the Chairman, who formerly was 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;

• The members of the Board meet regularly without the presence of management, and the independent members of the Board meet at least once a year;

• 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;

• 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 evaluates annually the performance of the individual directors.

Directors

The Committee on Directors and Corporate Governance is responsible for recruiting new directors and uses a variety of methods for identifying and evaluating nominees for director. The Committee on Directors and Corporate Governance 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 on Directors and Corporate Governance through shareholders, management, current members of the Board or search firms. Shareholders who wish to recommend candidates to the Committee on Directors and Corporate Governance may do so by following the procedures described in Shareholder Proposals and Nominations on page 77.

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Director qualifications.    The Company’s Principles of Corporate Governance (Principles) are available on its website at www.aep.com/investors/corporateleadersandgovernance/docs/principles.pdf. With respect to director qualifications and attributes, the Principles require the following:

In nominating a slate of Directors, the Board’s objective, with the assistance of the Committee on Directors and Corporate Governance, is to select individuals with skills and experience that can be of assistance to management in operating the Company’s business.

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

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 subsequently reviewed and refined several times, most recently at the Committee’s meeting in December 2009. The Criteria are available on the Company’s website at www.aep.com/investors/corporateleadersandgovernance/docs/criteriaforevaluatingdirectors.pdf.

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. Specifically, the Board considered the following experiences, qualifications, attributes and skills in nominating the director nominees for election at the Annual Meeting.

Mr. Akins is the Chief Executive Officer of the Company. He has undergraduate and graduate degrees in electrical engineering and is a professional registered engineer in Texas. Mr. Akins has worked at AEP and the former Central and South West Corporation for nearly thirty years, including as executive vice president-generation of AEP and president and chief operating officer of Southwestern Electric Power Company, a wholly-owned subsidiary of AEP.

Mr. Morris is the Non-Executive Chairman of the Company. He has undergraduate and graduate degrees in biology and a law degree. Mr. Morris worked for nearly four decades in the utility industry, originally in a consulting firm and then in progressively more responsible positions in gas and electric utility companies. Mr. Morris spent 15 years as chairman and chief executive officer of large, multi-state electric utility companies, having led Northeast Utilities from 1997 – 2003 and the Company from January 2004 – November 2011.

Mr. Nowell chairs the Audit Committee and is designated as the Audit Committee Financial Expert, a position required by the rules of the NYSE and the SEC. Mr. Nowell is a Certified Public Accountant and served until his retirement in 2009 in senior financial positions with Pepsico, RJR Nabisco, Pillsbury and other major companies in the food and beverage industry.

Three directors (Mr. Cordes – natural gas, Mr. Notebaert and Ms. Tucker – telecommunications) spent major parts of their careers in regulated utility companies that have many similarities to our business. And, two directors (Messrs. Cordes and Turner) understand our industry from past service on the boards of directors of another electric utility.

Our business is highly regulated, and several directors (Messrs. Cordes, Hoaglin, Morris, Notebaert and Ms. Tucker) spent careers in industries that are also highly regulated. Mr. Notebaert spent more than 11 years as Chairman and Chief Executive Officer of publicly-traded companies Qwest Communications International and Ameritech Corporation. Ms. Tucker spent a large part of her career at AT&T in senior management positions in human resources and customer service operations. Mr. Cordes spent many years as an executive in the natural gas business. Two directors (Mr. Turner and Ms. Tucker) have spent time as senior governmental officials and appreciate the issues of regulation from that perspective. Mr. Turner also served in the Wyoming state legislature

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for many years. Our business is also very capital intensive and involves sophisticated heavy equipment and facilities; Mr. Crosby’s experience in the aerospace industry gives him a background in a comparably capital intensive and sophisticated industry.

Science, engineering and technology are important in our business. Many of the Company’s directors have undergraduate and/or graduate degrees in engineering (Messrs. Akins, Cordes and Crosby and Ms. Goodspeed), while others have undergraduate and/or graduate degrees in scientific subjects (Messrs. Morris and Turner). Ms. Goodspeed is an engineering graduate with an M.B.A, who has worked in responsible positions in the service industry and in automotive and heating/cooling manufacturing. She is currently senior vice president and chief information officer of The ServiceMaster Company.

Environmental compliance is essential for success in our industry. Mr. Turner was chief executive of a national environmental organization and headed a governmental agency with environmental responsibilities, and Dr. Sandor headed a financial exchange focused on environmental financial products.

Several directors in addition to Mr. Nowell have significant experience in finance, auditing or other financial or accounting roles. Mr. Hoaglin was the chief executive of a regional bank headquartered in Columbus with a footprint that significantly overlaps the midwestern part of the Company’s service territory. Dr. Sandor was chief economist at a commodities exchange before he created the Chicago Climate Exchange (CCX) and he taught finance at the graduate level. Mr. Anderson is the Chief Financial Officer of Honeywell International, and has served as Chief Financial Officer with ITT Industries, RJR Nabisco and other major companies.

And, the experience gained from leading large, complex organizations brings invaluable perspective to a Board. Messrs. Hoaglin, Morris and Notebaert have been chief executive officers of public companies and Mr. Akins currently serves as a chief executive. Messrs. Cordes and Crosby have been chief executives of major subsidiaries of public companies, while Ms. Tucker has headed substantial non-profit organizations. Messrs. Cordes, Crosby, Hoaglin, Morris, Notebaert, Nowell, Sandor and Turner, and Ms. Goodspeed and Ms. Tucker bring to the board experience gained from currently or previously serving on the boards of directors of other public companies.

Any summary of the specific skills and attributes of individual directors is necessarily very high level. It cannot cover the full range of the skills, experience and personal attributes that each contributes to service on the Board of Directors, nor can it explain the ways in which the abilities and perspectives of different directors interact to benefit the Company.

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 Directors and Corporate Governance Committee considers these criteria each year as it determines the slate of directors 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 to the Board. The Board believes that its implementation of this policy is effective in considering the diversity of the members of the Board.

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Director Independence

In accordance with NYSE standards, a majority of the members of the Board of Directors must qualify as independent directors. No member of the Board is independent unless the Board affirmatively determines annually that such member is independent. 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 Company’s 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. The Committee 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 discusses 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, 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 buys electricity from 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. However, all of those organizations purchase electricity from us at rates set by a regulatory commission. 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. None of our directors, however, is an executive officer of those nonprofit organizations. Nonetheless, 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 AEP operates 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:

• Ms. Goodspeed is an executive officer of a company (The ServiceMaster Company) with which the Company does business. As explained earlier, although ServiceMaster purchases electricity from our subsidiaries, and the Company purchased an insignificant amount of goods from ServiceMaster, the Board does not believe that those transactions impair the independence of Ms. Goodspeed.

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• Mr. Anderson is also an executive officer of a company (Honeywell International) with which the Company does business. As explained earlier, although Honeywell purchases electricity from our subsidiaries, and the Company purchased an insignificant amount of goods from Honeywell, the Board does not believe that those transactions impair the independence of Mr. Anderson.

• Mr. Turner is a director of Peabody Energy Corporation, another company that transacted business with AEP. However, Mr. Turner is not an employee or executive officer of that company. Although we purchase a significant amount of coal from Peabody Energy Corporation, we entered into these coal buying relationships with Peabody in the ordinary course of business before Mr. Turner joined our Board. The nature of our coal purchased from Peabody since Mr. Turner became an AEP director is consistent with the nature before he was elected. In addition, since Mr. Turner became an AEP director, any AEP purchases from Peabody were awarded through a competitive process.

As a result of this review, the Board has determined that, other than Messrs. Akins and Morris, each of the directors and director nominees standing for election, including Messrs. Anderson, Cordes, Crosby, Hoaglin, Notebaert, Nowell and Turner, Dr. Sandor, Ms. Goodspeed 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 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 77 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 and Criteria for Evaluating Directors, 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.

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The Board addressed the question of whether to separate the offices of Chairman and CEO prior to Mr. Morris’ retirement and reached the conclusion that combining the position of chairman and CEO was in the best interests of the Company and its shareholders at the time. Upon Mr. Morris’ retirement, the Board made the determination that it was in the best interest of the Company and its shareholders that the two offices be separated effective November 12, 2011. The Board believes that it should retain the flexibility to make a judgment regarding its leadership structure. Currently, the Board believes that separating the two offices allows the Board to retain Mr. Morris as the best qualified person to serve as chairman of the board and to appoint Mr. Akins as the best qualified person to serve as CEO.

Mr. Morris spent 15 years leading large, multi-state, publicly held electric utility companies. He was the Company’s Chairman and Chief Executive Officer from early 2004 to late 2011. Before that, he had held the same positions at another publicly held electric utility company from August 1997 to the end of 2003. Mr. Morris has extensive knowledge about and influence within the electric utility industry, as indicated from his past leadership positions with the Institute of Nuclear Power Operations, the Edison Electric Institute and the Business Roundtable, among other organizations. In addition to serving on the Company’s Board, Mr. Morris sits on the boards of directors of two other large public companies, and he has been a panelist at prominent corporate governance conferences.

Because of Mr. Morris’ longstanding experience with the Company and other industry participants and the quality of his performance in these roles, and his extensive experience as a corporate director, the Board believes that the Company’s best interests are currently best served by Mr. Morris being non-executive chairman.

Even though Mr. Morris’ long employment history with the Company disqualifies him as serving as an independent chair, the Company already has policies and practices in place to provide independent oversight of management and the Company’s strategy. The Board currently includes eleven non-management directors among its thirteen members, all of whom qualify as independent under applicable NYSE listing standards. The Board routinely holds executive sessions at which only non-management directors are present, and, each year, the non-management directors select a Lead Director responsible for facilitating and chairing the independent directors sessions.

Dr. Hudson has been the Lead Director of the Board since 2003. 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 chief executive officer and the non-executive chairman 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, Dr. Hudson has the ability to call special meetings of the Board, as needed. He has the authority to retain outside legal counsel or other advisors as needed by the Board. He provides a channel of communications 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-management directors.

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. AEP’s Business Ethics and Corporate Compliance department will review such inquiries or communications. Communications other than advertising or promotions of a product or service will be forwarded to our Board, our independent directors as a group or our Lead Director, as applicable.

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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 5percent of the total equity of the Company and any immediate family member of any such person.

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

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

No approval or ratification of a Transaction with a Related Person necessarily satisfies or 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.

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Director Compensation for 2011

Directors who are employees of the Company receive no additional compensation for service as a director other than accidental insurance coverage. The following table presents the compensation provided by the Company in 2011 to the non-employee directors.

Name	Fees Earned Or Paid in Cash ($) (1)		Stock Awards ($) (2)(3)		All Other Compensation ($) (4)(5)(6)		Total ($)
David. J. Anderson		77,250		99,000		494		176,744
E. R. Brooks		35,115		42,438		247		77,800
Donald M Carlton		31,507		42,438		247		74,192
James F. Cordes		98,000		132,000		741		230,741
Ralph D. Crosby, Jr.		98,000		132,000		741		230,741
Linda A. Goodspeed		103,000		132,000		741		235,741
Thomas E. Hoaglin		98,000		132,000		741		230,741
Lester A. Hudson, Jr.		139,250		132,000		5,741		276,991
Richard C. Notebaert		73,500		99,000		494		172,994
Lionel L. Nowell III		123,000		132,000		1,591		256,591
Richard L. Sandor		88,000		132,000		741		220,741
Kathryn D. Sullivan		29,260		44,625		247		74,132
Sara M. Tucker		103,000		132,000		4,741		239,741
John F. Turner		103,000		132,000		741		235,741

(1) Consists of an annual cash retainer of $88,000 described below under Director Compensation and Stock Ownership – Annual Retainers and Fees. For Mr. Nowell compensation includes $20,000 paid for services as Chairman of the Audit Committee. With respect to Mr. Nowell, Mr. Turner, Ms. Goodspeed and Ms. Tucker, compensation includes $15,000 paid for services as members of the Audit Committee for the full year, and for Mr. Anderson and Mr. Brooks, compensation includes $11,250 and $4,823, respectively, paid for services as members of the Audit Committee for part of the year. For Dr. Hudson, Mr. Cordes, Mr. Crosby and Mr. Hoaglin, compensation includes $10,000 paid for services as members of the Human Resources Committee for the full year. For Dr. Carlton and Mr. Notebaert, includes $3,215 and $7,500, respectively, paid for services as members of the Human Resources Committee for part of the year. For Dr. Hudson, compensation includes $16,250 paid for services as chairman of the HR Committee and $25,000 paid for services as Lead Director.

(2) Consists of awards under the Stock Unit Accumulation Plan for Non-Employee Directors in 2011 described below under Director Compensation and Stock Ownership – Stock Unit Accumulation Plan. AEP Stock Units are credited to directors quarterly, based on the closing price of AEP common stock on the payment date. The grant date fair value of these awards for a full year of service was $132,000.

(3) Each non-employee director who served the full year received 3,481.70 AEP stock units in 2011. Messrs. Anderson and Notebaert each received 2,542.60 AEP stock units and Ms. Sullivan received 1,237.62 AEP Stock Units in 2011. Messrs. Brooks and Carlson each received 1,197.82 AEP stock units in 2011. The directors had the following aggregate number of AEP stock units at 2011 year-end: Mr. Anderson (2,574), Mr. Brooks 0, Dr. Carlton (24,897), Mr. Cordes (8,301), Mr. Crosby (20,965), Ms. Goodspeed (21,674), Mr. Hoaglin (15,693), Dr. Hudson (39,779), Mr. Notebaert (2,574), Mr. Nowell (25,108), Dr. Sandor (33,427), Ms. Sullivan (26,212), Ms. Tucker (11,920) and Mr. Turner ( 13,931).

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(4) Consists of premiums for accidental death insurance and annual costs of the Central and South West Corporation Memorial Gift Program and matching gift contributions. The following table presents the components of All Other Compensation for each non-employee director:

Name	Premiums ($)		Memorial Gifts ($)		Matching Gifts ($)(6)
David J. Anderson		494		-0-		-0-
E. R. Brooks		247		Note 5		-0-
Donald M Carlton		247		Note 5		-0-
James F. Cordes		741		-0-		-0-
Ralph D. Crosby, Jr.		741		-0-		-0-
Linda A. Goodspeed		741		-0-		-0-
Thomas E. Hoaglin		741		-0-		-0-
Lester A. Hudson, Jr.		741		-0-		5,000
Richard C. Notebaert		494		-0-		-0-
Lionel L. Nowell III		741		-0-		850
Richard L. Sandor		741		Note 5		-0-
Kathryn D. Sullivan		247		-0-		-0-
Sara M. Tucker		741		-0-		4,000
John F. Turner		741		-0-		-0-

(5) AEP is continuing a memorial gift program for former Central and South West Corporation (CSW) directors and executive officers who had been previously participating in this program. The program currently has 30 participants, including the three former CSW directors listed above. 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 $76,696 on those policies for 2011.

(6) Directors may participate in our Matching Gifts Program on the same terms as AEP employees. Under the program, AEP will match up to $2,500 per institution each year in charitable contributions from a director.

Directors Compensation and Stock Ownership

Annual Retainers and Fees.    The Board has determined that Board compensation should consist of a mix of cash and AEP stock units. The amount of the annual cash retainer paid to non-employee directors was $88,000 annually. The Lead Director fee was $25,000 annually. The fee for the chairman of the Audit Committee was $20,000 annually. Members of the Audit Committee, including the chairman, receive an additional annual retainer of $15,000. The chairman of the HR Committee received an annual fee of $15,000, which was increased to $20,000 as discussed below. Members of the HR Committee, including the chairman, receive an additional annual retainer of $10,000. Each of these cash retainers is paid in quarterly increments.

In September 2011, upon the recommendation of the Committee on Directors and Corporate Governance and taking into account comparative data from Meridian Compensation Partners, LLC, the Board determined that effective April 2012 the Lead Director annual fee should increase from $25,000 to $30,000, and effective October 1, 2011, the annual fee for the Chairman of the HR Committee should increase from $15,000 to $20,000.

As noted above, salaried employees receive no compensation for board service. Thus, Mr. Akins, our current CEO, receives no additional compensation for board service. Similarly, while employed as Executive Chairman through December 31, 2011, Mr. Morris received no additional compensation for serving as a director or as Executive Chairman. Following his January 1, 2012 appointment as Non-Executive Chairman, Mr. Morris has continued to provide support on strategic and public policy issues to the Company. As compensation for his service as Chairman of the Board of Directors, Mr. Morris will receive an additional annual retainer (payable quarterly) of

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$330,000 per year in cash. The retainer is designed to be a reasonable and competitive amount of compensation to pay a retired CEO who continues to serve as Chairman of the Board of Directors. Other compensation matters relating to Mr. Morris’ prior service as CEO and executive chairman are discussed in “Compensation Discussion and Analysis” beginning on page 27.

The Company believes that the standard director compensation amount 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 2011.

Expenses.    Non-employee 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.

Spouses may occasionally join non-employee directors on Company aircraft when a non-employee director is traveling to or from Board meetings or other business activities. The Company generally provides for, or reimburses the expenses of, the non-employee directors and their spouses for attendance at such meetings. The Board has eliminated tax gross-ups on all 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.

Stock Unit Accumulation Plan.    In 2011 the Stock Unit Accumulation Plan for Non-Employee Directors awarded $132,000 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 not paid to the director in cash until termination of service unless the director has elected to further defer payment 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, 2007 through September 1, 2012, has a premium of $48,175.

Stock Ownership.    Non-management directors are required by our Corporate Governance Principles to own AEP common stock or AEP stock units worth five times their annual equity award. Each non-management director is required to hold the stock units they receive under the Stock Unit Accumulation Plan until termination of service. A number of the non-management directors were recently elected to the Board within the last few years.

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Insurance

The directors and officers of AEP and the AEP System subsidiaries 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, 2011 to March 15, 2012, is provided by: Associated Electric & Gas Insurance Services Ltd., Energy Insurance Mutual Ltd., Zurich American Insurance Company, AXIS Insurance Company, Arch Insurance Company, Travelers Casualty and Surety Co. of America, Westchester Fire Insurance Company (ACE), Berkley Insurance Co. , RSUI Indemnity Company, U.S. Specialty Insurance Company (HCC Global), Scottsdale Indemnity Company (Freedom Specialty), Arch Reinsurance, Ltd., National Union Fire Insurance Company (Chartis), Allied World Assurance Company Ltd. (AWAC), Liberty Mutual Insurance Company, Houston Casualty Company (HCC Global), St. Paul Mercury Insurance Company (Travelers), Endurance Risk Solutions Assurance Co. and Catlin Specialty Insurance Company (Catlin, Inc.). The total cost of this insurance is $3,841,538.

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, 2011 to March 15, 2012, is provided by U.S. Specialty Insurance Company, AXIS Specialty Insurance Company, Energy Insurance Mutual Ltd., and Scottsdale Indemnity Company (Freedom Specialty). The total cost of this insurance is $544,277.

Item 2. Proposal to Approve the American Electric Power System Senior Officer Incentive Plan

The Board of Directors proposes that shareholders approve the American Electric Power System Senior Officer Incentive Plan (the “2012 Plan”). The Board of Directors adopted the 2012 Plan on February 28, 2012, subject to the approval of the Company’s shareholders. The 2012 Plan amends and restates the American Electric Power System Senior Officer Annual Incentive Compensation Plan that was last approved by the Company’s shareholders at the Company’s 2007 annual meeting (the “Existing Plan”). The only substantive change from the Existing Plan is the addition of a cash incentive compensation repayment (“claw back”) policy. The HR committee originally adopted a clawback policy in February 2007 and adopted the current version on February 27, 2012. We intend to amend the policy to comply with the additional requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (Dodd-Frank Act) after the SEC adopts new regulations implementing those requirements.

You are being asked to approve the adoption of the 2012 Plan in order to continue to preserve the Company’s federal income tax deduction when payments are made to certain executives based on established performance goals. The Company is seeking to preserve its ability to claim tax deductions for compensation paid to executives to the greatest extent practicable; therefore, the 2012 Plan is intended to comply with the requirements of Section 162(m) of the Internal Revenue Code (“Code Section 162(m)”). Code Section 162(m) limits how much the Company can deduct on its federal income tax return for compensation paid in a taxable year to an individual who, on the last day of the fiscal year, was either (i) the chief executive officer or (ii) among the next three highest-compensated executive officers named in the Summary Compensation Table on page 50 under Compensation Discussion and Analysis – Executive Compensation, excluding the CFO. Compensation that is considered “performance-based compensation” under Code Section 162(m) is not subject to this limit if certain conditions are met. One such condition is that the shareholders initially approve the material terms of the performance goals and re-approve those material terms every five years. Approval of this proposal will ensure that the Company is able to receive tax-deductions for the full amount of performance based compensation paid to officers under the 2012 Plan.

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The more significant features of the 2012 Plan are described below. This summary is subject, in all respects, to the terms of the 2012 Plan, which is attached to this Proxy Statement as Exhibit A.

Administration.    The HR Committee, all of whose members are outside directors, will administer the 2012 Plan. The HR Committee will have the authority to grant awards upon such terms (not inconsistent with the terms of the 2012 Plan) as it considers appropriate. In addition, the HR Committee will have complete authority to interpret all provisions of the 2012 Plan, to adopt, amend and rescind rules and regulations pertaining to the administration of the 2012 Plan and to make all other determinations necessary or advisable for the administration of the 2012 Plan.

Eligibility.    Any person who, during the term of the 2012 Plan, is a corporate officer of the Company or any subsidiary of the Company is eligible to participate under the 2012 Plan. The HR Committee determines which corporate officers will be participants under the 2012 Plan. The Company anticipates that approximately 7 employees will be eligible to receive awards under the 2012 Plan.

Performance Objectives.    2012 Plan participants will receive awards under the 2012 Plan after the end of a fiscal year if certain specified performance objectives are met during such fiscal year. The performance objectives are set by the HR Committee at the start of each fiscal year and are based on one or more of the following performance criteria: (i) earnings measures: primary earnings per share; fully diluted earnings per share; net income; pre-tax income; operating income; earnings before interest, taxes, depreciation and amortization; net operating profits after taxes; income before income taxes, minority interest and equity earnings; income before discontinued operations, extraordinary items and cumulative effect of accounting changes, or any combination thereof; (ii) expense control: operations & maintenance expense; total expenditures; expense ratios; and expense reduction; (iii) customer measures: 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; (iv) safety measures: recordable case rate; severity rate; and vehicle accident rate; (v) diversity measures: minority placement rate and utilization; (vi) environmental measures: emissions; project completion milestones; regulatory/legislative/cost recovery goals; and notices of violation; (vii) revenue measures: revenue and margin; (viii) shareholder return measures: 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; (ix) valuation measures: stock price increase; price to book value ratio; and price to earnings ratio; (x) capital and risk measures: debt to equity ratio and dividend payout as percentage of net income; (xi) employee satisfaction; (xii) project measures: completion of key milestones; (xiii) production measures: generating capacity factor; performance against the Institute of Nuclear Power Operation index; generating equivalent availability; heat rates and production cost. The targeted level or levels of performance with respect to such business criteria may be established at such levels and in such terms as the HR Committee may determine, in its discretion, including in absolute terms, as a goal relative to performance in prior periods (e.g., earnings growth), or as a goal compared to the performance of one or more comparable companies or an index covering multiple companies.

Payment of Awards.    All awards under the 2012 Plan for a fiscal year will be paid in cash following the end of such fiscal year, unless a portion of the award is required to be deferred under the terms of the AEP Stock Ownership Requirement Plan. The maximum individual award that can be made under the 2012 Plan for a fiscal year is the lesser of:

(i) $6,000,000 or

(ii) 400 percent of the corporate officer’s base salary (prior to any deferral elections) as of the date of grant of the award.

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The HR Committee does not currently intend to grant individual awards that approach the maximum allowable amount, but is asking shareholders to approve the maximum amount to preserve flexibility over the next five years.

Amendment and Termination.    The Company has the right, at any time and from time to time, to amend in whole or in part any of the terms and provisions of the 2012 Plan to the extent permitted by law for whatever reason the Company may deem appropriate; provided, however, that any such amendment which requires approval of the Company’s shareholders in order to maintain the qualification of awards as performance-based compensation pursuant to Code Section 162(m)(4)(C) shall not be made without such approval.

Federal Income Tax Consequences.    All cash awards under the 2012 Plan are taxable to the participant when paid. The 2012 Plan has been designed to comply with Code Section 162(m) such that all awards under the 2012 Plan qualify as performance-based compensation and, therefore, the Company will be entitled to claim a federal income tax deduction for the full amount of any cash award paid under the 2012 Plan.

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.

Item 3. Proposal to Ratify Appointment of 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 2012. 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 Company 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 24, 2012. 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 3.

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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, 2011 and December 31, 2010, and fees billed for other services rendered by Deloitte & Touche LLP during those periods.

	2011		2010
Audit Fees(1)	$	11,618,000	$	11,245,000
Audit-Related Fees(2)	$	595,000		664,000
Tax Fees(3)	$	142,000		220,000
TOTAL	$	12,355,000	$	12,129,000

(1) Audit fees in 2010 and 2011 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 tax compliance services. Tax compliance services are services rendered based upon facts already in existence or transactions that have already occurred to document, compute, and obtain government approval for amounts to be included in tax filings.

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.

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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 nine times during the year and held discussions, some of which were in private, with management, the internal auditor, and the independent auditor. 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, 2011. The Audit Committee has reviewed and discussed the consolidated financial statements and internal control over financial reporting with management, the internal auditor, and the independent auditor. The Audit Committee discussed with the independent auditor the matters required to be discussed by the statement on Auditing Standards No. 61, as amended (AICPA, Professional Standards, Vol. 1, AU section 380), as adopted by Public Company Accounting Oversight Board (PCAOB).

In addition, the Audit Committee has received the written disclosures and the letter from the independent auditor required by the applicable requirements of the PCAOB regarding the independent auditor’s communication with the Audit Committee concerning independence and has discussed with the independent auditor the independent auditor’s independence. The Audit Committee has also received written materials addressing the independent auditor internal quality control procedures and other matters, as required by the NYSE listing standards.

In reliance on the reviews and discussions referred to above, the Audit Committee recommended to the Board, and the Board has approved, that the audited financial statements be included in AEP’s Annual Report on Form 10-K for the year ended December 31, 2011, for filing with the SEC.

Audit Committee Members

Lionel L. Nowell, III, Chair

David J. Anderson

Linda A. Goodspeed

Sara Martinez Tucker

John F. Turner

Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Auditor

The Audit Committee’s policy is to pre-approve all audit and non-audit services provided by the independent auditor. 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 auditor and management are required to report to the Audit Committee at each regular meeting regarding the extent of services provided by the independent auditor in accordance with this pre-approval policy, and the fees for the services performed to date. The Audit Committee may also pre-approve particular services on a case-by-case basis. In 2011, all Deloitte & Touche LLP services were pre-approved by the Audit Committee.

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Item 4. Advisory Vote on Executive Compensation

In accordance with the requirements of the Exchange Act (which was added by the Dodd-Frank Act and the related rules of the SEC), we are including in these proxy materials a separate resolution for shareholders to vote upon, on an advisory (nonbinding) 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 Analysis” beginning on page 27 for additional details about the 2011 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 (60 percent) of this long-term compensation to two robust measures of shareholder value:

• Three-year total shareholder return compared to the Electric and Multi-Utilities in the S&P 500, and

• Three year cumulative earnings per share measure 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; and

• Elimination of the reimbursement and tax gross-up for excise taxes triggered under change in control agreements issued to new participants after October 2009.

We are asking our shareholders to indicate their support for our named executive officer compensation as described in this proxy statement. In doing so we ask that our shareholders take into consideration the effect that the CEO transition from Mr. Morris to Mr. Akins, which took place in late 2011 as planned, will have on the compensation for our CEO position. 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 will 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 2012 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.

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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 4.

Other Business

The Board of Directors does not intend to present to the meeting any business other than the election of directors, the approval of the American Electric Power System Senior Officer Incentive Plan, the ratification of the appointment of the independent registered public accounting firm and the advisory vote on the compensation of the named executive officers 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

Highlights for 2011

AEP’s shareholders received a more than 20 percent return on their investment for the year, and the dividend was increased by more than 2 percent during 2011. Favorable weather conditions throughout most of the year, and a 4 percent increase in industrial volume in 2011 led to solid financial performance for the year. AEP settled all legal challenges regarding construction of our John W. Turk Jr. Power Plant in Arkansas, which clears the way for the plant to begin operation in late 2012. In addition, the CEO role and responsibilities were successfully transferred from Mr. Morris to Mr. Akins in late 2011 (effective November 12, 2011).

The Company’s 2011 ongoing earnings were $3.12 per share, which exceeded the midpoint of our earnings per share (EPS) guidance at the start of the year ($3.00 to $3.20). The HR Committee established threshold (0 percent of target payout), target and maximum (200 percent of target payout) points for 2011 annual incentive compensation at $3.00, $3.10 and $3.20 per share, respectively. In setting the $3.10 target, the HR Committee considered the slow economic recovery in our service territory, the potential impact of compliance with pending EPA regulations and potential revenue reductions due to regulatory proceedings in our largest utility (AEP Ohio). This target was a $0.07 (or 2.4 percent) increase from AEP’s 2010 ongoing earnings of $3.027 per share. Throughout this CD&A, we refer to ongoing earnings, which is a non-GAAP financial measure. Exhibit B to this proxy statement contains a reconciliation of GAAP earnings with ongoing earnings for 2011.

AEP’s ongoing 2011 EPS of $3.12 resulted in funding of 119.0 percent of the target award pool for 2011 for all employees. Unfortunately, a fatal employee accident occurred in our River Operations unit in December 2011. Although the cause of this accident is undetermined as of this writing, it was treated as a work related fatality for incentive compensation purposes. Therefore a 10 percent reduction was applied to the annual incentive funding for all officers and all employees in our Fuel, Emissions and Logistics group, which includes River Operations. A 5 percent incentive funding reduction was applied for all other employees. Due to this negative fatality adjustment and the relatively strong performance of our business units against their incentive goals, which reduced the incentive funding available for the corporate officer group, the overall 2011 annual incentive funding for AEP’s executive officers was 97.8 percent of target.

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In 2011, the Company continued to align executive officers’ total compensation opportunity with shareholders’ interests by providing a substantial percentage of the total compensation opportunity in the form of performance-based stock compensation. AEP’s three-year performance unit awards accounted for approximately 39 percent and 26 percent of the total compensation opportunity for Messrs. Morris and Akins, respectively. These performance units are tied to AEP’s three year cumulative EPS and three year total shareholder return relative to the electric utility and multi-utility companies in the S&P 500. An additional 26 percent and 17 percent of the total compensation opportunity for Messrs. Morris and Akins, respectively, was tied to the value of AEP common stock as restricted stock units that vest over a 40 month period.

For 2011, the HR Committee provided 60 percent of the value of long-term incentives in performance units and forty percent of the value in restricted stock units, rather than 100 percent in performance units. This change was made to provide a stronger retention incentive and more market competitive compensation during both up and down cycles. This change also brought AEP’s long-term incentive award mix closer to that of the companies in AEP’s Compensation Peer Group. The restricted stock unit awards included a two year post retirement holding requirement for senior executives who are subject to mandatory retirement, which applied to Messrs. Morris and English for 2011. This post retirement holding period was introduced to mitigate the risk created near the end of an executive’s career when many long-term incentive awards lose some of their capacity to encourage decision making in the long-term interests of the Company.

The cumulative EPS score for the 2009-2011 performance units was below expectations at 85.0 percent of target. The relative total shareholder return measure at the end of the performance period was at the 48th percentile of the comparator group, which produced a score of 94.7 percent of target. The EPS and TSR scores combined to produce an overall score of 89.8 percent of target for the 2009-2011 performance period. As a result, 89.8 percent of the 2009-2011 performance units outstanding at year-end vested.

The HR Committee recognizes that the Company’s executive compensation levels and practices are a subject of interest and potential concern for the Company’s stakeholders, including its shareholders, regulators and customers. As such, the HR Committee regularly reviews best practices in executive compensation and has made the changes it believes are necessary to keep the Company’s executive compensation levels and practices both market competitive and in line with best practices.

Shareholders have an opportunity to cast an annual advisory vote on executive compensation (a “say-on-pay proposal”). At the Company’s annual meeting of shareholders held in April 2011, approximately 96 percent of the votes cast on the say-on-pay proposal at that meeting were voted in favor of this proposal. In accordance with 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 stockholder feedback when establishing compensation programs and making compensation decisions for the named executive officers.

In light of the voting results with respect to the frequency of the advisory vote on executive compensation at the 2011 annual meeting of shareholders, 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 vote on the frequency of the advisory votes on executive compensation. Because the Dodd-Frank Act requires that such advisory votes on frequency 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.

For many years, the Company has had stock ownership requirements for its executive officers, tied a substantial portion of the compensation for its executives to annual and long-term perform-

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ance, and has had a policy that allows the Company to claw back incentive compensation in certain circumstances. In addition, the HR Committee has made several changes to the Company’s executive compensation program in the last several years, including:

• Generally freezing executive salaries for two years (2009 and 2010) and then providing salary increases of 3.2 percent overall for 2011, excluding promotions, which generally kept pace with the rate of salary growth in the market but did not bring AEP’s executive salaries up to current market levels;

• Freezing target annual incentive opportunities for each salary grade, expressed as a percentage of base pay, at the 2008 level for 2009 through November 2011;

• Freezing the target long-term incentive opportunities for each salary grade, expressed as a grant date fair value, at the 2008 level for 2009 through 2011;

• Granting all new 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 a separation from service;

• Eliminating company paid country club memberships;

• Generally eliminating personal use of Company provided aircraft, to the extent that such use has an incremental cost to the Company, except for Mr. Morris who negotiated this as part of his employment agreement. This change applies to Mr. Akins and other executive officers;

• Eliminating most tax gross-ups;

• Eliminating the reimbursement and tax gross-up for excise taxes triggered under change in control agreements issued to new participants after October 2009. Mr. Akins also voluntarily relinquished the reimbursement and gross-up for excise taxes in his change in control agreement. As a result of these changes, the majority of AEP’s change in control agreements (12 of 21) do not provide for the reimbursement and gross-up of excise taxes. In addition, in January 2012 the HR Committee decided that the reimbursement and gross-up for excises taxes will be eliminated from the change in control agreements for any participant who is subsequently promoted, as a condition of such promotion.

Overview

The HR Committee oversees and determines AEP’s executive compensation. The HR Committee makes recommendations to the independent members of the board of directors about the compensation of the Chief Executive Officer, and those independent board members determine the CEO’s compensation.

AEP’s executive compensation programs are designed to:

• Attract, retain, motivate and reward a superb leadership team for both outstanding team and individual performance with market competitive compensation and benefits;

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

• Emphasize performance-based compensation over base salary by providing a substantial portion of executive officers’ total compensation opportunity in the form of incentive compensation;

• Align the interests of the Company’s 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 that has a value linked to the total return on AEP’s common stock and, with respect to performance units, other shareholder return measures;

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

• Promote the stability of the management team by creating strong retention incentives with multi-year vesting schedules for long-term incentive compensation, and requiring executives to meet stock ownership requirements.

Overall, AEP’s executive compensation program is intended to create a total compensation opportunity that, on average, is equal to the median of AEP’s Compensation Peer Group, as described under Compensation Peer Group on page 31. The HR Committee’s independent compensation consultant, Pay Governance, LLC (Pay Governance) participates in HR Committee meetings, assists the HR Committee in developing the compensation program and has an opportunity to meet with the HR Committee in executive session without management present. See the Human Resources Committee Report on page 47 for additional information about the independence of Pay Governance’s advice to the HR Committee.

Compensation Program Design

The compensation program for executive officers includes base salary, annual incentive compensation, long-term incentive compensation, a comprehensive benefits program and minimum perquisites. The HR Committee 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 ongoing earnings per share target with other objectives, such as safety.

The HR Committee has chosen ongoing earnings per share as the funding measure for the annual incentive plan for many years because it largely reflects management’s performance in operating the Company, is 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. The EPS measure is also well understood by both our shareholders and employees. Management and the HR Committee also believe that EPS growth is the primary means for the Company to create long-term shareholder value.

The majority of AEP’s long-term incentive compensation (60 percent) is tied to longer-term shareholder return objectives to maintain an appropriate focus on creating sustainable long-term shareholder value. The HR Committee awarded performance units to executive officers with three-year performance measures tied to AEP’s total shareholder return, relative to all the electric and multi-utility companies in the S&P 500 Index, and cumulative earnings per share relative to a board approved target. A cumulative earnings measure was chosen to ensure that the total earnings for all three years contribute equally to the award calculations. The HR Committee also chose 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 period relative to other large companies in our industry.

The HR Committee also uses long-term incentives as a retention tool to foster management continuity. The performance unit awards described above are subject to a three-year vesting period. In addition, effective January 1, 2011, the HR Committee granted 40 percent of the annual grant date value of AEP’s long-term incentive awards in the form of restricted stock units (RSUs). These RSUs vest over 40 months in three approximately equal components on the May 1^st following the first, second and third anniversaries of the grant date.

The HR Committee annually reviews the mix of base salary, annual incentive and long-term incentive compensation opportunity provided to executives. For 2011, 84 percent of the total compensation opportunity for Mr. Morris and at least 70 percent of that for the other named execu-

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tive officers was at risk in the form of incentive compensation and stock based compensation. Because the transition of CEO responsibilities from Mr. Morris to Mr. Akins occurred late in 2011, Mr. Akins’ first stock award at the CEO level was granted in 2012. This stock award increased the portion of Mr. Akins’ total compensation opportunity that is at risk to 86 percent. More than 65 percent of the 2011 target compensation opportunity for Mr. Morris and between 43 percent and 60 percent of that for the other named executive officers is in the form of long-term, stock based incentive compensation. The ultimate value that executives realize from that compensation opportunity is therefore closely linked to AEP’s share price and dividends.

The HR Committee targets the total compensation opportunity for executives within a range of plus or minus 15 percent of the median of the Compensation Peer Group, which is the range of compensation that is generally considered to be market competitive by the HR Committee’s independent compensation consultant. The HR Committee chose the median as a target because it corresponds to the Company’s near median position within the Compensation Peer Group for various size measures, such as revenue, number of employees, and total assets. To the extent that the total compensation opportunity for an executive is above or below the +/- 15 percent target range around the peer group median, the HR Committee adjusts elements of pay over time to bring their total compensation opportunity into the market competitive range. The HR Committee’s independent compensation consultant completes an annual executive compensation study. In October 2011, this study found that, in aggregate, executive base salaries, total cash compensation (base salary and annual incentive compensation) and total direct compensation (total cash compensation and long-term incentives) were within the market competitive range and less than the market median.

Compensation Peer Group

The HR Committee 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. This Compensation Peer Group is reviewed annually by the HR Committee in consultation with its independent compensation consultant. The companies included in the Compensation Peer Group are chosen from utility industry and general industry companies that are comparable in size to AEP in terms of revenues, total assets, market capitalization, number of employees and business complexity. In addition the HR Committee considers one and three year total shareholder return of potential industrial companies in selecting the peer group.

The Compensation Peer Group is selected to consist of an approximately equal number of utility and industrial companies. The utility companies are selected to provide a more direct comparison to companies with businesses similar to AEP’s. The HR Committee includes industrial companies outside the utility industry because AEP must also compete with industrial companies to attract and retain executives. In addition, because AEP is one of the largest U.S. utility companies based on assets and employees, the industrial companies are included in the peer group to increase the median level of assets and employees of the peer group to a level similar to AEP.

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For 2011 the Compensation Peer Group consisted of the 14 large and diversified utility industry companies and the 12 general industry companies shown in the table below. The Compensation Peer Group has not changed for the past three years.

AEP’s Compensation Peer Group

Energy (14 Companies)	General Industry (12 Companies)
Centerpoint Energy, Inc.	3M Company
Constellation Energy Group, Inc.	Bristol-Myers Squibb Company
Dominion Resources, Inc.	Caterpillar Inc.
Duke Energy Corporation	CSX Corporation
Edison International	Goodyear Tire & Rubber Company
Entergy Corporation	Northrop Grumman Corporation
Exelon Corporation	PPG Industries, Inc.
FirstEnergy Corp.	Schlumberger N.V.
NextEra Energy, Inc.	Sunoco, Inc.
PG&E Corporation	Textron Inc.
Public Service Enterprise Group Inc.	Union Pacific Corporation
Sempra Energy	Weyerhaeuser Company
Southern Company (The)
Xcel Energy Inc.

The table below shows that, at the time the Compensation Peer Group data was collected in July 2011, AEP’s revenue, market capitalization, number of employees and three year total shareholder return were all near the 50^th percentile of the combined peer group, while AEP’s Total Assets were above the 75^th percentile.

2011 Compensation Peer Group

	Revenue ($ million)		Total Assets ($ million)		Market Capitalization ($ million)		Employees		Total Shareholder Return
									1 Year			3 Year
Summary Statistics
Compensation Peer Group
25th Percentile	$	11,564	$	21,930	$	11,687		13,691		11	%		-4	%
50th Percentile	$	14,156	$	31,249	$	16,697		19,319		18	%		3	%
75th Percentile	$	18,785	$	45,901	$	28,798		36,725		26	%		9	%
Utility Industry Median	$	13,376	$	40,751	$	16,528		14,824		14	%		-1	%
General Industry Median	$	19,158	$	29,149	$	21,868		41,404		25	%		-4	%
AEP	$	14,427	$	50,455	$	17,777		18,712		8	%		3	%

The HR Committee’s independent compensation consultant annually provides the HR Committee with an executive compensation study covering all executive officer positions and many other executive positions based on survey information for the Compensation Peer Group. The methodology and job matches used in this study were 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 compensation paid by the Compensation Peer Group. The HR Committee’s independent compensation consultant uses other benchmarks if, in their judgment, such other benchmarks provide a better comparison based on the specific scope of the job being matched. Broader energy and general industry data is used when sufficient data is not available in the Compensation Peer Group to provide a comparison, as was the case in 2011 for Mr. Akins’ and Mr. Powers’ positions. In 2011, Pay Governance used the 75^th percentile of the utility peers as the market benchmark for Mr. Powers’ position to provide a better comparison to the size and scope of his responsibilities, which are specific to the utility industry. This position (President AEP Utilities) had responsibility for a substantially larger organization than the median of the Compensation Peer Group so the 75^th percentile was used to provide a more similar compensation benchmark. In 2011, the HR Committee’s independent compensation consultant also matched Mr. Akin’s position to the median for the second highest paid executive among the General Industry companies because this match was not available in AEP’s Compensation Peer Group.

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Executive Compensation Program Detail

Executive Compensation Component 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 number of promotional salary increases occurred in 2011 due to AEP’s CEO transition as described below under Base Salary on page 35. •    A 3.2 percent executive merit budget was approved by the HR Committee for 2011 for all AEP executives and other merit eligible employees. •    Merit budgets are generally set by management with HR Committee oversight, based on surveys of past and expected future salary increase trends, the competitiveness of AEP’s salaries to market survey information for similar positions and the extent to which the company can afford to provide merit increases while meeting investor earnings expectations. •    Merit and other salary increases are awarded by the HR Committee based on: •     The Company’s merit budget, •     Sustained individual performance and competencies as assessed by each executive’s direct manager with input from other senior managers and communicated via written evaluations, performance ratings and merit increase recommendations, •     The market competitiveness of the executive’s salary, •     Internal comparisons, •     The responsibilities, experience and future potential of each executive officer, •     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.

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Component	Purpose	Key Attributes
Annual Incentive Compensation	•    To intensify executive officer focus on annual performance objectives that are critical to AEP’s success. •    To communicate these critical annual performance objectives throughout the Company in a way that distinguishes them from other objectives and makes their importance clear to all. •    To communicate and align executive and employee efforts to the Company’s earnings and operational performance objectives. •    To link compensation to performance measures in four categories for 2011: •    Safety and health, •    Operations, •    Regulatory, and •    Strategic initiatives.	•    Annual incentive targets are established by the HR Committee based on competitive compensation information provided by the HR Committee’s compensation consultant. •    From year to year, actual awards generally may vary within a range of from 0 percent to 200 percent of each executive’s annual incentive target. •    Ongoing earnings per share (EPS) was again chosen as the funding measure. •    For 2011, an ongoing EPS threshold was established that provided annual incentive funding only if the Company’s EPS exceeded $3.00. •    Individual awards are then determined by the HR Committee based on: •    Each executive’s calculated annual incentive opportunity, and •    A subjective evaluation of their 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 executive compensation directly to shareholder returns. •   To help ensure that Company management remains focused on longer-term results, which the HR Committee considers to be essential given the large long-term investments in physical assets required in our business. •   To reduce executive turnover and maintain management consistency.	•   The HR Committee provided long-term incentive awards in the form of three-year performance units, which were 60 percent of the grant value, and restricted stock units (RSUs), which were 40 percent of the grant value. •   The HR Committee establishes award guidelines for each executive salary grade based on total compensation practices for similar positions in AEP’s Compensation Peer Group. •   Again for the 2011-2013 performance unit awards, the HR committee established the following equally weighted performance measures: •    Three-year cumulative earnings per share relative to a board approved target, and •    Three-year total shareholder return relative to the electric and diversified utilities in the S&P 500. •   Individual long-term incentive awards are based on: •    Award guidelines for each salary grade established by the HR Committee, •    Market competitive compensation levels, and •    Individual performance.

Base Salary.    Having frozen executive salaries, except for promotional increases, for 2009 and 2010 due to extremely difficult economic conditions, the HR Committee approved a 3.2 percent merit budget for 2011 for executives and other employees. This increase was close to market median salary survey projections at the time. In addition, three executive officers were promoted at the beginning of 2011. Mr. Akins was promoted to AEP President and his salary was increased to $750,000 in connection with his selection as the successor CEO to Mr. Morris. In addition, the salary grades for Mr. Tierney’s and Mr. Powers’ positions were both increased to $600,000 in connection with a salary grade increase for their positions.

Effective November 12, 2011, in connection with AEP’s CEO transition, Mr. Akins was promoted to President and CEO at a salary of $900,000 and Mr. Powers was promoted to EVP and Chief Operating Officer at a salary of $650,000. On this date Mr. Morris also became Executive Chairman. Mr. Morris subsequently retired from AEP employment on December 31, 2011 but is continuing his service to the Company as Chairman of the Board of Directors. Mr. Tierney’s salary

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was also increased by 2.1 percent on November 12, 2011 to $612,333. Due to the promotions described above and the retirements of Messrs. Morris, English and Miller and Ms. Tomasky, Mr. Tierney was the only executive officer named in the summary compensation table to receive a salary increase during AEP’s annual executive salary review process. He received a combined merit increase and market adjustment to a salary of $650,000, effective January 1, 2012.

Annual Incentive Compensation.

Annual Incentive Targets.    The HR Committee, in consultation with its independent compensation consultant and Company management, establishes the annual incentive targets for each executive officer primarily based on compensation benchmark studies. For 2011 the HR Committee established the following annual incentive targets for each of the positions held by the named executive officers:

• 115 percent of base earnings for both the Chairman and CEO position and the Executive Chairman positions (Mr. Morris);

• 95 percent of base earnings for the President position, which Mr. Akins held from January 1 through November 11 of 2011, and 110 percent of base earnings for the President and CEO position, which Mr. Akins held for the remainder of the year;

• 75 percent of base earnings for the CFO position for the period January 1 through November 11 of 2011 and 80 percent of base earnings for this position for the remainder of the year (Mr. Tierney);

• 75 percent of base earnings for the President – AEP Utilities position for the period January 1 through November 11 of 2011 and 80 percent of base earnings for the EVP and Chief Operating Officer position for the remainder of the year (Mr. Powers);

• 75 percent of base earnings for the Vice Chairman position (Mr. English);

• 65 percent of base earnings for the SVP, General Counsel and Secretary position (Mr. Miller); and

• 70 percent of base earnings for the President AEP Transmission position (Ms. Tomasky).

Funding For Annual Incentive Plan.    In 2011 AEP produced ongoing EPS of $3.119, which was above the midpoint of AEP’s earnings guidance at the beginning of the year. This resulted in annual incentive funding of 119.0 percent of the target award pool for all employees. This result was calculated by interpolation between a 100 percent of target payout at EPS of $3.10 and a 200 percent of target payout at EPS of $3.20. Because the Company experienced a fatal employee accident, a 10 percent reduction was applied to the annual incentive funding for all officers. As a result of the negative fatality adjustment and the relatively strong performance of our business units against their incentive goals, which reduced the incentive funding available for the corporate officer group, the overall annual incentive funding for AEP’s executive officers was 97.8 percent of target for 2011.

For 2011, GAAP earnings per share reported in AEP’s financial statements was $0.90 per share higher than ongoing earnings, primarily because of a Texas Supreme Court decision resulting in a net-of-tax favorable adjustment related to recovery of stranded costs in Texas. Exhibit B to this proxy statement contains a reconciliation of ongoing and GAAP EPS.

Annual Performance Objectives.    For 2011, the HR Committee developed a balanced scorecard to tie annual incentive awards for AEP’s executive team to the company’s performance objectives for the year in four areas of performance: safety, operations, regulatory and strategic initiatives. The HR Committee uses this balanced scorecard because it mitigates the risk that executives will focus on one or a few overriding objectives, such as short term financial perform-

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ance, to the detriment of other objectives. The weightings of those targets are determined by the HR Committee. The threshold, target and maximum payout levels are determined by the HR Committee and are set forth with 2011 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)
FUNDING - Ongoing EPS	NA	$3.00	$3.10	$3.20	$3.119	119.0%
Deductions
Fatality Adjustment	NA	+10% of composite score for year without a fatality or -10% (20% swing) if there is a fatality			1 fatality	-10% (-.110)
PERFORMANCE
Safety
Recordable Case Rate (the number of Occupational Safety and Health Administration recordable incidents per 200,000 work hours)	10%	1.12	0.97	0.84	1.00	80.08%
Severity Rate (the number of lost and restricted duty days due to Occupational Safety and Health Administration recordable incidents per 200,000 work hours)	15%	22.94	19.94	17.34	23.07	0.0%
Contractor Recordable Case Rate (the number of Occupational Safety and Health Administration recordable incidents per 200,000 work hours for major AEP contractors)	5%	1.95	1.7	1.44	1.52	169.2%
Operations
Wires Reliability – SAIDI (System Average Incident Duration Index, excluding major storm days)	15%	198.2 minutes	188.8 minutes	179.4 minutes	227.9 minutes	0.0%
Generating Fleet Availability – Effective forced outage rate (EFOR) relative to budget	10%	12.11%	10.61%	9.61%	9.03%	200.0%
Planned Generating Plant Outage Performance	5%	65%	75%	90%	81.0%	140.0%
Regulatory
Rate Recovery – The score for this measure is determined subjectively by the HR Committee based on: •  Progress towards Transco approvals and successful achievement of regulatory objectives in other filings, and •  The total dollar value of improvement in AEP’s rate recovery vs. the total 2011 budget for rate recovery	20%	This is a subjective measure scored at 1.5 because rate recovery exceeded target, and we succeeded in obtaining regulatory approvals for Transcos in several jurisdictions.			Not Applicable	150%
Strategic Initiatives
Turk Plant Completion Progress – The score for this measure is determined subjectively by the HR Committee based on: •  Achievement of major 2011 objectives for the Turk Plant, including timely and successful completion of construction milestones, permitting, public outreach, and communications	10%	This is a subjective measure scored at 2.0 because we settled all legal challenges regarding the Turk Plant allowing for completion of its construction.			Not Applicable	200.0%
Transmission Project Earnings	5%	90% of Budget	100% of Budget	110% of Budget	121% of Budget	200.0%
Strategic Initiative Milestones – The score for this measure is determined subjectively by the HR Committee based on specific milestones related to the development of transmission investment opportunities	5%	This is a subjective measure scored at 2.0 because the development of our transmission business and related capital investment substantially exceeded targets.			Not Applicable	200.0%

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Safety.    With safety as an AEP core value, maintaining the safety of AEP employees, customers and the general public is always our primary consideration. Accordingly, safety measures comprised 30 percent of the 2011 scorecard. We measure this using employee and contractor recordable case rate in accordance with the methodology prescribed by the Occupational Safety and Health Administration (OSHA) for recordable incidents. We also measure the incident severity rate portion 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 adjustment for 2011, which is discussed below.

Operations.    The HR Committee tied 30 percent of the scorecard to the operating performance of AEP’s assets. This category measures the reliability of our wires assets, the equivalent forced outage rate for our generating plants and our performance on planned generating plant outages. The reliability measure is the system average incident duration index (SAIDI), which is a standard measure in our industry. The equivalent forced outage rate is an indicator of the extent to which our plants ran reliably during the year.

Regulatory.    Investments in our business depend on obtaining satisfactory and appropriate rates of return on our regulated businesses in all the jurisdictions in which we operate. Therefore, the HR Committee tied 20 percent of the scorecard to AEP’s overall success in achieving rate recovery in regulatory proceedings at the Federal Energy Regulatory Commission and state public utility commissions. In 2011, AEP secured over $235 million in additional rate recovery related to increased costs and approved increases in the Company’s rate base.

Strategic Initiatives.    The remaining 20 percent of the executive council scorecard was tied to strategic initiatives for 2011, which were progress towards completion of the Turk Plant (10 percent), Transmission Project Earnings (5 percent) and milestones primarily related to development of transmission investment opportunities (5 percent).

The above balanced scorecard goals were maintained throughout the year and produced an overall score of 113.5 percent of target for 2011 before application of the EPS Funding Factor and Deductions as described below.

EPS Funding Factor.    In order to allocate the award pool created by AEP’s EPS to each incentive group (typically a business unit or operating company), the resulting scores are divided by the weighted average performance score for all groups. For 2011 the average performance score for all groups in AEP’s annual incentive compensation program was 124.2 percent of target. The maximum EPS and Gross Composite scores are 200.0 percent of target. The chart below shows the calculation of the overall performance score for the named executive officers.

Scorecard Result			EPS Score				Average Performance Score		Gross Composite Score
	113.5%	×		119.0	%	÷	124.2%	=		108.7	%

Deduction.    The HR Committee established a fatality adjustment for 2011 that would have added 10 percent of the Gross Composite Score above in the event of a fatality free year or deducted 10 percent in the event of a fatal work-related employee accident. Unfortunately, a fatal employee accident occurred in our River Operations unit in 2011. The impact of the fatality deduction is shown in the table below:

Overall Performance Score			Fatality Deduction				Final Performance Score
	108.7%	-		10.9	%	=	97.8%

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2011 Individual Award Calculations.    The calculated annual incentive opportunity is shown in the chart below for each named executive officer. The annual incentive award opportunity for executives who had promotions in the year is the sum of the pro rata opportunities they had for the year. This is the starting point for determining annual incentive awards. The HR Committee then evaluates the individual performance of each named executive officer to determine the actual awards, which are also shown in the table below for 2011.

Name	2011 Base Earnings			Annual Incentive Target %				Final Performance Score				Calculated Annual Incentive Opportunity		2011 Actual Awards
Michael G. Morris	$	1,304,702	x		115	%	x		97.8	%	=	$	1,467,398	$	1,500,000
Nicholas K. Akins	$	658,896	x		95	%	x		97.8	%	=	$	612,180
	$	103,846	x		110	%	x		97.8	%	=	$	111,718
												$	723,898	$	750,000
Brian X. Tierney	$	528,173	x		75	%	x		97.8	%	=	$	387,415
	$	70,654	x		80	%	x		97.8	%	=	$	55,280
												$	442,695	$	450,000
Robert P. Powers	$	529,258	x		75	%	x		97.8	%	=	$	388,210
	$	75,000	x		80	%	x		97.8	%	=	$	58,680
												$	446,890	$	450,000
Carl L. English	$	574,738	x		75	%	x		97.8	%	=	$	421,571	$	421,571
D. Michael Miller	$	409,808	x		65	%	x		97.8	%	=	$	260,515	$	260,515
Susan Tomasky	$	312,912	x		70	%	x		97.8	%	=	$	214,219	$	214,219

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 column above, but should instead be adjusted from this starting point to reflect each executive’s individual performance and contribution. Based on recommendations from each executive officer’s manager focusing on the subjective evaluation of their individual performance and contribution, particularly with respect to the executive council scorecard goals, the HR Committee approved the annual incentive awards shown in the Actual Awards column for 2011.

Long-Term Incentive Compensation.    AEP annually reviews the mix of long-term incentive compensation it provides its executives. For the 2011 award cycle, the HR Committee granted 60 percent of the grant date value of long-term incentive awards as performance units and 40 percent of this value as restricted stock units (RSUs). This was a change from past practice in which the HR Committee granted 100 percent of the grant value of its annual long-term incentive awards as performance units. RSUs were added to:

• Better reflect the mix and diversity of long-term incentive awards provided by the companies in AEP’s Compensation Peer Group, and

• Provide a more consistent retention incentive during periods of economic instability.

Both the 2011 performance unit and restricted stock unit awards were granted with change in control provisions that include a double trigger that provides earlier vesting of awards only if both a change in control and a separation from service under defined circumstances occurs. The restricted stock unit awards granted for 2011 also included a two year post-retirement holding requirement for senior executives who are subject to mandatory retirement, which included Messrs. Morris and English in 2011.

The HR Committee grants long-term incentive awards on an annual year-end award cycle. It is a long-standing HR Committee practice to consider the impact of any recent and upcoming Company announcements and financial disclosures that may impact AEP’s share price, as well as

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AEP’s current stock price itself, when determining the number of shares, units or options to grant under AEP’s long-term incentive program.

The HR Committee establishes award guidelines for each executive salary grade based on market competitive total compensation for similar positions in AEP’s Compensation Peer Group. Individual long-term incentive awards are determined 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 salary grade established by the HR Committee, which creates an overall award pool that AEP management and the HR Committee use in determining awards,

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

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

• The executive officer’s future potential for advancement.

The HR Committee also regularly reviews tally sheets for the named executive officers 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. The tally sheets also show whether the value that executive officers have already received from vested equity awards is so large as to significantly reduce the need for or effectiveness of any future equity awards. The HR Committee may reduce equity awards to any or all executives if they were to find that any of these considerations or any other consideration warrant doing so.

Performance Units.    The HR Committee granted performance unit awards for a 2011 – 2013 performance period to each named executive officer shown in the 2011 Long-Term Incentive Award table below. Dividends are reinvested in additional performance units, but those additional performance units are subject to the same performance measures and vesting requirments 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; however, the maximum score for each performance measure is 200 percent. For further information on these awards, see the description under 2011 Stock Award Grants beginning on page 53.

Performance Measures for 2011 – 2013 Performance Units

Performance Measure	Weight			Threshold Performance	Target Performance	Maximum Payout Performance
3-Year Cumulative Earnings Per Share		50	%	$8.73 (30% payout)	$9.70 (100% payout)	$10.67 (200% payout)
3-Year Total Shareholder Return vs. S&P Electric and Multi-Utilities		50	%	20th Percentile (0% payout)	50th Percentile (100% payout)	80th Percentile (200% payout)

On December 31, 2011 performance units granted for the 2009 – 2011 performance period vested. The combined score for the 2009-2011 performance period was 89.8 percent of target. See page 58 under the Option Exercises and Stock Vested Table for additional information about the vesting of these performance units.

Restricted Stock Units.

The HR Committee also granted 40 percent of the grant date value of the company’s 2011 long-term incentive awards as RSUs. These RSUs vest over a forty month period, subject to the execu-

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tive’s continued employment, in three approximately equal installments on May 1, 2012, May 1, 2013 and May 1, 2014, respectively. Dividends are reinvested in additional RSUs, but those additional RSUs vest at the same time as the underlying RSUs vest. For further information on these awards, see the description under 2011 Stock Award Grants beginning on page 53.

2011 Long-Term Incentive Awards

Name	Number of Performance Units Granted		Number of Restricted Stock Units Granted		Total Units Granted
Mr. Morris		90,000		60,000		150,000
Mr. Akins		19,026		12,684		31,710
Mr. Tierney		20,328		13,552		33,880
Mr. Powers		19,026		12,684		31,710
Mr. English		25,410		16,940		42,350
Mr. Miller		15,246		10,164		25,410
Ms. Tomasky		16,938		11,292		28,230

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 salary grade as of December 2010. Mr. Akins’ first long-term incentive award at the President and CEO level occurred in January 2012.

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 senior executives (47 individuals as of December 31, 2011) 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 salary grade and periodically adjusts these levels. Executives are generally expected to achieve their stock ownership requirement within five years.

AEP’s stock ownership requirements are specified as a fixed number of shares and share equivalents for executives in each salary grade. As of November 2011 the value of AEP’s stock ownership requirements were equal to 3.6 times the salary range midpoint for the CEO, 3.0 times the salary range midpoint for the CFO and COO positions, and 2.4 times the salary range midpoint for AEP’s General Counsel position. The highest minimum stock ownership requirement assigned to each of the named executive officers, except Ms. Tomasky who retired on July 31, 2011, and their holdings at December 31, 2011, are shown in the table below.

Name	Highest Minimum Stock Ownership Requirement as  of 12/31/2011 (Shares)		AEP Stock and Share Equivalent Holdings on 12/31/2011
Mr. Morris(1)		109,300		452,082
Mr. Akins(2)		35,300		94,704
Mr. Tierney(2)		52,700		114,660
Mr. Powers(2)		52,700		122,955
Mr. English(1)		62,900		95,252
Mr. Miller(1)		35,300		32,130

(1) AEP’s Stock ownership requirements ceased to apply for Messrs. Morris, English and Miller effective January 1, 2012 due to their December 31, 2011 retirement.

(2) The stock ownership requirement for Messrs. Akins, Tierney and Powers were increased, effective January 1, 2012 to 109,300, 62,900 and 62,900, respectively.

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If a participant has failed to meet their minimum stock ownership requirement, that executive’s performance units are mandatorily deferred into AEP Career Shares to the extent necessary to meet such requirement. AEP Career Shares are phantom stock units whose rate of return is equivalent to the total return on AEP stock with dividends reinvested. In addition, to the extent an executive has not met their minimum stock ownership requirement within five years of the date it was assigned, the executive is subject to mandatory deferral into AEP Career Shares of up to 50 percent of their annual incentive compensation award. AEP Career Shares are not paid to participants until after their AEP employment ends.

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.

AEP’s named executive officers participate in the same pension and savings plans as other eligible employees. These include tax-qualified and non-qualified defined contribution and defined benefit plans, as well as a Stock Ownership Requirement Plan that AEP maintains to provide a tax deferred method for senior executives to meet their minimum stock ownership requirements. AEP’s non-qualified retirement benefit plans 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, or a similar value of other compensation or benefits, is a part of a market competitive total rewards package.

The non-qualified plans also provide contractual benefits such as the starting balance credit of $2,100,000 and an increased credit rate under AEP’s pension program that Mr. Morris negotiated as part of his employment contract when he joined AEP. The increased pension benefits were provided to Mr. Morris to replace pension benefits that he otherwise could have earned from his prior employer. To offset pension benefits that they would have been able to earn from prior employers due to their length of service to those companies, Mr. Powers negotiated additional years of credited service and Mr. English negotiated an increased crediting rate in AEP’s non-qualified pension plan. No additional retirement benefits were provided to Mr. Akins as the result of his promotion to President and CEO. Ms. Tomasky also negotiated 20 years of additional service credit under AEP’s pension program in addition to her actual years of service with AEP.

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.

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For executives who relocate, it is AEP’s practice to offer relocation assistance to offset their moving expenses. This policy enables AEP to obtain high quality new hires and to relocate internal candidates as needed. None of AEP’s executive officers relocated in 2011.

Perquisites.    AEP provides limited perquisites that help executives conduct Company business. The HR Committee annually reviews the perquisites provided by the Company to ensure that they are efficient and effective uses of AEP’s resources. The HR Committee also periodically reviews the value of perquisites provided to each named executive officer.

During 2011 the Company provided personal use of corporate aircraft to Mr. Morris. While corporate aircraft provide enhanced security, travel flexibility and reduced travel time, which benefits the Company, the HR Committee is also 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, except for Mr. Morris, who negotiated the use of corporate aircraft for personal travel as part of his employment agreement. However, the HR Committee has offset Mr. Morris’ compensation opportunity by an amount approximating the incremental cost to the Company of his personal use of corporate aircraft above that of other CEOs in AEP’s Compensation Peer Group. This benefit expired with Mr. Morris’ retirement and has not been provided to Mr. Akins. Taxes are withheld on the value of executive personal use of corporate aircraft in accordance with IRS standards. AEP does not provide a gross-up for these taxes.

The Company allows spouses to accompany executives on business trips using corporate aircraft if there is no incremental cost to the Company. Taxes are withheld on the value of executive spouse travel on corporate aircraft in accordance with IRS standards, and AEP does not provide a gross-up for these taxes.

AEP provides executives with 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 financial counseling and tax preparation services. AEP does not provide a gross-up for these taxes.

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.

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Role of the CEO with Respect to Determining Executive Compensation.    The HR Committee has invited the CEO and all directors to attend HR Committee meetings. The HR Committee regularly holds executive sessions without the CEO or other management present to provide a confidential avenue for any concerns to be expressed. The Chairman of the Board and the HR Committee Chairman have the authority to call meetings of the HR Committee.

The CEO has assigned AEP’s Senior Vice President – Shared Services, Vice President – Human Resources and Director – Compensation and Executive Benefits to support the HR Committee. These individuals work closely with the HR Committee Chairman, the CEO and the Committee’s independent compensation consultant (Richard Meischeid of Pay Governance, LLC) 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 in keeping with the objectives established by the HR Committee. The management supporting the HR Committee also meets with the CEO, the HR Committee Chairman and Mr. Meischeid prior to meetings to review and finalize the meeting agenda and meeting materials.

The CEO regularly discusses his strategic vision and direction for the Company during HR Committee meetings with Mr. Meischeid in attendance. Likewise, Mr. Meischeid 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 dialog and exchange of ideas is important to the development and implementation of a successful executive compensation strategy. Neither Mr. Morris nor Mr. Akins obtained any outside compensation consulting services with respect to AEP’s executive compensation and benefits.

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 all employment offers for executive officer positions require the approval of the HR Committee.

Change In Control Agreements.    The HR Committee provides change in control agreements to all the named executive officers to help align the interests of these executives with those of AEP’s shareholders by mitigating the financial impact if their employment is 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 in the course of a lengthy and stressful possible corporate transaction would be critical to the successful completion of a change in control. As of December 31, 2011 there were 21 executives who have change in control agreements.

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 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 executive compensation consultant, the HR Committee periodically reviews change in

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control agreement practices for similar companies, including the 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 executive officers. Therefore, the HR Committee approved change in control multiples of 2.99 times base salary and bonus for all of the named executive officers. Most of the other executives covered by change in control agreements have a lesser multiple of 2.0 times their base salary and target annual incentive award. All of our change in control agreements have a “double trigger,” which is a change in control accompanied by an involuntary termination or constructive termination within two years.

If the payments made to a named executive officer on account of his or her termination exceed certain amounts, the Company may not be able to deduct the payments for federal income tax purposes and the named executive officer could be subject to a 20 percent excise tax on such payments. The excise tax is in addition to the executive’s regular payroll and income taxes. Participants with change in control agreements prior to November 2009, other than Mr. Akins, receive a payment that offsets the effect of the excise tax with a “gross-up” payment that reimburses executives for the excise tax on an after tax basis. However, the total benefit that an executive would receive by reason of the change in control will be reduced by up to 5 percent, if that reduction would avoid the excise tax. The gross-up payment to reimburse the executive for these excise taxes is no longer being included in change in control agreements entered into with new participants after October 2009. Mr. Akins voluntarily relinquished the reimbursement and gross-up for excise taxes in his change in control agreement in January 2012. The HR Committee also determined in January 2012 that change of control participants will become ineligible for the potential reimbursement of excise taxes and gross up payment if they are promoted, as a condition of such promotion.

In the event of a change in control, a pro-rata portion of outstanding performance units for performance periods beginning before 2011 would vest and would be paid at a target performance score. For performance periods beginning on or after January 1, 2011, a double trigger was added. This double trigger requires the termination of a participant’s employment under defined circumstances within one year after a change in control, in which case a pro-rata portion of their outstanding performance unit awards will vest and be paid at the target performance score.

All outstanding restricted stock unit awards granted effective December 7, 2010 vest in the event of a change in control. A double trigger was also added to restricted stock unit awards granted on or after this date. This double trigger requires that a participant’s employment be terminated under defined circumstances within one year after a change in control, in which case all of their outstanding restricted stock units will 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 a participant’s employment is terminated due to a consolidation, restructuring or downsizing as described below.

Other Employment Separations.    AEP maintains a 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 employees include outplacement services and access to health benefits at a reduced net cost 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; severance attributed to restructuring, consolidation or downsizing; or death.

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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. Messrs. Morris, English, Powers, and Miller were retirement eligible in 2011 and Ms. Tomasky retired from the Company on July 31, 2011.

A prorated portion of outstanding performance units would also vest to a participant’s heirs in the event of their death.

In 2011, 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.

Insider Trading and Hedging.    The Company maintains an insider trading policy that prohibits directors and officers from directly 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 officers from placing AEP stock in margin accounts without the approval of the Company. The Company is unaware of any executive officer who has attempted to directly or indirectly hedge the economic risk associated with minimum stock ownership requirements. The Company is also not aware of any executive officer or director who has pledged or otherwise encumbered their shares of AEP stock.

Tax Considerations.    Section 162(m) of the Internal Revenue Code 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 paid named executive officers, other than the Chief Financial Officer. The HR Committee considers the limits imposed by Section 162(m) when designing compensation and benefit programs for the Company and its executive officers. Because the annual incentive compensation awarded in 2011 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, its deductibility is not subject to the Section 162(m) limit. 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 2011 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 for tax deductibility by the Company under section 162(m) of the Internal Revenue Code. In no case did the annual incentive awards paid for 2011 exceed the maximum award provided under the SOIP.

Amounts paid to the named executive officers for vested performance units, which were granted under the shareholder approved Long-Term Incentive Plan, also are not subject to the deductibility limit because they are performance based.

AEP’s restricted shares and restricted stock units are not considered to be performance based under Section 162(m). Therefore, any amounts attributable to those restricted shares and units are not tax deductible if and to the extent that they cause the compensation of the covered 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 eligible for deduction. 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, while maintaining sufficient flexibility to award appropriate incentives to named executive officers.

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In addition, Sections 280G and 4999 of the Internal Revenue Code limit income tax deductions for the Company and impose excise taxes on named executive officers who receive payments in excess of a defined limit upon a change in control. As discussed under “Potential Payments upon Termination or Change in Control of the Company” on page 64, certain payments to the named executive officers may be reduced to a limited extent to avoid the imposition of the excise tax, but payments to the named executive officers in connection with a change in control may be subject to these taxes (and loss of tax deductions).

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 HR Committee had five members in 2011. 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 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 and other key employees 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, modified and adopted annually by the Board. This charter is available on AEP’s web-site 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 officers at the senior vice president level and above and other key employees. 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.

In carrying out its responsibilities, the HR Committee addressed many aspects of AEP’s human resource and executive compensation programs and practices in 2011, including:

• Overseeing the CEO succession,

• Establishing annual and long-term performance objectives for senior executives,

• Assessing the performance of the CEO, other senior executives and the Company relative to those established performance objectives,

• Conducting an evaluation of Mr. Morris based on written comments from board members, senior AEP management, the CEO’s direct reports 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 to be provided to executives,

• Reviewing the design of the Company’s long-term incentive program and changing the mix of long-term incentive awards to better meet the Company’s current needs,

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• Reviewing an analysis of executive compensation for all senior executives, including the named executive officers,

• Reviewing and approving the base salaries, annual incentive awards and long-term incentive award opportunities for all senior executives,

• Reviewing and approving the major elements of the Company’s benefits and perquisites,

• Evaluating whether and how the design of the Company’s executive compensation programs and practices affect risk taking,

• Reviewing, adjusting and approving the major terms of employment, change in control and any other special agreements with executives,

• Reviewing the Company’s workforce safety efforts and results,

• Reviewing the senior management succession plan, including succession candidates for the CEO position,

• Reviewing and approving reports to shareholders regarding executive compensation, and

• Selecting and engaging a compensation consultant to provide objective and independent advice to the HR Committee.

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 2011 annual incentive compensation for all executive officers to measures that included employee safety, while also tying funding for annual incentive compensation to AEP’s 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, fostering a high performance culture and leadership of the board of directors,

• 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 senior officer,

• Compensation history,

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

• The impact of compensation on risk taking,

• The expense implications of any changes, and

• Tally sheets, showing multiple views of each of the named executive officer’s total compensation.

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2011 Changes.    During 2011 the HR Committee changed the mix of awards to be issued for 2011 and future years under its long-term incentive program. The new mix provided 40 percent of the grant value of these awards in restricted stock units and 60 percent of the value in performance units, rather than 100 percent in performance units. This change was made to provide a stronger retention incentive and more market competitive compensation during both up and down cycles. This change also brings AEP’s long-term incentive award mix closer to that of the companies in AEP’s Compensation Peer Group. The restricted stock unit awards include a two year post retirement holding requirement for senior executives who are subject to mandatory retirement. This post retirement holding period was introduced to mitigate the risk created near the end of an executive’s career when many long-term incentive awards may lose some of their capacity to encourage decision making in the long-term interests of the Company.

In addition, the HR Committee changed the terms under which long-term incentive awards are granted effective for 2011 and future years to implement double trigger vesting in the event of a change in control of the Company. This double trigger requires that a participant’s employment be terminated under defined terms in the event of a change in control for these long-term incentive awards to vest.

The HR Committee’s Independent Compensation Consultant.    In January 2011 the HR Committee reengaged Pay Governance, LLC, with Richard Meischeid as its lead consultant, to provide recommendations to the HR Committee regarding AEP’s executive compensation and benefit programs and practices. Mr. Meischeid is a nationally recognized executive compensation consultant. 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 consultant provides an annual executive compensation study and a report on current executive compensation and benefits trends within the electric utility industry and among U.S. industrial companies in general. In 2011, the Company paid $107,621 for executive compensation consulting services provided to the HR Committee by Pay Governance.

The HR Committee annually assesses and discusses the independence of its executive compensation consultant. Because Pay Governance does not provide any services to AEP, other than the work it performs for the HR Committee, the HR Committee concluded that Pay Governance, LLC and Mr. Meischeid were independent.

The Committee also annually assesses the performance and objectivity of its executive compensation consultant and has consistently found that the advice provided was of a high quality, objective and appropriate for the Company. Pay Governance does not have any role in recommending director compensation. The HR Committee regularly holds executive sessions with Mr. Meischeid to help ensure that they receive full and independent advice and that he is not unduly influenced by AEP 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 the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011 and in the Company’s proxy statement to be filed in connection with the Company’s 2012 Annual Meeting of Shareholders, each of which will be filed with the Securities and Exchange Commission.

Human Resources Committee Members

Lester A. Hudson, Jr., Chair

James F. Cordes

Ralph D. Crosby, Jr.

Thomas E. Hoaglin

Richard C. Notebaert

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Executive Compensation

Summary Compensation Table

The following table provides summary information concerning compensation paid or accrued by us to or on behalf of our Chairman and former Chief Executive Officer, our President and Chief Executive Officer, our Executive Vice President and Chief Financial Officer and four other highly compensated executive officers, to whom we refer collectively as the named executive officers. Ms. Tomasky retired from the Company on July 31, 2011.

Name and Principal Position	Year		Salary ($)(1)		Bonus ($)		Stock Awards ($)(2)		Option Awards ($)		Non- Equity Incentive Plan Compen- sation ($)(3)		Change in Pension Value and  Non- qualified Deferred Compen- sation Earnings ($)(4)		All Other Compen- sation ($)(5)		Total ($)
Michael G. Morris—		2011		1,305,480		—		5,313,000		—		1,500,000		477,339		591,087		9,186,906
Chairman of the board		2010		1,270,442		—		5,321,150		—		1,579,785		341,768		512,969		9,026,114
and former Chief Executive Officer		2009		1,254,808		—		5,265,750		—		—		446,490		572,230		7,539,278
Nicholas K. Akins(6)—		2011		770,192		—		1,123,168		—		750,000		112,879		51,563		2,807,802
President and Chief Executive Officer		2010		515,056		—		2,429,269		—		365,000		114,757		35,161		3,459,243
		2009		451,731		—		857,866		—		—		129,664		61,652		1,500,913
Brian X. Tierney—		2011		601,660		—		1,200,030		—		450,000		131,605		46,533		2,429,828
Executive Vice President		2010		467,365		—		2,703,635		—		425,000		180,228		29,456		3,805,684
and Chief Financial Officer		2009		401,539		—		857,866		—		—		124,813		69,767		1,453,985
Robert P. Powers—		2011		606,731		—		1,123,168		—		450,000		392,240		57,639		2,629,778
Executive Vice President-		2010		523,844		—		2,763,712		—		420,961		511,871		34,569		4,254,957
Chief Operating Officer		2009		511,961		—		1,213,530		—		—		692,065		68,442		2,485,998
Carl L. English—		2011		575,000		—		1,500,037		—		421,571		120,668		43,369		2,660,645
Former Vice Chairman		2010		563,998		—		1,805,415		—		450,000		74,119		35,475		2,929,007
		2009		552,115		—		1,848,128		—		—		108,781		74,965		2,583,989
D. Michael Miller(7)—		2011		410,000		—		900,022		—		260,515		60,759		526,677		2,157,973
Former Senior Vice President and General Counsel		2010		356,885		—		828,940		—		210,000		154,873		16,806		1,567,504
Susan Tomasky—		2011		302,885		—		999,907		—		214,219		555,245		982,965		3,055,221
Former President AEP Transmission		2010		523,844		—		1,203,610		—		300,000		689,992		34,566		2,751,942
		2009		511,961		—		1,221,052		—		—		1,009,187		64,060		2,806,260

(1) Amounts in the salary column are composed of executive salaries paid for the year shown, which include additional days of pay earned for years with more than the standard 260 calendar work days and holidays.

(2) The amounts reported in this column reflect the total grant date fair value, calculated in accordance with FASB ASC Topic 718, of performance units and restricted stock units granted under our Long-Term Incentive Plan. See Note 14 to the Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2011 for a discussion of the relevant assumptions used in calculating these amounts. The restricted stock units vest over a forty month period. 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. Therefore, the maximum amount payable is equal to 200 percent of the target award. The target value of performance units, which is the value reflected in this column, was $3,187,800 for Mr. Morris, $673,901 for Mr. Akins, $720,018 for Mr. Tierney, $673,901 for Mr. Powers, $900,022 for Mr. English, $540,013 for Mr. Miller and $599,944 for Ms. Tomasky. The maximum amount payable (200% of target) would be $6,375,600 for Mr. Morris, $1,347,802 for Mr. Akins, $1,440,036 for Mr. Tierney, $1,347,802 for Mr. Powers, $1,800,044 for Mr. English, $1,080,026 for Mr. Miller and $1,199,888 for Ms. Tomasky. For further information on these awards, see the Grants of Plan-Based Awards Table on page 52 and the Outstanding Equity Awards at Fiscal Year-End Table on page 56. For Messrs. Morris, English and Miller, two-thirds of the 2011 performance unit awards and one-third of the 2010 performance unit awards were cancelled upon their retirement on December 31, 2011. For Ms. Tomasky, 29/36^th of the 2011 performance unit awards, 17/36^th of the 2010 performance unit awards, and 5/36^th of the 2009 performance unit awards were cancelled upon her retirement on July 31, 2011. In addition, for Messrs. Morris and English, seventy percent of their restricted stock unit awards were cancelled upon their retirements and the remainder were vested, but are subject to a two year holding requirement. One hundred percent of Mr. Miller’s restricted stock unit awards were cancelled upon his retirement on December 31, 2011. For Ms. Tomasky, 17.5 percent of her restricted stock unit awards vested and the remainder were cancelled upon her July 31, 2011 retirement.

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The 2010 amounts also include 41,380 restricted stock units awarded in August 2010 to each of Messrs. Akins, Powers and Tierney.

(3) The amounts shown in this column are annual incentive awards made 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.

(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. The amount shown for Ms. Tomasky also includes the value of the payments made to her from the AEP Retirement Plan during 2011. See the Pension Benefits Table on page 59, and related footnotes for additional information. No named executive officer received preferential or above-market earnings on deferred compensation. See Note 7 to the Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2011, for a discussion of the relevant assumptions.

(5) A detailed breakout of the amounts shown in the All Other Compensation column for 2011 is shown below. These amounts include Company contributions to the Company’s Retirement Savings Plan and the Company’s Supplemental Retirement Savings Plan.

For Mr. Morris, the amount shown for 2011 includes the aggregate incremental cost associated with his personal use of Company-provided aircraft of $488,806. This amount is the incremental cost to the Company for his personal use of Company-provided aircraft, including all operating costs such as fuel, a maintenance reserve for the hours flown, on-board catering, landing/ramp fees and other miscellaneous variable costs. Fixed costs that do not change based on usage, such as pilot salaries, the lease costs for Company aircraft and the cost of maintenance not related to personal trips, are excluded. For proxy reporting purposes, personal use of corporate aircraft includes the incremental cost of relocating aircraft to accommodate personal trips and the incremental costs of flights for Mr. Morris to attend outside board meetings for the public companies at which he serves as an outside director. In 2009, the HR Committee generally eliminated personal use of Company provided aircraft to the extent that such use has an incremental cost to the Company, except for Mr. Morris who negotiated this as part of his employment agreement.

For Mr. Miller, the amount shown for 2011 includes a $500,000 separation payment. During 2011, Mr. Miller assisted with the transition of the General Counsel position to his newly-hired successor and then retired. The Company provided this separation payment to offset a portion of the compensation Mr. Miller would have received had he remained employed with the Company and retired in June 2012 at age 65 as was originally intended when he became General Counsel. For Ms. Tomasky, the amount shown for 2011 includes $893,250 paid in connection with her retirement pursuant to a separation and release of all claims agreement containing, among other things, certain non-solicitation, confidentiality and cooperation obligations of Ms. Tomasky.

(6) Mr. Akins was appointed President and Chief Executive Officer of the Company effective November 12, 2011. He was previously President.

(7) Mr. Miller became an executive officer of AEP in 2010, so only his compensation for 2010 and 2011 is shown.

All Other Compensation for 2011

Type	Michael G. Morris		Nicholas K. Akins		Brian X. Tierney		Robert P. Powers		Carl L. English		D. Michael Miller		Susan Tomasky
Retirement Savings Plan Match	$	4,484	$	11,025	$	9,773	$	11,025	$	11,025	$	11,025	$	11,025
Supplemental Retirement Savings Plan Match		85,262		29,337		22,910		35,110		21,894		15,612		16,201
Director Life and Accident Insurance		741		124		—		—		—		—		—
Financial Counseling and Tax Preparation		11,760		11,077		13,850		11,474		10,450		—		6,708
Vacation Payout		—		—		—		—		—		—		55,781
Personal Use of Executive Dining Room		34		—		—		30		—		40
Personal Use of Company Aircraft		488,806
Separation Payment		—		—		—		—		—		500,000		893,250

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Grants of Plan Based Awards in 2011

The following table provides information on plan based awards granted in 2011 to each of our named executive officers.

Name	Grant Date Approval(1)		Grant Date		Estimated Possible 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 (#)(5)		Grant Date Fair Value of Stock and Option Awards(6) ($)
					Threshold ($)		Target ($)		Maximum (3) ($)		Threshold (#)		Target (#)		Maximum (#)
Michael G. Morris
2011 Senior Officer Incentive Plan						—		1,500,407		3,000,814
2011 – 2013 Performance Units		12/7/10		1/1/2011								13,500		90,000		180,000				3,187,800
Restricted Stock Units		12/7/10		1/1/2011														60,000		2,125,200
Nicholas K. Akins
2011 Senior Officer Incentive Plan						—		740,182		1,480,364
2011 – 2013 Performance Units		12/7/10		1/1/2011								2,854		19,026		38,052				673,901
Restricted Stock Units		12/7/10		1/1/2011														12,684		449,267
Brian X. Tierney
2011 Senior Officer Incentive Plan						—		452,653		905,307
2011– 2013 Performance Units		12/7/10		1/1/2011								3,049		20,328		40,656				720,018
Restricted Stock Units		12/7/10		1/1/2011														13,552		480,012
Robert P. Powers
2011 Senior Officer Incentive Plan						—		456,943		913,885
2011– 2013 Performance Units		12/7/10		1/1/2011								2,854		19,026		38,052				673,901
Restricted Stock Units		12/7/10		1/1/2011														12,684		449,267
Carl L. English
2011 Senior Officer Incentive Plan						—		431,054		862,108
2011– 2013 Performance Units		12/7/10		1/1/2011								3,812		25,410		50,820				900,022
Restricted Stock Units		12/7/10		1/1/2011														16,940		600,015
D. Michael Miller
2011 Senior Officer Incentive Plan						—		266,375		532,750
2011– 2013 Performance Units		12/7/10		1/1/2011								2,287		15,246		30,492				540,013
Restricted Stock Units		12/7/10		1/1/2011														10,164		360,009
Susan Tomasky
2011 Senior Officer Incentive Plan						—		219,038		438,076
2011– 2013 Performance Units		12/7/10		1/1/2011								2,541		16,938		33,876				599,944
Restricted Stock Units		12/7/10		1/1/2011														11,292		399,963

(1) On December 7, 2010 the HR Committee and the independent members of the board approved performance unit awards and restricted stock units, effective January 1, 2011, under our Long-Term Incentive Plan. The performance and vesting period for performance unit awards is January 1, 2011 through December 31, 2013. The restricted stock units vest in three equal installments on May 1, 2012, May 1, 2013 and May 1, 2014.

(2) Consists of potential payouts under the Senior Officer Incentive Plan (SOIP), which are based on base salary paid during the year.

(3) The amount shown in this column represents 200 percent of the target award for each of the named executive officers, which is generally the maximum annual incentive award for all AEP executives and other employees. Awards under the SOIP were also capped in aggregate at 0.75 percent of income before discontinued operations, extraordinary items and the cumulative effect of accounting changes. In addition, the maximum award payment to any SOIP participant for any year is the lesser of:

(i) $6,000,000 or

(ii) 400 percent of the executive’s base salary (prior to any salary reduction or deferral elections) as of the date of grant of the award.

(4) Consists of performance units awarded under our Long-Term Incentive Plan for the three-year performance period 2011 – 2013. For further information on these awards, see the description under 2011 Stock Award Grants below. For Messrs. Morris, English and Miller, two-thirds of the 2011 performance unit awards were cancelled upon their retirement on December 31, 2011.

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(5) Consists of restricted stock units awarded under the Long-Term Incentive Plan. These awards generally vest in three equal installments on May 1, 2012, May 1, 2013, and May 1, 2014. For Messrs. Morris and English, thirty percent of their restricted stock unit awards vested and the remainder were cancelled upon their retirement on December 31, 2011. Messrs. Morris’ and English’s vested shares are subject to a two year holding period. One hundred percent of Mr. Miller’s restricted stock unit awards were cancelled upon his retirement on December 31, 2011. For Ms. Tomasky, 17.5 percent of her restricted stock unit awards vested and the remainder were cancelled upon her July 31, 2011 retirement.

(6) For performance units, the value is computed by multiplying the closing price of AEP common stock on December 7, 2010 ($35.42) by the target number of performance units granted. The actual number of performance units earned will depend on AEP’s performance over the 2011 through 2013 period and could vary from 0 percent to 200 percent of the target award plus reinvested dividends. 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. For restricted stock units, the value is computed by multiplying the closing price of AEP common stock on December 7, 2010 ($35.42) by the number of restricted stock units.

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

2011 Stock Award Grants.    Effective January 1, 2011, the named executive officers were granted long-term incentive awards as part of AEP’s regular annual grant cycle. These awards were granted with change in control provisions that include a double trigger that only provides earlier vesting of awards in the event of a change in control and a covered separation from service. Of these awards, 60 percent were granted in the form of performance units for the 2011-2013 three-year performance period and 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. Dividends are reinvested in additional performance units.

The 2011-2013 performance units are subject to two equally weighted performance measures for the three-year performance period, which are:

• Three-year total shareholder return relative to the electric utility and multi-utility companies included in the S&P 500 Index, and

• Three-year cumulative 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 on page 40. 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. Recipients must remain employed by AEP through the end of the vesting period to receive a payout unless they retire; are severed by the Company as part of a consolidation, restructuring or downsizing; or are terminated in conjunction with a change in control. In the event of a participant’s retirement or severance by the company, a prorated portion of their performance units will vest. This portion is calculated as the number of months of the vesting period that the participant actively worked divided by the total number of months of the vesting period. In the event a participant’s employment is terminated in conjunction with a change in control, then all of the performance units will vest. Each performance unit that is vested and earned is paid out or deferred with a value equal to the average closing price of AEP common stock for the last twenty trading days of the performance period.

The remaining 40 percent of AEP’s long-term incentive awards were granted in the form of restricted stock units (RSUs) that generally vest, subject to the executive officer’s continued employment, in three equal installments on May 1, 2012, May 1, 2013 and May 1, 2014. Recipients must remain employed by AEP through the vesting date to receive a payout for the RSUs that vest on such date unless they retire pursuant to AEP’s mandatory officer retirement policy at age 65; are severed by the Company as part of a consolidation, restructuring or downsizing; or are terminated in conjunction with a change in control. In the event of a participant’s retirement pursuant to

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AEP’s mandatory retirement policy or severance by the company, a prorated portion of their RSUs will vest. This portion is calculated as the number of months of the vesting period that the participant actively worked divided by the total number of months of the longest vesting period less the portion of the RSUs originally granted that have already vested. RSUs that vest pursuant to the mandatory retirement policy, less shares withheld for taxes, are subject to a two year post-retirement holding period. The RSUs that vested for Messrs. Morris and English are subject to this holding period. In the event a participant’s employment is terminated in conjunction with a change in control, then all of these RSUs will vest.

2011 Non-Equity Incentive Compensation.    For 2011 the HR Committee established the following annual incentive targets for the named executive officers:

• 115 percent of base salary for Mr. Morris,

• 95 percent of base salary for Mr. Akins,

• 75 percent of base salary for Messrs. Tierney, Powers and English,

• 65 percent of base salary for Mr. Miller, and

• 70 percent of base salary for Ms. Tomasky.

The incentive targets for Messrs. Akins, Tierney and Powers were increased effective November 12, 2011 to 110 percent, 80 percent and 80 percent, respectively. Actual awards generally may vary from 0 percent to 200 percent of the annual incentive target.

The HR Committee set target funding for the 2011 annual incentive compensation program at $3.10 per share, the midpoint of the Company’s publicly disclosed ongoing earnings guidance of $3.00 to $3.20 per share. In 2011 AEP reported ongoing earnings per share (EPS) of $3.12, which was above the midpoint of AEP’s earnings guidance for the year and resulted in a score of 119.0 percent of target. For 2011, GAAP EPS reported in AEP’s financial statements was $0.90 per share higher than ongoing earnings, primarily because of to a Texas Supreme Court decision that resulted in a net-of-tax favorable adjustment related to stranded costs in Texas. Exhibit B to this proxy statement has a reconciliation of ongoing and reported EPS for 2011.

For 2011 the HR Committee again used an executive council scorecard with four performance categories: safety, operating performance, regulatory performance and strategic initiatives. The HR Committee also established a fatality adjustment for 2011 that increased or decreased the overall score for all executive officers by 10 percent depending on whether AEP experienced a fatal work related employee accident. Since AEP experienced a fatal work related accident in 2011, a 10 percent score reduction was applied.

Due to the above target EPS score, the negative fatality adjustment and the relatively strong performance of our business units against their incentive goals, which reduced the incentive funding available for the corporate officer group, the overall annual incentive funding for AEP’s executive officers was 97.8 percent of target for 2011.

The HR Committee then allocated annual incentive awards from this funding pool to the executive officers, other than Messrs. Morris and Akins, based on a subjective assessment of each executive’s performance. The independent members of the Board also determined the annual incentive award for Messrs. Morris and Akins for 2011 based on a subjective assessment of their performance. The 2011 annual incentive awards are shown in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table and reflect adjustments above and below the 97.8 percent of target score based on these assessments of individual performance.

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AEP provides annual incentive compensation to executive officers through the Senior Officer Incentive Plan, which was approved by shareholders at the 2007 annual meeting and has been submitted to shareholders for approval at this meeting. This plan establishes the maximum annual incentive award opportunity for each executive officer. For further information, see page 36.

Employment Agreements.    The Company entered into an employment agreement (Agreement) with Mr. Morris that became effective January 1, 2004. The Agreement awarded Mr. Morris a nonqualified stock option grant of 149,000 shares and 200,000 restricted shares, payable in three approximately equal installments, as a replacement for certain long-term compensation that he forfeited from his prior employer in order to accept employment with the Company. These restricted shares vested in three equal installments on November 30 of 2009, 2010 and 2011.

Pursuant to the terms of the Agreement, Mr. Morris was provided an opening balance in the AEP Supplemental Benefit Plan of $2.1 million. Mr. Morris vested in this plan in 20 percent increments on each of the first five anniversary dates of his employment. Mr. Morris is credited at the maximum rate permitted under the AEP Supplemental Benefit Plan (currently at 8.5 percent) on all eligible earnings. For further information, see note (2) under Pension Benefits on page 60.

The Agreement also provided Mr. Morris with coverage under the Company’s benefit programs available to its senior executives, including retiree medical coverage in effect as of the date of his retirement from the Company. In connection with Mr. Morris’ retirement as an employee of the Company, the Company has undertaken to pay or reimburse such portion of the costs Mr. Morris incurs for medical coverage for himself and his wife so that his cost for that coverage is equal to the amount he would have incurred had he qualified for retiree medical benefits under the Company’s medical plan.

The Company entered into an employment agreement with Mr. English that provided that his cash balance account under the AEP Supplemental Benefit Plan would be credited with the maximum rate permitted (currently at 8.5 percent) on all eligible earnings. For further information, see note (2) under Pension Benefits on page 60.

Mr. Powers and Ms. Tomasky each has an agreement with the Company, which credits them with 17 and 20 years, respectively, of additional service under AEP’s Supplemental Benefit Plan. For further information on these agreements, see note (3) under the Pension Benefits on page 60.

In addition to these agreements, each of the named executive officers has entered into a Change In Control Agreement with AEP. For further information about these Change In Control Agreements see page 65.

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Outstanding Equity Awards at Fiscal Year-End for 2011

The following table provides information with respect to holdings of stock options, restricted stock, restricted stock units and performance units by the named executive officers at December 31, 2011.

	Option Awards						Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Option Exercise Price ($)		Option Expiration Date		Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($)		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)
Michael G. Morris
Stock Options		149,000		30.76		1/2/2014
2010 – 2012 Performance Units(2)												113,997		4,709,216
2011 – 2013 Performance Units(2)												31,516		1,301,926
Nicholas K. Akins
2010 – 2012 Performance Units(2)												29,830		1,232,277
2011 – 2013 Performance Units(2)												19,987		825,663
Restricted Stock Units(3)								44,536		1,839,782
2011 Restricted Stock Units(4)								13,325		550,456
Brian X. Tierney
2010 – 2012 Performance Units(2)												38,678		1,597,788
2011 – 2013 Performance Units(2)												21,355		882,175
Restricted Stock Units(3)								44,536		1,839,782
2011 Restricted Stock Units(4)								14,237		588,130
Robert P. Powers
2010 – 2012 Performance Units(2)												40,609		1,677,558
2011 – 2013 Performance Units(2)												19,987		825,663
Restricted Stock Units(3)								44,536		1,839,782
2011 Restricted Stock Units(4)								13,325		550,456
Carl L. English
2010 – 2012 Performance Units(2)												38,678		1,597,788
2011 – 2013 Performance Units(2)												8,898		367,576
D. Michael Miller
2010 – 2012 Performance Units(2)												5,994		247,612
2011 – 2013 Performance Units(2)												5,339		220,554
Susan Tomasky
2010 – 2012 Performance Units(2)												20,413		843,261
2011 – 2013 Performance Units(2)												3,460		142,933

(1) 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, 2011 ($41.31) by the target number of performance units including performance units resulting from reinvested dividends. The actual number of performance units credited upon vesting will be based on AEP’s performance over the applicable three year period.

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(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 2009 – 2011 performance period vested at December 31, 2011 and are shown in the Options Exercises and Stock Vested table below. The awards shown for the 2010 – 2012 and 2011 – 2013 performance periods include performance units resulting from reinvested dividends. Messrs. Morris, English and Miller retired effective December 31, 2011 and Ms. Tomasky retired as of July 31, 2011, which resulted in vesting of a pro rata portion of their performance units but these awards will remain subject to the same performance criteria and payment date. The prorated portion that vests due to retirement is calculated as the number of months of the vesting period that the participant actively worked divided by the 36 months of the vesting period. For Messrs. Morris, English and Miller, this portion was 12/36^th of the 2011 – 2013 performance units and 24/36^th of the 2010-2012 performance units. For Ms. Tomasky this portion was 7/36^th of the 2011 – 2013 performance units and 19/36^th of the 2010-2012 performance units.

(3) These restricted stock units were granted on August 3, 2010, and include restricted stock units resulting from reinvested dividends. These units will vest, subject to the executive officer’s continued employment, in three equal installments, on August 3, 2013, August 3, 2014 and August 3, 2015, respectively. The market value of the restricted stock units reported in this column was computed using the closing price of AEP’s common stock on December 31, 2011 ($41.31).

(4) These restricted stock units were approved by the HR Committee on December 7, 2010, effective January 1, 2011. They will vest, subject to the executive officer’s continued employment, in three equal installments, on May 1, 2012, May 1, 2013 and May 1, 2014, respectively. The market value of the restricted stock units reported in column was computed using the closing price of AEP’s common stock on December 31, 2011 ($41.31). Messrs. Morris and English retired effective December 31, 2011 due to AEP’s mandatory retirement policy for officers, which resulted in the vesting of a pro rata portion of their 2011 restricted stock units, which are shown in the Options Exercises and Stock Vested table below. The shares issued when these restricted stock units vested are subject to a two year holding period.

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Option Exercises and Stock Vested for 2011

The following table provides information with respect to the vesting of stock options, restricted shares and performance units granted to our named executive officers.

	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)
Michael G. Morris		—		—		269,037		11,005,252
Nicholas K. Akins		—		—		29,888		1,234,673
Brian X. Tierney		—		—		29,888		1,234,673
Robert P. Powers		—		—		42,280		1,746,587
Carl L. English		—		—		69,729		2,880,505
D. Michael Miller		—		—		25,787		1,043,461
Susan Tomasky		—		—		38,659		1,587,987

(1) This column includes performance units for the 2009 – 2011 performance period that vested on December 31, 2011. For Messrs. Morris, English and Miller and Ms. Tomasky, this column also includes restricted stock units that vested upon their retirements. For Mr. Morris, this column also includes 66,667 restricted shares that vested on November 30, 2011.

(2) As is required, the value shown in this column for performance units is computed by multiplying the number of units by the market value of these units on the vesting date ($41.31). However, the actual value realized from these units was based on the previous 20-day average closing market price of AEP common stock as of the vesting date ($40.146). For a more detailed discussion of vesting of the performance units, see the Long-Term Incentive Compensation section of the Compensation Discussion and Analysis beginning on page 39. This column also includes 18,909, 5,339, and 10,763 restricted stock units, for Mr. Morris, Mr. English and Mr. Miller, respectively. All of these units vested on December 31, 2011 with a value of $41.31. Mr. Miller also had an additional 5,253 restricted stock units that vested on July 28, 2011 with a value of $37.16. In addition, this column includes 2,026 restricted stock units for Ms. Tomasky that vested upon her retirement on July 31, 2011 with a market value of $36.86 per share.

Executive officers may only exercise stock options pursuant to AEP’s Insider Trading Policy.

Two equally weighted performance measures were established by the HR Committee for the 2009-2011 performance units when they were granted in December 2008:

• Total Shareholder Return measured relative to the utility companies in the S&P 500 Index, and

• Cumulative earnings per share measured relative to a target approved by the HR Committee.

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The threshold, target and maximum payout levels are shown in the table below.

AEP’s total shareholder return for this performance period was at the 48^th percentile of the utility companies in the S&P 500, which produced a score of 94.7 percent. AEP’s cumulative earnings per share were $8.888 for this performance period, compared to the target of $9.02. This produced an earnings per share score of 85.0 percent. The average of these two scores produced a composite score of 89.8 percent of the target award. These performance units vested on December 31, 2011 and were valued at the average closing price of AEP common stock for the last 20 days of the performance period, which was $40.146. The final score calculation for these performance measures is shown in the chart below.

2009 – 2011 Performance Units

Performance Measures	Threshold Performance	Target Performance	Maximum Payout Performance	Actual Performance	Score	Weight	Weighted Score
3-Year Cumulative Earnings Per Share	$7.92 (0% payout)	$9.02 (100% Payout)	$9.90 (200% Payout)	$8.888	85.0%	50%	42.5%
3-Year Total Shareholder Return vs. S&P Electric Utilities	20th Percentile (0% Payout)	50th Percentile (100% Payout)	80th Percentile (200% Payout)	48th Percentile	94.7%	50%	47.3%
Composite Result							89.8%

Pension Benefits for 2011

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
Michael G. Morris	AEP Retirement Plan		8.0	$	155,958		—
	AEP Supplemental Benefit Plan		8.0  (2)		4,677,704		—
Nicholas K Akins	AEP Retirement Plan		29.6		404,782		—
	CSW Executive Retirement Plan		29.6		324,170		—
Brian X. Tierney	AEP Retirement Plan		13.7		206,891		—
	AEP Supplemental Benefit Plan		13.7		687,493		—
Robert P. Powers	AEP Retirement Plan		13.5		439,195		—
	AEP Supplemental Benefit Plan		30.5  (3)		3,335,610		—
Carl L. English	AEP Retirement Plan		7.5		154,946		—
	AEP Supplemental Benefit Plan		7.5  (2)		487,200		—
D. Michael Miller	AEP Retirement Plan		16.8		678,823		—
	AEP Supplemental Benefit Plan		16.8		799,680		—
Susan Tomasky(4)	AEP Retirement Plan		13.1		468,501	$	16,423
	AEP Supplemental Benefit Plan		33.1  (3)		4,933,551		—

(1) The Present Value of Accumulated Benefits is based on the benefit accrued under the applicable plan through December 31, 2011, 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, Mr. Powers and Ms. Tomasky, retires at age 62, or for Mr. Miller, who previously reached age 62, retires at his current age, when unreduced benefits would be payable), and commences the payment of benefits (the “accrued benefit”).

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• 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 4.55 percent, 4.40 percent and 4.40 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 the IRS 2012 sex-distinct 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 6.25 percent and assumed mortality based on the 2012 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 4.55 percent, 4.40 percent and 4.40 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, Mr. Miller and Ms. Tomasky, due to their 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. Morris and Mr. English each had an individual agreement that provided for annual credits at the maximum rate provided (currently 8.5 percent). If not for their agreements, their combined age and service would have entitled each of them to an annual credit of 5.5 percent (through December 31, 2004) and 7 percent (from 2005 through 2009) of eligible pay for each year prior to 2010 rather than the 8.5 percent maximum rate. Mr. Morris’ agreement further provided him an opening cash balance credit of $2,100,000 as of January 1, 2004. The higher crediting rate for Mr. Morris and Mr. English for years prior to 2010, and Mr. Morris’ opening cash balance credit, have augmented the present value of their accumulated benefits under the AEP Supplemental Benefit Plan as of December 31, 2011 by $3,368,605 and $92,332, respectively.

(3) Mr. Powers and Ms. Tomasky each have an agreement with AEP that credits them with years of service in addition to their actual years of service with AEP. Their additional years of service credit have augmented the present value of their accumulated benefits under the AEP Supplemental Benefit Plan by $1,973,915 and $3,104,417, respectively.

(4) Ms. Tomasky separated from service on July 31, 2011. As of August 1, 2011, Ms. Tomasky commenced payment of her benefit under the AEP Retirement Plan as a monthly life annuity of $3,285, with a contingent monthly survivor annuity payable to her spouse in the amount of $985, if he survives her. Ms. Tomasky’s lump sum benefit under the AEP Supplemental Benefit Plan was $3,944,487 as of December 31, 2011, and that amount plus interest at 4 percent was payable to her in February 2012.

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 respective tax-qualified plans 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. As of December 31, 2011, each of the named executive officers was vested.

In addition, employees who have continuously participated in the AEP Retirement Plan since December 31, 2000 (“Grandfathered AEP Participants,” which includes Mr. Tierney, Mr. Powers and Ms. Tomasky) 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.

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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.

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, participant’s 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 2011, the limit was $245,000.

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. For 2011, the interest rate was 4.19 percent.

Final Average Pay Formula.    Grandfathered AEP Participants receive their benefits under the cash balance formula or the final average pay formula, whichever provides the higher benefit. On December 31, 2010, the final average pay benefit payable at the Grandfathered AEP Participant’s normal retirement age was frozen, meaning that their final average pay formula benefit will no longer be affected by the participant’s subsequent service or compensation. Therefore, the final average pay normal retirement benefit for each of the Grandfathered AEP Participants was frozen as of December 31, 2010, based upon 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.

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 pay.

AEP previously granted certain named executive officers additional years of credited service, an opening balance credit, special crediting rates and special vesting schedules under the AEP Supplemental Benefit Plan. These special items are further described under Employment Agreements on page 55.

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As of December 31, 2011, 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.

Nonqualified Deferred Compensation for 2011

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) ($)
Michael G. Morris		SRSP		157,775		85,262		62,039			—		3,393,974
		SORP		—		—		1,198,379			—		7,975,314
Nicholas K. Akins		SRSP		39,115		29,337		14,055			—		464,118
		ICDP		—		—		(4,177	)		—		170,768
		SORP		150,027		—		294,349			—		1,479,099
Brian X. Tierney		SRSP		50,912		22,910		235,358			—		1,512,093
		SORP		—		—		92,901			—		618,269
Robert P. Powers		SRSP		56,065		35,110		123,189			—		1,931,470
		ICDP		—		—		(25,038	)		—		556,968
		SORP		—		—		262,608			—		1,747,679
Carl L. English		SRSP		29,192		21,894		20,926			—		554,007
		SORP		—		—		412,010			—		2,741,963
D. Michael Miller		SRSP		97,138		15,612		35,585			—		681,810
		SORP		—		—		50,255			—		334,449
Susan Tomasky		SRSP		31,460		16,201		43,063			—		1,552,867
		SORP		—		—		722,856			—		4,810,670

(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 at either (i) Salary for 2011 or (ii) the Non-Equity Incentive Plan Compensation column for 2010.

(3) The amounts set forth under “Registrant Contributions in Last FY” for the SRSP are reported in the 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: $2,056,400 for Mr. Morris, $50,079 for Mr. Akins, $312,778 for Mr. Tierney, $354,061 for Mr. Powers, $354,428 for Mr. English and $257,981 for Ms. Tomasky. In addition, the “Aggregate Balance at Last FYE” for the SORP includes $150,625 for Mr. Akins previously reported in the Summary Compensation Table for a prior year.

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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 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 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 pay and annual incentive pay in excess of the IRS’ eligible compensation limit for qualified plans, which is $245,000 for 2011, 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.

• 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 withdraw amounts attributable to their pre-2005 contributions once 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 total return on AEP stock with dividends reinvested. AEP Career Shares become payable in cash following the participant’s termination of employment. Participants may elect to take distribution of their AEP Career Shares in the same manner as described above for the Supplemental Retirement Savings Plan.

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Potential Payments upon Termination 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. The amounts reported in the tables below are hypothetical amounts. 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.

Severance.    AEP currently provides full-time employees, including the named executive officers, with severance benefits in the event their employment is terminated as the direct result of a restructuring or downsizing (“Severance-Eligible Employees”) if 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, except for Mr. Morris who would receive a severance payment equal to two times his annual base salary in the event of his severance pursuant to his employment agreement,

• 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 to 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 severance pay (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 Code Section 409A.

Although employees generally must be employed through year-end to be eligible for annual incentive compensation, Severance-Eligible Employees and Retirement-Eligible Employees remain eligible for annual incentive compensation, to the extent of their eligible earnings, for the year of their termination. The target award for these employees reflects their cumulative base earnings for the plan year, which will be less than a full year of base earnings to the extent that the employee was not employed by the Company for the full plan year. Annual incentive awards for named executive officers continue to be subject to the performance-based maximum award limits of the Senior Officer Incentive Plan and the discretion of the HR Committee. Any annual incentive awards for severed or retired executive officers would be paid at approximately the same time as the awards for active employees.

A Severance-Eligible executive’s termination entitles that executive to a pro-rata portion of any outstanding performance units which the executive has held for at least six months. These prorated performance units will not become payable until the end of the performance period and remain subject to all performance objectives.

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Severance-Eligible executives are eligible for continuation of financial counseling and tax preparation services one year following their termination up to a maximum annual incremental cost to the Company of $11,450.

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, which 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.” Such termination must be within one year before or two years after the change in control. These agreements provide for:

• A lump sum payment equal to 2.99 times the named executive officers’ annual base salary plus target annual incentive under the annual incentive program,

• Payment, if required, to make the named executive officer whole for any excise tax imposed by Section 4999 of the Internal Revenue Code, and

• Outplacement services.

The Company will reduce the lump sum change in control benefit payment for each of the named executive officers by up to 5 percent if that reduction would avoid the 4999 excise tax. In November 2009 the HR Committee revised the change in control agreements offered to new participants to eliminate the reimbursement for excise taxes. Mr. Akins also voluntarily relinquished the reimbursement and gross-up for excise taxes in his change in control agreement.

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”.

Also, award agreements issued under the Long-Term Incentive Plan with an effective date prior to January 1, 2011 provide that such awards will vest immediately upon a change in control. Long-Term Incentive Plan awards granted with an effective date on or after January 1, 2011, will vest upon a “Qualifying Termination” upon 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, certain types of long-term incentive awards are subject to special payment and valuation provisions if they vest upon a change in control as follows:

Stock Options – Participants with outstanding stock options are permitted to direct an advance exercise of any of their options and receive cash equal to the value received by other AEP shareholders as a result of the change in control transaction (less applicable tax withholdings).

Performance Unit Awards – The performance unit awards with an effective date prior to January 1, 2011 would be deemed to have been fully earned at 100 percent of the target score, and would be paid in a lump sum in cash upon a change in control. Performance units with an effective date on or after January 1, 2011 would be deemed to have been fully earned at 100 percent of the target score upon a “Qualifying Termination” (defined as described above for performance units issued on or after January 1, 2011) following a change in control. The value of each vested performance unit following a change in control or “Qualifying Termination” would be (1) if the payment is due upon a change in control that 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, or (2), otherwise, the closing price of a share of AEP common stock on the date of the change in control (or Qualifying Termination, if applicable).

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The AEP Supplemental Benefit Plan also provides that all accrued supplemental retirement benefits 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, 2011 under the hypothetical circumstances cited in each column and calculated in accordance with the methodology required by the SEC. Actual payments 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, the Company may enter into agreements or establish arrangements that provide additional benefits or amounts, or may alter the terms of benefits described below.

With respect to annual incentive compensation for the completed year, the calculated annual incentive opportunity is shown, which varies from the actual value paid, which is reported in the Summary Compensation Table on page 50, due to discretionary adjustments for individual performance

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 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, 2011

For Michael G. Morris

Executive Benefits and Payments Upon Termination	Voluntary Termination or Retirement			Severance			For Cause Termination		Change-In- Control		Death
Compensation:
Base Salary ($1,305,480)	$	0		$	2,610,960	(1)	$	0	$	3,903,385	$	0
Annual Incentive for Completed Year(2)	$	1,467,398		$	1,467,398		$	0	$	1,467,398	$	1,467,398
Other Payment for Annual Incentives(3)	$	0		$	0		$	0	$	4,488,893	$	0
Long-Term Incentives:(4)
2010-2012 Performance Units(5)	$	4,709,216		$	4,709,216		$	0	$	7,063,845	$	4,709,216
2011-2013 Performance Units(5)	$	1,301,926		$	1,301,926		$	0	$	3,905,737	$	1,301,926
2011 Restricted Stock Units	$	781,131	(6)	$	781,131		$	0	$	2,603,811	$	2,603,811
Benefits:
Health and Welfare Benefits(8)	$	0		$	638		$	0	$	638	$	0
Financial Counseling	$	11,450		$	11,450		$	0	$	11,450	$	11,450
Outplacement Services(9)	$	0		$	28,000		$	0	$	28,000	$	0
Other
Change in Control Benefit Reduction(10)	$	0		$	0		$	0	$	0	$	0
Tax Gross-up Upon Change In Control(11)	$	0		$	0		$	0	$	0	$	0
Total Incremental Compensation And Benefits	$	8,271,121		$	10,910,719		$	0	$	23,473,157	$	10,093,801

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, 2011

For Nicholas K. Akins

Executive Benefits and Payments Upon Termination	Voluntary Termination or Retirement		Severance		For Cause Termination		Change-In- Control		Death
Compensation:
Base Salary ($900,000)	$	0	$	1,038,462	$	0	$	2,691,000	$	0
Annual Incentive for Completed Year(2)	$	723,898	$	723,898	$	0	$	723,898	$	723,898
Other Payment for Annual Incentives(3)	$	0	$	0	$	0	$	2,960,100	$	0
Long-Term Incentives:(4)
2010-2012 Performance Units(5)	$	0	$	821,532	$	0	$	1,232,277	$	821,532
2011-2013 Performance Units(5)	$	0	$	275,207	$	0	$	825,663	$	275,207
Restricted Stock Units	$	0	$	272,563	$	0	$	1,839,782	$	1,839,782
2011 Restricted Stock Units	$	0	$	165,116	$	0	$	550,456	$	550,456
Benefits:
Health and Welfare Benefits(8)	$	0		151,173	$	0		151,173		55,323
Financial Counseling	$	0	$	11,450	$	0	$	11,450	$	11,450
Outplacement Services(9)	$	0	$	28,000	$	0	$	28,000	$	0
Other
Change in Control Benefit Reduction(10)	$	0	$	0	$	0	$	0	$	0
Tax Gross-up Upon Change In Control(11)	$	0	$	0	$	0	$	5,070,247	$	0
Total Incremental Compensation and Benefits	$	723,898	$	3,487,401	$	0	$	16,084,046	$	4,277,648

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, 2011

For Brian X. Tierney

Executive Benefits and Payments Upon Termination	Voluntary Termination or Retirement		Severance		For Cause Termination		Change-In- Control		Death
Compensation:
Base Salary ($612,333)	$	0	$	329,718	$	0	$	1,830,877	$	0
Annual Incentive for Completed Year(2)	$	442,695	$	442,695	$	0	$	442,695	$	442,695
Other Payment for Annual Incentives(3)	$	0	$	0	$	0	$	1,464,701	$	0
Long-Term Incentives:(4)
2010-2012 Performance Units(5)	$	0	$	1,065,178	$	0	$	1,597,788	$	1,065,178
2011-2013 Performance Units(5)	$	0	$	294,045	$	0	$	882,175	$	294,045
Restricted Stock Units	$	0	$	272,563	$	0	$	1,839,782	$	1,839,782
2011 Restricted Stock Units	$	0	$	176,435	$	0	$	588,130	$	588,130
Benefits:
Health and Welfare Benefits(8)	$	0	$	22,620	$	0	$	22,620	$	110,367
Financial Counseling	$	0	$	11,450	$	0	$	11,450	$	11,450
Outplacement Services(9)	$	0	$	28,000	$	0	$	28,000	$	0
Other
Change in Control Benefit Reduction(10)	$	0	$	0	$	0	$	0	$	0
Tax Gross-up Upon Change In Control(11)	$	0	$	0	$	0	$	3,501,313	$	0
Total Incremental Compensation and Benefits	$	442,695	$	2,642,704	$	0	$	12,209,531	$	4,351,647

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, 2011

For Robert P. Powers

Executive Benefits and Payments Upon Termination	Voluntary Termination or Retirement		Severance		For Cause Termination		Change-In- Control		Death
Compensation:
Base Salary ($650,000)	$	0	$	350,000	$	0	$	1,943,500	$	0
Annual Incentive for Completed Year(2)	$	446,890	$	446,890	$	0	$	446,890	$	446,890
Other Payment for Annual Incentives(3)	$	0	$	0	$	0	$	1,554,800	$	0
Long-Term Incentives:(4)
2010-2012 Performance Units(5)	$	1,118,344	$	1,118,344	$	0	$	1,677,558	$	1,118,344
2011-2013 Performance Units(5)	$	275,207	$	275,207	$	0	$	825,663	$	275,207
Restricted Stock Units	$	0	$	272,563	$	0	$	1,839,782	$	1,839,782
2011 Restricted Stock Units	$	0	$	165,116	$	0	$	550,456	$	550,456
Benefits:
Health and Welfare Benefits(8)	$	0	$	4,687	$	0	$	4,687	$	0
Financial Counseling	$	11,450	$	11,450	$	0	$	11,450	$	11,450
Outplacement Services(9)	$	0	$	28,000	$	0	$	28,000	$	0
Other
Change in Control Benefit Reduction(10)	$	0	$	0	$	0	$	0	$	0
Tax Gross-up Upon Change In Control(11)	$	0	$	0	$	0	$	3,452,418	$	0
Total Incremental Compensation and Benefits	$	1,851,891	$	2,672,257	$	0	$	12,335,204	$	4,242,129

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, 2011

For Carl L. English

Executive Benefits and Payments Upon Termination	Voluntary Termination or Retirement			Severance		For Cause Termination		Change-In- Control		Death
Compensation:
Base Salary ($575,000)	$	0		$	176,923	$	0	$	1,719,250	$	0
Annual Incentive for Completed Year(2)	$	421,571		$	421,571	$	0	$	421,571	$	421,571
Other Payment for Annual Incentives(3)	$	0		$	0	$	0	$	1,289,438	$	0
Long-Term Incentives:(4)
2010-2012 Performance Units(5)	$	1,597,788		$	1,597,788	$	0	$	2,396,682	$	1,597,788
2011-2013 Performance Units(5)	$	367,576		$	367,576	$	0	$	1,102,729	$	367,576
2011 Restricted Stock Units	$	220,554	(6)	$	220,554	$	0	$	735,153	$	735,153
Benefits:
Health and Welfare Benefits(8)	$	0		$	22,620	$	0	$	22,620	$	1,550
Financial Counseling	$	11,450		$	11,450	$	0	$	11,450	$	11,450
Outplacement Services(9)	$	0		$	28,000	$	0	$	28,000	$	0
Other
Change in Control Benefit Reduction(10)	$	0		$	0	$	0	$	0	$	0
Tax Gross-up Upon Change In Control(11)	$	0		$	0	$	0	$	3,044,555	$	0
Total Incremental Compensation and Benefits	$	2,618,939		$	2,846,482	$	0	$	10,771,448	$	3,135,088

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, 2011

For D. Michael Miller

Executive Benefits and Payments Upon Termination	Voluntary Termination or Retirement		Severance		For Cause Termination		Change-In- Control		Death
Compensation:
Base Salary ($410,000)	$	0	$	268,077	$	0	$	1,225,900	$	0
Annual Incentive for Completed Year(2)	$	260,515	$	260,515	$	0	$	260,515	$	260,515
Other Payment for Annual Incentives(3)	$	0	$	0	$	0	$	796,835	$	0
Long-Term Incentives:(4)
Unvested 2010-2012 Performance Units(5)	$	247,612	$	247,612	$	0	$	371,418	$	247,612
Unvested 2011-2013 Performance Units(5)	$	220,540	$	220,540	$	0	$	661,621	$	220,540
Restricted Stock Units(7)	$	444,620	$	444,620	$	0	$	444,620	$	444,620
2011 Restricted Stock Units	$	0	$	132,316	$	0	$	441,067	$	441,067
Benefits:
Health and Welfare Benefits(8)	$	0	$	2,648	$	0	$	2,648	$	0
Financial Counseling	$	11,450	$	11,450	$	0	$	11,450	$	11,450
Outplacement Services(9)	$	0	$	28,000	$	0	$	28,000	$	0
Other
Change in Control Benefit Reduction(10)	$	0	$	0	$	0	$	0	$	0
Tax Gross-up Upon Change In Control(11)	$	0	$	0	$	0	$	1,776,976	$	0
Total Incremental Compensation and Benefits	$	1,184,737	$	1,615,778	$	0	$	6,021,050	$	1,625,804

(1) Mr. Morris’ employment agreement provided a severance benefit equal to two times his base pay in the event his employment would have been terminated not for cause, as defined therein.

(2) Executive officers are eligible for an annual incentive award if they remain employed with AEP through year-end unless their employment is terminated for cause. The amount shown is the calculated annual incentive opportunity, as shown on page 39, 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.

(3) Represents a severance payment of 2.99 times each named executive officer’s current target annual incentive as of December 31, 2011.

(4) 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.

(5) The target value of performance unit awards are shown. The actual value paid in the event of voluntary termination, 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 change in control, awards would be paid at a target performance score as soon as administratively practical after the change in control.

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(6) The value shown in the Voluntary Termination or Retirement column for Messrs. Morris and English is the value of the portion of these restricted stock units that vested due to their mandatory retirement at age 65. The resulting shares are subject to a two year holding period.

(7) The value shown in the Voluntary Termination or Retirement column for Mr. Miller is the value of the portion of these restricted stock units that vested due to his retirement.

(8) The amount reported upon severance or a change in control represents the cost to the Company of providing subsidized medical and dental benefits at active employee rates for 18 months for those named executive officers who are not retirement-eligible. The amount reported upon death represents the present value of the cost to the Company of providing 50 percent subsidized medical coverage to the employee’s surviving spouse (until the spouse reaches age 65) and any surviving eligible dependent children (until each reaches age 26).

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

(10) Represents a reduction in the lump sum change in control benefit payment of up to 5 percent that applies for an executive officer if that reduction would avoid excise taxes under Section 4999 of the Internal Revenue Code.

(11) Represents a tax gross-up for the excise tax under section 4999 of the Internal Revenue Code, including all applicable taxes on this tax gross-up itself. The amount does not reflect any reductions attributable to non-compete agreements or other provisions to which the executive must agree in order to be eligible for change in control benefits. Effective January 1, 2012, Mr. Akins voluntarily relinquished this provision of his change in control agreement so he will not be entitled to this payment going forward.

The following table shows the value of previously earned and vested compensation and benefits as of December 31, 2011, that would have been provided to each named executive officer following a termination of his or her employment on December 31, 2011. For Ms. Tomasky, the amounts shown are the December 31, 2011 values of the compensation and benefits that she has and will receive due to her retirement on July 31, 2011. In all cases, these amounts were generally earned or vested over multiple years of service to the Company and only a portion is attributable to compensation for 2011.

Non-Incremental Post-Termination Compensation and Benefits on December 31, 2011

Name	Long-Term Incentives						Benefits
	Vested Stock Options (1)		Vested Performance Units (2)		AEP Career Shares (3)		Vacation Payout (4)		Post Retirement Benefits (5)		Deferred Compensation (6)
Michael G. Morris	$	1,571,950	$	7,578,774	$	8,206,562	$	117,995	$	4,848,920	$	3,393,974
Nicholas K. Akins		—	$	1,234,673	$	1,521,984	$	88,269	$	704,830	$	634,886
Brian X. Tierney		—	$	1,234,673	$	636,215	$	26,495	$	628,458	$	1,512,093
Robert P. Powers		—	$	1,746,587	$	1,798,348	$	32,500	$	3,179,354	$	2,488,438
Carl L. English		—	$	2,659,951	$	2,821,473	$	81,412	$	621,755	$	554,007
D. Michael Miller		—	$	403,640	$	344,154	$	31,538	$	1,620,816	$	681,810
Susan Tomasky		—	$	1,513,309	$	4,950,136	$	55,781	$	4,629,369	$	1,552,867

(1) Represents the value that would have been realized had the named executive officer exercised his vested and outstanding stock options at the closing price of AEP common stock on December 31, 2011.

(2) Represents the value of performance units that vested on December 31, 2011 calculated using the market value of these shares on December 31, 2011. However, the actual value realized from these shares in February 2012 was based on the previous 20-day average closing market price of AEP common stock as of the vesting date. For a more detailed discussion of vesting of performance units, see page 58

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(3) 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, 2011. However, the actual value that would have been realized from these AEP share equivalents would have been determined using the previous 20-day average closing market price of AEP common stock as of the date of termination.

(4) Represents accumulated but unused vacation.

(5) 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. For Messrs. Powers and Miller, who were eligible to receive AEP’s retiree medical, dental and life insurance benefits, it also includes the actuarial present value of these postretirement welfare benefits. For Mr. Morris, whose employment agreement entitles him to retiree medical benefits, it also includes the actuarial present value of such benefits

(6) 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 (3).

Upon his December 31, 2011 retirement Mr. Miller received a $500,000 payment, which is discussed in the notes to the All Other Compensation table on page 51.

In addition to the amounts shown above in Non-Incremental Post-Termination Compensation and Benefits on December 31, 2011, Ms. Tomasky has received or will receive the following compensation and benefits pursuant to her retirement:

• A separation payment of $893,250 in connection with her separation and release of all claims agreement, which is included in the Summary Compensation Table on page 50;

• An annual incentive award of $214,219 for 2011, which is also included in the Summary Compensation Table on page 50;

• Payments for the 2010 – 2012 and 2011 – 2013 performance unit awards, if any, will be calculated based on the performance scores for these performance periods and prorated to reflect the 19 months and 7 months, respectively, of the 36 month performance and vesting periods that she was employed by AEP before she retired. The actual amount paid will depend on the performance score and will not be paid until the end of the three year performance period;

• A prorated portion of the restricted stock unit awards granted to her effective January 1, 2011; prorated to reflect the 7 months of the 40 month performance and vesting periods that she was employed by AEP before she retired; which is included in the Options Exercised and Stock Vested for 2011 table and footnote (2) on page 58;

• Outplacement services and one year of continued financial counseling services with maximum values of $28,000 and $11,450, respectively.

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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 22, 2011 for all Directors, 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			Stock Units(a)		Retainer Deferral Plan Stock Units(b)		Options Exercisable Within 60 Days		Total
N. K. Akins		—			139,170		—		—		139,170
D. J. Anderson		—			2,574		—		—		2,574
J. F. Cordes		—			8,301		—		—		8,301
R. D. Crosby, Jr.		—			20,965		—		—		20,965
C. E. English		26,952			68,300		—		—		95,252
L. A. Goodspeed		—			21,674		—		—		21,674
T. Hoaglin		1,000			15,693		—		—		16,693
L. A. Hudson, Jr.		1,853	(d)		39,779		—		—		41,632
D. M. Miller		23,799	(c)		8,331		—		—		32,130
M. G. Morris		253,424			198,658		—		149,000		601,082
R. C. Notebaert		—			2,574		—		—		2,574
L. L. Nowell III		—			25,108		—		—		25,108
R. P. Powers		21,561	(c)		119,730		—		—		141,291
R. L. Sandor		1,092			33,427		3,536		—		38,055
B. X. Tierney		40,486	(c)		92,510		—		—		132,996
S. Tomasky		5,361	(c)		119,829		—		—		125,190
S. Martinez Tucker		1,532	(e)		11,920		—		—		13,452
J. F. Turner		—			13,931		—		—		13,931
All directors, nominees and executive officers as a group (22 persons)		380,087	(f)		942,474		3,536		149,000		1,475,097

(a) This column includes amounts deferred in stock units and held under the Stock Unit Accumulation Plan for Non-Employee Directors and held under AEP’s various executive benefit plans. Includes the following numbers of career shares: Mr. Morris, 198,658; Mr. Akins, 36,843; Mr. English, 68,300; Mr. Miller, 8,331; Mr. Powers, 43,533; Mr. Tierney, 15,401; Ms. Tomasky, 119,829; and all directors and executive officers as a group, 490,895.

(b) This column reflects amounts held in the Retainer Deferral Plan for Non-Employee Directors.

(c) Includes share equivalents held in the AEP Retirement Savings Plan and the AEP Supplemental Retirement Savings Plan.

(d) Includes 750 shares held by family members of Dr. Hudson over which he disclaims beneficial ownership.

(e) Includes 32 shares held by family members of Ms. Tucker over which she disclaims beneficial ownership.

(f) Represents less than 1 percent of the total number of shares outstanding.

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

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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, 2011, AEP believes that all Section 16(a) filing requirements were met during 2011 except that Michael G. Morris, Nicholas K. Akins, Joseph M. Buonaiuto, Carl L. English, D. Michael Miller, Robert P. Powers and Brian X. Tierney did not timely report acquisitions of restricted stock units on January 2, 2011, although each of them reported their respective acquisitions shortly thereafter.

Share Ownership of Certain Beneficial Owners

Set forth below are the only persons or groups known to AEP as of February 29, 2012, 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. 40 East 52nd Street New York, NY 10022		30,452,463	(a)		6.31	%
State Street Corporation. One Lincoln Street Boston, MA 02111		24,781,911	(b)		5.1	%

(a) Based on the Schedule 13G filed with the SEC, BlackRock, Inc. reported that it has sole power to vote 30,452,463 shares and sole dispositive power for 30,452,463 shares.

(b) Based on the Schedule 13G filed with the SEC, State Street Corporation, on behalf of its wholly-owned subsidiaries State Street Global Advisors France S.A., State Street Bank and Trust Company, SSGA Funds Management, Inc., State Street Global Advisors Limited, State Street Global Advisors LTD, State Street Global Advisors, Australia Limited, State Street Global Advisors Japan Co., LTD, State Street Global Advisors, Asia Limited and SSARIS Advisors LLC, reported that they have shared power to vote 24,781,911 shares and sole dispositive power for 24,781,911 shares.

Shareholder Proposals and Nominations

To be included in AEP’s proxy statement and form of proxy for the 2013 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 15, 2012.

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, 2012. The Assistant Secretary will forward the recommendations to the Committee on Directors and Corporate Governance for consideration.

For any proposal intended to be presented by a shareholder without inclusion in AEP’s proxy statement and form of proxy for the 2013 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 30, 2013. 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.

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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 compensation, other than their regular salaries, 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 $9,500, plus reasonable out-of-pocket expenses.

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Exhibit A

AMERICAN ELECTRIC POWER COMPANY, INC.

SENIOR OFFICER INCENTIVE PLAN

ARTICLE I

INTRODUCTION AND PURPOSE

American Electric Power Company, Inc. previously adopted the American Electric Power System Senior Officer Annual Incentive Compensation Plan (the “Incentive Plan”) effective January 1, 1997. This document amends and restates the Incentive Plan effective as of February 28, 2012 (the date the changes made by this Incentive Plan by resolution of the Human Resources Committee were ratified by Board of Directors of the Company) (the “Effective Date”). Any changes made to the Incentive Plan by this document shall not affect Awards granted prior to the Effective Date. Grants of Awards under the Incentive Plan, as amended hereby, may be made on or after the Effective Date.

ARTICLE II

DEFINITIONS

For purposes of the Plan, the following terms shall have the following meanings:

(a) “Award” means an incentive award, which entitles a Participant to receive a payment from the Company or a Subsidiary pursuant to Article IV, subject to such terms and conditions as the Committee may prescribe.

(b) “Board” means the Board of Directors of the Company.

(c) “Code” means the Internal Revenue Code of 1986, as amended from time to time, or any successor statute, and applicable regulations.

(d) “Committee” means the Human Resources Committee of the Board or such other committee or subcommittee as may be designated by the Board to oversee the Company’s executive compensation; provided that any such Committee shall consist of two or more persons, each of whom is an “outside director” within the meaning of Code Section 162(m).

(e) “Company” means American Electric Power Company, Inc., a New York corporation.

(f) “Covered Employee” means a Participant who the Committee determines meets the definition of a Covered Employee as defined in Code Section 162(m)(3).

(g) “Effective Date” is defined in Article I.

(h) “Participant” means a corporate officer of the Company or of a Subsidiary who is granted an Award by the Committee.

(i) “Performance-Based Compensation” means an Award that is intended to constitute “remuneration payable solely on account of the attainment of one or more or performance goals” or “qualified performance-based compensation” within the meaning of Section 162(m)(4)(C) of the Code and the regulations promulgated thereunder.

(j) “Performance Objective” is defined in Section 4.2.

(k) “Performance Period” is defined in Section 4.2.

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(l) “Plan” means the American Electric Power System Senior Officer Incentive Plan, as set forth herein and as amended from time to time.

(m) “Subsidiary” means any corporation (other than the Company), limited liability company, partnership or other business organization of which a majority of the outstanding voting stock or voting power is beneficially owned directly or indirectly by the Company.

ARTICLE III

ELIGIBILITY

Awards may be granted to any Participant from time to time by the Committee. The Committee shall determine the terms, conditions, and limitations applicable to each Award consistent with the Plan. Designation by the Committee as a Participant for an Award in one period shall not confer on such Participant the right to participate in the Plan for any other period.

ARTICLE IV

INCENTIVE AWARDS

Section 4.1. General.

(a) Awards may be granted to a Participant in such amounts and upon such terms, and at any time and from time to time, as shall be determined by the Committee. The Committee, at the time an Award is made, shall specify the terms and conditions which govern the Award, which terms and conditions shall prescribe that the Award shall be earned only upon, and to the extent that, Performance Objectives as described in Section 4.2, are satisfied within a designated time.

(b) Different terms and conditions may be established by the Committee for different Awards and for different Participants with respect to the same or different Performance Periods.

Section 4.2. Performance Objectives. The vesting and payment of Awards shall be contingent upon the degree of attainment of such performance goal(s) (the “Performance Objectives”) over such period (the “Performance Period”) as shall be specified by the Committee at the time the Award is granted. Performance Objectives will be established prior to or within the first ninety (90) days of each Performance Period (or within the first 25% of the Performance Period, if the Performance Period is shorter than 360 days).

The criteria for developing the Performance Objectives upon which payment or vesting of an Award intended to qualify for the exemption under Code Section 162(m) may be based shall be limited to one or more of the following, as determined by the Committee: (i) earnings measures: primary earnings per share; fully diluted earnings per share; net income; pre-tax income; operating income; earnings before interest, taxes, depreciation and amortization; net operating profits after taxes; income before income taxes, minority interest and equity earnings; income before discontinued operations, extraordinary items and cumulative effect of accounting changes, or any combination thereof; (ii) expense control: operations & maintenance expense; total expenditures; expense ratios; and expense reduction; (iii) customer measures: 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; (iv) safety measures: recordable case rate; severity rate; and vehicle accident rate; (v) diversity measures: minority placement rate and utilization; (vi) environmental measures: emissions; project completion milestones; regulatory/legislative/cost recovery goals; and notices of violation; (vii) revenue measures: revenue and margin; (viii) shareholder return measures: 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

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return on investment and cash flow in excess of cost of capital or any combination thereof; (ix) valuation measures: stock price increase; price to book value ratio; and price to earnings ratio; (x) capital and risk measures: debt to equity ratio and dividend payout as percentage of net income; (xi) employee satisfaction; (xii) project measures: completion of key milestones; (xiii) production measures: generating capacity factor; performance against the Institute of Nuclear Power Operation index; generating equivalent availability; heat rates and production cost. The targeted level or levels of performance with respect to such business criteria may be established at such levels and in such terms as the Committee may determine, in its discretion, including in absolute terms, as a goal relative to performance in prior periods (e.g., earnings growth), or as a goal compared to the performance of one or more comparable companies or an index covering multiple companies.

Performance Objectives may relate to attainment of specified objectives by the Participant or by the Company or one or more Subsidiaries, including a division or a department of the Company or of one or more Subsidiaries.

Section 4.3. Payment of Awards. An Award shall not become payable unless, after the expiration of the Performance Period, the Committee has certified either that the Performance Objectives with respect to such Award have been satisfied or the level of attainment of each Performance Objective. Unless otherwise expressly stated in the terms and conditions of a particular Award, the Committee retains the power, authority and discretion to reduce or eliminate, but not to increase, the amount calculated as payable under the terms of any Award in order to reflect other performance criteria. Payment of such Awards that have been certified shall be made to Participants in a single lump sum in cash at such time determined by the Committee, and generally no later than two and one-half months after the end of the Performance Period; provided that unless otherwise clearly specified in the terms and conditions of a particular Award, payment shall be made no later than 2-1/2 months after the end of the calendar year during which the Award became vested, or as soon as practical thereafter. In no event shall any Participant receive an Award payment or payments in any fiscal year that exceeds the lesser of (i) $6,000,000 or (ii) 400% of the Participant’s base salary (prior to any salary reduction or deferral elections) as of the date of grant of the Award.

Section 4.4. Recoupment of Incentive Compensation. Each Participant who is granted an Award shall reimburse the amount awarded, earned, received or paid under such Award if the Committee, in its discretion, determines that: (i) the Award or any compensation resulting from it was predicated upon the achievement of financial or other results that were subsequently materially restated or corrected, and (ii) the Participant engaged in misconduct that caused or partially caused the need for the restatement or correction, and (iii) a lower payment would have been made to the Participant based upon the restated or corrected financial results. If and to the extent that the Committee, in its sole discretion, determines that the conditions set forth in (i) through (iii) have been met and such reimbursement is warranted by the facts and circumstances of the particular case or if the applicable legal requirements impose more stringent requirements on the Company or any of its Subsidiaries to obtain reimbursement of such compensation, then the Participant will be required to reimburse Company or its Subsidiaries, as applicable, for the value of such compensation paid to that Participant. The Company or its Subsidiaries, as applicable, also may retain any deferred compensation previously credited to the Participant and not paid, provided that the Company or its Subsidiaries, as applicable, will retain such deferred compensation only if, when and to the extent that it otherwise becomes payable to the Participant. This right to reimbursement is in addition to, and not in substitution for, any and all other rights the Company and its Subsidiaries might have to pursue reimbursement or such other remedies against an employee for misconduct in the course of employment or otherwise based on applicable legal considerations, all of which are expressly retained by the Company and its Subsidiaries.

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ARTICLE V

ADMINISTRATION

The Plan shall be administered by the Committee. The Committee shall have all of the powers necessary to enable it to properly carry out its duties under the Plan. Not in limitation of the foregoing, the Committee shall have the power and discretion to construe and interpret the Plan and to determine all questions that shall arise thereunder. The Committee shall have such other and further specified duties, powers, authority and discretion as are elsewhere in the Plan either expressly or by necessary implication conferred upon it. The Committee may appoint such agents, who need not be members of the Committee, as it may deem necessary for the effective performance of its duties, and may delegate to such agents such powers and duties as the Committee may deem expedient or appropriate that are not inconsistent with the intent of the Plan to the fullest extent permitted under applicable law. The decision of the Committee or any agent of the Committee upon all matters within the scope of its authority shall be final and conclusive on all persons.

ARTICLE VI

AMENDMENT AND TERMINATION

Section 6.1. Amendment of Plan. The Company has the right, at any time and from time to time, to amend in whole or in part any of the terms and provisions of the Plan to the extent permitted by law for whatever reason(s) the Company may deem appropriate; provided, however, that any such amendment which requires approval of the Company’s shareholders in order to maintain the qualification of Awards as performance-based compensation pursuant to Code Section 162(m) (4)(C) shall not be made without such approval.

Section 6.2. Termination of Plan. The Company expressly reserves the right, at any time, to suspend or terminate the Plan to the extent permitted by law for whatever reason(s) the Company may deem appropriate, including, without limitation, suspension or termination as to any Subsidiary, Employee, or class of Employees.

Section 6.3. Procedure for Amendment or Termination. Any amendment to the Plan or termination of the Plan shall be made by the Company by resolution of the Committee and shall not require the approval or consent of any Subsidiary or Participant to be effective to the extent permitted by law. Any amendment to the Plan or termination of the Plan may be retroactive to the extent not prohibited by applicable law.

ARTICLE VII

MISCELLANEOUS

Section 7.1. Rights of Employees. Status as an eligible Employee shall not be construed as a commitment that any Award will be made under the Plan to such eligible Employee or to eligible Employees generally. Nothing contained in the Plan (or in any other documents related to this Plan or to any Award) shall confer upon any Employee any right to continue in the employ or service of the Company or any Subsidiary or constitute any contract or limit in any way the right of the Company to change such person’s compensation or other benefits or to terminate the employment or service of such person with or without cause.

Section 7.2. Unfunded Status. The Plan shall be unfunded. Neither the Company, any Subsidiary, the Committee, nor the Board shall be required to segregate any assets that may at any time be represented by Awards made pursuant to the Plan. Neither the Company, any Subsidiary, the Committee, nor the Board shall be deemed to be a trustee of any amounts to be paid under the Plan.

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Section 7.3. Limits on Liability. Any liability of the Company or any Subsidiary to any Participant with respect to an Award shall be based solely upon contractual obligations created by the Plan. Neither the Company nor any Subsidiary nor any member of the Board or the Committee, nor any other person participating in any determination of any question under the Plan, or in the interpretation, administration or application of the Plan, shall have any liability to any party for any action taken or not taken in good faith under the Plan. To the extent permitted by applicable law, the Company shall indemnify and hold harmless each member of the Board and the Committee from and against any and all liability, claims, demands, costs, and expenses (including the costs and expenses of attorneys incurred in connection with the investigation or defense of claims) in any manner connected with or arising out of any actions or inactions in connection with the administration of the Plan except for such actions or inactions which are not in good faith or which constitute willful misconduct.

Section 7.4. Interpretation. Unless otherwise expressly stated by the Committee with respect to an Award, each Award granted to a Covered Employee under the Plan is intended to (i) be Performance-Based Compensation that is fully deductible by the Company for federal income taxes and not subject to the deduction limitation of Section 162(m) of the Code and (ii) comply with the requirements of Code Section 409A (including by reason of being exempt from the application of Code Section 409A), and the Plan shall be construed or deemed amended to the extent possible to conform any Award to effect such intent. The Committee shall not have any discretion to determine that an Award will be paid to a Covered Employee if the Performance Objective for such Award is not attained.

Section 7.5. Tax Withholding. The Company shall be entitled to withhold from any payment made under the Plan the full amount of any required federal, state or local taxes or such other amounts as may be required by applicable law.

Section 7.6. Nontransferability of Benefits. A Participant may not assign or transfer any interest in an Award. Notwithstanding the foregoing, upon the death of a Participant, the Participant’s rights and benefits under the Plan shall pass by will or by the laws of descent and distribution.

Section 7.7. Governing Law. To the extent not governed by federal law, the Plan shall be construed in accordance with and governed by the laws of the State of Ohio.

ARTICLE VIII

EFFECTIVE DATE; DURATION OF THE PLAN

The Plan shall be effective as of the Effective Date. Notwithstanding any provision of this Plan to the contrary, this Plan shall be subject to approval by a vote of the shareholders of the Company at its 2012 annual meeting, and such shareholder approval shall be a pre-condition to the right of any Participant to receive any benefits pursuant to an Award made under this Plan on or after the Effective Date.

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Exhibit B

Financial Results for 2011

Reconciliation of Ongoing to GAAP Reported Earnings

	EPS
Ongoing Earnings	$	3.12
Special Items
Texas Capacity Auction, Tax		1.16
Normalization & Carrying Charges
Sporn Unit 5 Retirement		(0.06	)
Muskingum River Unit 5 – Suspended Scrubber Project		(0.06	)
Turk Impairment		(0.07	)
Carbon Capture & Storage		(0.03	)
Litigation Settlement – Enron Bankruptcy		(0.05	)
Other		0.01
GAAP Reported Earnings	$	4.02

B-1

		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 24, 2012.
			Vote by Internet
			• Go to www.envisionreports.com/AEP
			• Or scan the QR code with your smartphone
			• Follow the steps outlined on the secure website
			Vote by telephone
			• Call toll free 1-800-652-VOTE (8683) within the USA, US territories & Canada on a touch tone telephone
Using a black ink pen, mark your votes with an X as shown in this example. Please do not write outside the designated areas.	x		• Follow the instructions provided by the recorded message

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 and 4.

1.

Election of Directors:

For

Against

Abstain

For

Against

Abstain

For

Against

Abstain

+

01 - Nicholas K. Akins

¨

¨

¨

02 - David J. Anderson

¨

¨

¨

03 - James F. Cordes

¨

¨

¨

04 - Ralph D. Crosby, Jr.

¨

¨

¨

05 - Linda A. Goodspeed

¨

¨

¨

06 - Thomas E. Hoaglin

¨

¨

¨

07 - Michael G. Morris

¨

¨

¨

08 - Richard C. Notebaert

¨

¨

¨

09 - Lionel L. Nowell III

¨

¨

¨

10 - Richard L. Sandor

¨

¨

¨

11 - Sara Martinez Tucker

¨

¨

¨

12 - John F. Turner

¨

¨

¨

		For	Against	Abstain			For	Against	Abstain
2.	Approval of the American Electric Power System Senior Officer Incentive Plan.	¨	¨	¨	3.	Ratification of the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2012.	¨	¨	¨
4.	Advisory approval of the Company’s executive compensation	¨	¨	¨

 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.

American Electric Power Company, Inc.

2012 Annual Meeting of Shareholders and Admission Ticket

Tuesday April 24, 2012, at 9:30 a.m. Central Time

The Renaissance Tulsa Hotel and Convention Center

6808 South 107th East Avenue

Tulsa, Oklahoma

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 Ratification of Auditors	Ÿ Chief Executive Officer’s Report
Ÿ Election of Directors	Ÿ Advisory approval of the Company’s    executive compensation	Ÿ Comments and Questions from Shareholders
Ÿ Approval of Senior Officer Incentive Plan

Directions to Renaissance Tulsa Hotel & Convention Center (918) 307-2600 Take I-244 East to 169 South. Follow 169 South to 71st Street exit. Turn left onto 71st Street and head east to 109th East Avenue. Turn left and follow 109th East Avenue to stop sign. Turn left on 69th Street to hotel entrance.

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

+

Proxy — American Electric Power Company, Inc.

Proxy Solicited on behalf of the Board of Directors for the Annual Meeting to be held April 24, 2012

The shareholder signing on the reverse of this proxy card appoints Michael G. Morris, 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 24, 2012, 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 - James F. Cordes	04 - Ralph D. Crosby, Jr.	05 - Linda A. Goodspeed	06 - Thomas E. Hoaglin
07 - Michael G. Morris	08 - Richard C. Notebaert	09 - Lionel L. Nowell III	10 - Richard L. Sandor	11 - Sara Martinez Tucker	12 - John F. Turner

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. +

EX-99

Appendix A to the

Proxy Statement

American Electric Power

2011 Annual Report

Audited Consolidated Financial Statements and

Management’s Financial Discussion and Analysis

CONTENTS	AMERICAN ELECTRIC POWER 1 Riverside Plaza Columbus, Ohio 43215-2373
Glossary of Terms		i
Forward-Looking Information		iv
AEP Common Stock and Dividend Information		vi
Selected Consolidated Financial Data		1
Management’s Financial Discussion and Analysis		2
Reports of Independent Registered Public Accounting Firm		43-44
Management’s Report on Internal Control Over Financial Reporting		45
Consolidated Statements of Income		46
Consolidated Statements of Comprehensive Income (Loss)		47
Consolidated Statements of Changes in Equity		48
Consolidated Balance Sheets		49-50
Consolidated Statements of Cash Flows		51
Index of Notes to Consolidated Financial Statements		52
Corporate and Shareholder Information		148
Executive Leadership Team		149

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., a holding company.
AEP Consolidated	AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit	AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East companies	APCo, I&M, KPCo and OPCo.
AEP Foundation	AEP charitable organization created in 2005 for charitable contributions in the communities in which AEP’s subsidiaries operate.
AEP Power Pool	Members are APCo, I&M, KPCo and OPCo.  The AEP Power Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEP System or the System	American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP West companies	PSO, SWEPCo, TCC and TNC.
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, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC	Allowance for Funds Used During Construction.
AOCI	Accumulated Other Comprehensive Income.
APCo	Appalachian Power Company, an AEP electric utility subsidiary.
APSC	Arkansas Public Service Commission.
ASU	Accounting Standard Update.
BOA	Bank of America Corporation.
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.
CSPCo	Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
CSW	Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW 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.
CTC	Competition Transition Charge, a transition charge applied to TCC’s transmission and distribution rates for stranded costs and other true-up amounts as required by the Texas Restructuring Legislation.
CWIP	Construction Work in Progress.
DCC Fuel	DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC and DCC Fuel IV LLC, consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DETM	Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DHLC	Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
E&R	Environmental compliance and transmission and distribution system reliability.
EIS	Energy Insurance Services, Inc., a nonaffiliated captive insurance company.

i

Term	Meaning
ENEC	Expanded Net Energy Charge.
ERCOT	Electric Reliability Council of Texas regional transmission organization.
ESP	Electric Security Plans, filed with the PUCO, pursuant to the Ohio Amendments.
ETA	Electric Transmission America, LLC an equity interest joint venture with MidAmerican Energy Holdings Company America Transco, LLC formed to own and operate electric transmission facilities in North America outside of ERCOT.
ETT	Electric Transmission Texas, LLC, an equity interest joint venture between AEP and MidAmerican Energy Holdings Company Texas Transco, LLC 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.
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, defining the sharing of costs and benefits associated with their respective generating plants.
IRS	Internal Revenue Service.
IURC	Indiana Utility Regulatory Commission.
I&M	Indiana Michigan Power Company, an AEP electric utility subsidiary.
JMG	JMG Funding LP.
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 AEP Power Pool transactions to its members.
MMBtu	Million British Thermal Units.
MPSC	Michigan Public Service Commission.
MTM	Mark-to-Market.
MW	Megawatt.
NEIL	Nuclear Electric Insurance Limited insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks.
NOx	Nitrogen oxide.
Nonutility Money Pool	AEP’s Nonutility Money Pool is the centralized funding mechanism AEP uses to meet the short term cash requirements of pool participants.
NSR	New Source Review.
OCC	Corporation Commission of the State of Oklahoma.
OPCo	Ohio Power Company, an AEP electric utility subsidiary.
OPEB	Other Postretirement Benefit Plans.

ii

Term	Meaning
OTC	Over the counter.
OVEC	Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
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 generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
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.
SEET	Significantly Excessive Earnings Test.
SEC	U.S. Securities and Exchange Commission.
SIA	System Integration Agreement, effective June 15, 2000, 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.
Stall Unit	J. Lamar Stall Unit at Arsenal Hill Plant.
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 and AEP Texas Central Transition Funding II 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 law.
True-up Proceeding	A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.
Turk Plant	John W. Turk, Jr. Plant.
Utility Money Pool	AEP System’s Utility Money Pool is the centralized funding mechanism AEP uses to meet the short term cash requirements of pool participants.
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.

iii

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 Financial Discussion and Analysis,” 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:

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

· Inflationary or deflationary interest rate trends.

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

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

· Electric load, customer growth and the impact of retail competition, particularly in Ohio due to the February 2012 PUCO rehearing order.

· Weather conditions, including storms, and our ability to recover significant storm restoration costs through applicable rate mechanisms.

· Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.

· Availability of necessary generating capacity and the performance of our generating plants.

· Our ability to resolve I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration and outage-related issues through warranty, insurance and the regulatory process.

· Our ability to recover regulatory assets and stranded costs in connection with deregulation.

· Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.

· Our ability to build or acquire generating 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 (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.

· 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 and cost recovery of our plants and related assets.

· A reduction in the federal statutory tax rate.

· 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.

· Resolution of litigation.

· Our ability to constrain operation and maintenance costs.

· Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.

· Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.

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

· Volatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities.

iv

· Changes in utility regulation, including the implementation of ESPs and the expected legal separation and transition to market for generation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.

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

· 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 on future funding requirements.

· Prices and demand for power that we generate and sell at wholesale.

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

· Our ability to recover through rates or market prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.

· Our ability to successfully manage negotiations with stakeholders and obtain regulatory approval to terminate or amend the Interconnection Agreement and break up or modify the AEP Power Pool.

· Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.

· 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.

v

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-End
Quarter Ended	High		Low		Closing Price		Dividend
December 31, 2011	$	41.71	$	35.85	$	41.31	$	0.47
September 30, 2011		38.98		33.09		38.02		0.46
June 30, 2011		38.99		34.37		37.68		0.46
March 31, 2011		36.92		33.47		35.14		0.46
December 31, 2010	$	37.94	$	34.92	$	35.98	$	0.46
September 30, 2010		36.93		31.87		36.23		0.42
June 30, 2010		35.00		28.17		32.30		0.42
March 31, 2010		36.86		32.68		34.18		0.41

AEP common stock is traded principally on the New York Stock Exchange.  At December 31, 2011, AEP had approximately 87,000 registered shareholders.

vi

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
			2011		2010			2009		2008		2007
			(dollars in millions, except per share amounts)
STATEMENTS OF INCOME DATA
Total Revenues			$	15,116	$	14,427		$	13,489	$	14,440	$	13,380
Operating Income			$	2,782	$	2,663		$	2,771	$	2,787	$	2,319
Income Before Discontinued Operations and Extraordinary Items			$	1,576	$	1,218		$	1,370	$	1,376	$	1,153
Discontinued Operations, Net of Tax				-		-			-		12		24
Income Before Extraordinary Items				1,576		1,218			1,370		1,388		1,177
Extraordinary Items, Net of Tax				373		-			(5)		-		(79)
Net Income				1,949		1,218			1,365		1,388		1,098
Net Income Attributable to Noncontrolling Interests				3		4			5		5		6
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS				1,946		1,214			1,360		1,383		1,092
Preferred Stock Dividend Requirements of Subsidiaries Including
	Capital Stock Expense			5		3			3		3		3
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS			$	1,941	$	1,211		$	1,357	$	1,380	$	1,089
BALANCE SHEETS DATA
Total Property, Plant and Equipment			$	55,670	$	53,740		$	51,684	$	49,710	$	46,145
Accumulated Depreciation and Amortization				18,699		18,066			17,340		16,723		16,275
Total Property, Plant and Equipment – Net			$	36,971	$	35,674		$	34,344	$	32,987	$	29,870
Total Assets			$	52,223	$	50,455		$	48,348	$	45,155	$	40,319
Total AEP Common Shareholders’ Equity			$	14,664	$	13,622		$	13,140	$	10,693	$	10,079
Noncontrolling Interests			$	1	$	-		$	-	$	17	$	18
Cumulative Preferred Stock Not Subject to Mandatory Redemption			$	-	$	60		$	61	$	61	$	61
Long-term Debt (a)			$	16,516	$	16,811		$	17,498	$	15,983	$	14,994
Obligations Under Capital Leases (a)			$	458	$	474	(b)	$	317	$	325	$	371
AEP COMMON STOCK DATA
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders:
Income Before Discontinued Operations and Extraordinary Items			$	3.25	$	2.53		$	2.97	$	3.40	$	2.87
Discontinued Operations, Net of Tax				-		-			-		0.03		0.06
Income Before Extraordinary Items				3.25		2.53			2.97		3.43		2.93
Extraordinary Items, Net of Tax				0.77		-			(0.01)		-		(0.20)
Total Basic Earnings per Share Attributable to AEP Common Shareholders			$	4.02	$	2.53		$	2.96	$	3.43	$	2.73
Weighted Average Number of Basic Shares Outstanding (in millions)				482		479			459		402		399
Market Price Range:
		High	$	41.71	$	37.94		$	36.51	$	49.11	$	51.24
		Low	$	33.09	$	28.17		$	24.00	$	25.54	$	41.67
Year-end Market Price			$	41.31	$	35.98		$	34.79	$	33.28	$	46.56
Cash Dividends Declared per AEP Common Share			$	1.85	$	1.71		$	1.64	$	1.64	$	1.58
Dividend Payout Ratio				46.02%		67.59%			55.41%		47.8%		57.9%
Book Value per AEP Common Share			$	30.36	$	28.32		$	27.49	$	26.35	$	25.17
(a)		Includes portion due within one year.
(b)		Obligations Under Capital Leases increased primarily due to capital leases under new master lease agreements for property that was previously leased
		under operating leases.

1

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

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:

· Almost 36,500 megawatts of generating capacity, one of the largest complements of generation in the U.S.

· Approximately 39,000 miles of transmission lines, including 2,116 miles of 765kV lines, the backbone of the electric interconnection grid in the Eastern U.S.

· Approximately 223,000 miles of distribution lines that deliver electricity to 5.3 million customers.

· Substantial commodity transportation assets (more than 7,600 railcars, approximately 3,300 barges, 61 towboats, 29 harbor boats and a coal handling terminal with 18 million tons of annual capacity).  Our commercial barging operations annually transport approximately 44 million tons of coal and dry bulk commodities.  Approximately 37% of the barging is for transportation of agricultural products, 31% for coal, 16% for steel and 16% for other commodities.

CSPCo-OPCo Merger

On December 31, 2011, CSPCo merged into OPCo with OPCo being the surviving entity.  All prior disclosed amounts have been recast as if the merger occurred on the first day of the earliest reporting period.   All contracts and operations of CSPCo and its subsidiary are now part of OPCo.  The merger had no impact on our prior reported net income, cash flow or financial condition.

January 2012 – May 2016 Ohio ESP

In December 2011, the PUCO approved a modified stipulation for a new ESP for the period January 2012 through May 2016 that includes a standard service offer (SSO) pricing for generation.  Various parties, including OPCo, filed requests for rehearing with the PUCO.  In February 2012, the PUCO issued an entry on rehearing which rejected the modified stipulation and ordered a return to the 2011 ESP rates until a new rate plan is approved.  Under the February 2012 rehearing order, OPCo has 30 days to notify the PUCO whether it plans to modify or withdraw its original application as filed in January 2011.  Management is currently evaluating its options and the potential financial and operational impacts on OPCo.  See “Ohio Electric Security Plan Filing” section of Note 3.

Ohio Customer Choice

In our Ohio service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service.  As a result, in comparison to 2010, we lost approximately $132 million of generation and transmission related gross margin.  We are recovering a portion of lost margins through collection of capacity and transmission revenues from competitive CRES providers, off-system sales and new revenues from our CRES provider.  AEP Retail Energy Partners LLC, our CRES provider and member of our Generating and Marketing segment, targets retail customers in Ohio, both within and outside of our retail service territory.  As a result of the February 2012 order on rehearing, OPCo is subject to significant risk of revenue loss associated with customer switching, which could materially reduce future net income and cash flows and materially impact financial condition.  Currently, there are no limitations on the obligation of OPCo to provide below cost capacity rate pricing to alternative suppliers to support customers switching in Ohio.  As a result of customer switching, for every 10% decline in the number of retail customers, management estimates OPCo could lose approximately $75 million of generation gross margin, net of estimated off-system sales.  On February 27, 2012, OPCo filed a Motion for Relief and Request for Expedited Ruling with the PUCO related to the review of capacity charges.  The filing seeks a decision within 90 days and the avoidance of an immediate change to pricing for capacity at the Reliability Pricing Model auction price, which is substantially below OPCo’s cost.  We are evaluating our options to challenge this capacity pricing issue.

2

In January 2012, we entered into an agreement to acquire BlueStar Energy Holdings, Inc. (BlueStar) and its independent retail electric supplier BlueStar Energy Solutions.  BlueStar provides electric supply for retail customers in Ohio, Illinois and other deregulated electricity markets and also provides energy solutions, including demand response and energy efficiency services, nationwide.  BlueStar has approximately 21,000 customer accounts.  Consummation of the transaction is subject to regulatory and other approvals.  The transaction is expected to close in the first quarter of 2012.

Corporate Separation

In January 2012, the PUCO approved a corporate separation plan of OPCo’s generation assets to complete the transition to a fully competitive generation market by June 2015, which includes the transfer of generation assets to a nonregulated AEP subsidiary at net book value.  In February 2012, as part of the PUCO’s entry on rehearing which rejected the ESP modified stipulation, the PUCO revoked its approval of OPCo’s corporate separation plan.  Any proposed corporate separation plan will require approval by the PUCO and the FERC.  Management intends to pursue Ohio corporate separation in future regulatory proceedings.

In February 2012, prior to the PUCO revoking OPCo’s corporate separation plan, applications were filed with the FERC proposing to establish a new power cost sharing agreement between APCo, I&M and KPCo and transfer OPCo’s generation assets to APCo, KPCo and a nonregulated AEP subsidiary.  In conjunction with these filings, APCo and KPCo, which are generation capacity deficit utilities, filed an application with the FERC to acquire approximately 2,400 MWs of OPCo’s 12,000 MW generation capacity at net book value.  This acquisition would allow APCo and KPCo to satisfy their capacity reserve requirements in PJM and provide baseload generation to meet their customers’ energy requirements.  As a result of the February 2012 ESP rehearing order, we are reviewing the recoverability of all OPCo generation assets and are in the process of withdrawing the PUCO and the FERC applications.  We intend to file new FERC and PUCO applications related to corporate separation.  To the extent 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.  Upon receipt of all regulatory approvals, the remaining generation assets of OPCo will be owned by a nonregulated AEP subsidiary.

If we receive all regulatory approvals, our results of operations related to generation currently owned by OPCo will be determined by our ability to sell power and capacity at a profit at rates determined by the prevailing market.

Customer Demand

In comparison to 2010, cooling degree days in 2011 were up 20% in our western region and down 7% in our eastern region.  While cooling degree days in our eastern region were down in comparison to 2010, they were significantly higher than normal.  Our weather-normalized residential and commercial sales remained relatively flat in comparison to 2010.  Industrial sales increased 4% in 2011, primarily due to a significant increase in production from Ormet, a large aluminum company, and lesser increases from other industrial customers, reflecting an increase in production by several of our metals and refinery customers.  Commercial margins decreased 6% during 2011 primarily due to the loss of retail customers in Ohio.  See “Ohio Customer Choice” section below.

Texas Restructuring

In July 2011, the Supreme Court of Texas overturned a 2006 PUCT order that denied recovery of capacity auction true-up amounts related to TCC securitized net recoverable stranded generation cost and remanded for reconsideration the treatment of certain tax balances under normalization rules.  Based upon the Supreme Court of Texas’ reversal of the PUCT’s capacity auction true-up disallowance, TCC recorded $421 million of pretax income ($273 million, net of tax) in Extraordinary Items, Net of Tax on the statement of income in the third quarter of 2011.

Also in 2011, TCC recorded $271 million in pretax Carrying Costs Income on the statement of income related to the debt component of carrying costs for the period from January 2002 through December 2011.  This carrying costs income represents previously unrecorded earnings associated with restructuring in Texas since 2002.  The total regulatory asset related to the capacity auction true-up as of December 31, 2011 was $692 million, excluding unrecognized equity carrying costs.  TCC plans to continue to recognize debt carrying costs income until securitization occurs and plans to recognize equity carrying costs income as collected from customers over the life of the securitization.  Securitization is expected to be completed in March 2012.

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In December 2011, the PUCT approved an unopposed stipulation allowing TCC to recover $800 million, including carrying charges, and retain contested tax balances in full satisfaction of its true-up proceeding.  TCC recorded the reversal of regulatory credits of $65 million ($42 million, net of tax) and the reversal of $89 million of accumulated deferred investment tax credits ($58 million, net of tax) in Extraordinary Items, Net of Tax on the statement of income in the fourth quarter of 2011.  Also, in the fourth quarter of 2011, TCC recorded $52 million in pretax Carrying Costs Income on the statement of income.  See the “Texas Restructuring Appeals” and “TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes” sections of Note 3.

Regulatory Activity

The table below summarizes our significant 2011 regulatory activities:

			Requested			Approved
		Annual		Requested	Annual			Approved
		Requested		Return on	Approved			Return on	Approved
		Base Rate		Common	Base Rate			Common	Effective
Jurisdiction		Change		Equity	Change			Equity	Date
		(in millions)			(in millions)
Indiana		$	149	11.15%	$	(a)		(a)	(a)
Michigan			25	11.15%		15		10.2%	April 2012
Ohio			94	11.15%		-	(b)	10.2%	January 2012
Virginia			126	11.65%		55		10.9%	February 2012
West Virginia			156	11.75%		51		10.0%	April 2011
(a)	The Indiana base rate case is presently under review at the IURC.
(b)	Although the distribution base rate did not change, approximately $47 million was being recovered through the Distribution Investment Rider (DIR).  Due to the February 2012 PUCO ESP entry on rehearing, which rejected the modified stipulation for a new ESP, collection of the DIR terminated.  OPCo has the right to withdraw from the stipulation in its distribution base rate case.  Management is currently evaluating all of its options.

2009 – 2011 Ohio ESP

In 2011, the PUCO issued an order in the 2009 – 2011 ESP remand proceeding requiring OPCo to cease POLR billings and apply POLR collections since June 2011 first to the FAC deferral with any remaining balance to be credited to OPCo’s customers in November and December 2011.  As a result, in comparison to 2010, we lost approximately $71 million of pretax income related to POLR.  In February 2012, the Ohio Consumers’ Counsel (OCC) and the Industrial Energy Users-Ohio filed appeals with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which if ordered could total up to $698 million, excluding carrying costs.

OPCo filed its 2010 Significantly Excessive Earnings Test (SEET) with the PUCO based upon the approach in the PUCO’s 2009 order.  Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings, which included off-system sales in the SEET calculation.  In December 2011, the PUCO staff filed testimony that recommended a $23 million refund of 2010 earnings.  In the fourth quarter of 2011, OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO ordered SEET refund.  OPCo is required to file its 2011 SEET filing with the PUCO in 2012.  Management does not currently believe that there are significantly excessive earnings in 2011.  See “Ohio Electric Security Plan Filing” section of Note 3.

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Virginia Rate Adjustment Clause

In January 2012, the Virginia SCC issued an order related to a generation rate adjustment clause which requested recovery of the Dresden Plant costs.  The order allows APCo to recover $26 million annually, effective March 2012.  See “Rate Adjustment Clauses” section of Note 3.

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal generating unit in Arkansas, which is expected to be in service in the fourth quarter of 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  SWEPCo’s share of construction costs is currently estimated to be $1.3 billion, excluding AFUDC, plus an additional $122 million for transmission, excluding AFUDC.  SWEPCo submitted applications with the APSC, the LPSC and the PUCT for approval to build the Turk Plant.  The APSC and the LPSC approved SWEPCo’s applications.  However, in June 2010, the APSC issued an order which reversed and set aside the previously granted Certificate of Environmental Compatibility and Public Need (CECPN).  The PUCT approved SWEPCo’s application with several conditions, including a Texas jurisdictional capital costs cap.  In November 2011, the Texas Court of Appeals affirmed the PUCT’s order in all respects.  As a result, in the fourth quarter of 2011, SWEPCo recorded a pretax write-off of $49 million in Asset Impairments and Other Related Charges on the statement of income related to the estimated excess of the Texas jurisdictional portion of the Turk Plant above the Texas jurisdictional capital costs cap.  In December 2011, SWEPCo and the Texas Industrial Energy Consumers filed motions for rehearing at the Texas Court of Appeals which were denied in January 2012.  SWEPCo intends to seek review of the Texas Court of Appeals decision at the Supreme Court of Texas.

Several parties, including the Hempstead County Hunting Club, the Sierra Club and the National Audubon Society had challenged the air permit, the wastewater discharge permit and the wetlands permit that were issued for the Turk Plant.  In 2011, SWEPCo entered into settlement agreements with these parties which resolved all outstanding issues related to the permits and the APSC’s grant of a CECPN.  The parties dismissed all pending permit and CECPN challenges at the APSC, other administrative agencies and the courts.  See “Turk Plant” section of Note 3.

Cook Plant

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator.  Repair of the property damage and replacement of the turbine rotors and other equipment cost approximately $400 million.  Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process.  Due to the extensive lead time required to manufacture and install new turbine rotors, I&M repaired Unit 1 and it resumed operations in December 2009.  The installation of the new turbine rotors and other equipment occurred during the refueling outage of Unit 1 in the fall of 2011.  If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 5.

As a result of the nuclear plant situation in Japan following a March 2011 earthquake, the Nuclear Regulatory Commission (NRC) initiated a review of safety procedures and requirements for nuclear generating facilities.  This review could increase procedures and testing requirements, require physical modifications to the plant and increase future operating costs at the Cook Plant.  The NRC is also looking into the fuel used at eleven reactors, including the units at the Cook Plant.  Their concern relates to fuel temperatures if abnormal conditions are experienced.  We have been monitoring this issue and will respond to the NRC’s inquiry.In addition to the review by the NRC, Congress could consider legislation tightening oversight of nuclear generating facilities.  We are unable to predict the impact of potential future regulation of nuclear facilities.

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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 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to materially affect our net income, financial condition and cash flows.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with new 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, new proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.

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 are also engaged in the development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change.  We, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court.  The U.S. House of Representatives passed legislation called the Transparency in Regulatory Analysis of Impacts on the Nation (the TRAIN Act) that would delay implementation of certain Federal EPA rules and facilitate a comprehensive analysis of their impacts.  The Senate is considering similar legislation.  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.

We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  We should be able to recover certain of these expenditures through market prices in deregulated jurisdictions.  If not, the costs of environmental compliance could materially affect future net income, cash flows and possibly 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, 2011, the AEP System had a total generating capacity of nearly 36,500 MWs, of which 23,900 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, investment to meet these proposed requirements ranges from approximately $6 billion to $7 billion between 2012 and 2020.  These amounts include investments to convert 1,055 MWs of coal generation to natural gas capacity and the completion of 580 MWs of natural gas-fired generation in January 2012.

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 or federal implementation plans 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.

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Subject to the factors listed above and based upon our continuing evaluation, we may retire the following plants or units of plants before or during 2015:

		Generating
Company	Plant Name and Unit	Capacity
		(in MWs)
APCo	Clinch River Plant, Unit 3		235
APCo	Glen Lyn Plant		335
APCo	Kanawha River Plant		400
APCo/OPCo	Philip Sporn Plant, Units 1-4		600
I&M	Tanners Creek Plant, Units 1-3		495
KPCo	Big Sandy Plant, Unit 1		278
OPCo	Conesville Plant, Unit 3		165
OPCo	Kammer Plant		630
OPCo	Muskingum River Plant, Units 1-4		840
OPCo	Picway Plant		100
SWEPCo	Welsh Plant, Unit 2		528
Total			4,606

Duke Energy Corporation, the operator of W. C. Beckjord Generating Station, has announced its intent to close the facility in 2015.  OPCo owns 12.5% (54 MWs) of one unit at that station.

Effective December 1, 2011, we revised book depreciation rates for certain OPCo generating units consistent with shortened depreciable lives for the generating units.  This change in depreciable lives is expected to result in a $54 million increase in depreciation expense in 2012.  However, as a result of the January and February 2012 PUCO orders and the expected corporate separation of OPCo's generation assets and the termination of the AEP Power Pool, we are reviewing the recoverability of all OPCo generation assets.

Plans for and the timing of conversion of some of our coal units to natural gas, installing emission control equipment on other units and closure of existing units will be impacted by changes in emission requirements and demand for power.  As part of environmental compliance, we are evaluating options related to maturity of the lease for Rockport Plant Unit 2 in 2022.

To the extent 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.

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.  In 2008, the D.C. Circuit Court of Appeals issued a decision remanding CAIR to the Federal EPA.  The Federal EPA issued the Cross-State Air Pollution Rule (CSAPR) (discussed in detail below) in August 2011 to replace CAIR.  The CSAPR has been challenged in the courts, and the United States Court of Appeals for the D.C. Circuit issued an order in December 2011 staying the effective date of the rule pending judicial review.  CAIR remains in effect while the litigation continues.  Nearly all of the states in which our power plants are located are covered by CAIR.

The Federal EPA issued the final maximum achievable control technology (MACT) standards for coal and oil-fired power plants (discussed in detail below) in February 2012.

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

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through individual state implementation plans (SIPs) or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs).  The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas and Oklahoma.  The Federal EPA finalized a FIP for Oklahoma that contains more stringent control requirements for SO2 emissions from affected units in that state and we have challenged the FIP in the Tenth Circuit Court of Appeals.  No action has been finalized in Arkansas.  If the Federal EPA is upheld and similar action is taken in Arkansas, it could increase the costs of compliance, accelerate the installation of required controls and/or force the premature retirement of existing units.

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 gasemissions 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 is reconsidering whether to include CO2 emissions in a number of stationary source standards, including standards that apply to new and modified electric utility units and announced a settlement agreement to issue proposed new source performance standards for utility boilers.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for SO2, NOx and lead, and is currently reviewing the NAAQS for ozone and PM.  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.

Cross-State Air Pollution Rule (formerly the Clean Air Act Transport Rule)

In July 2010, the Federal EPA issued a proposed rule to replace CAIR that would impose new and more stringent requirements to control SO2 and NOx emissions from fossil fuel-fired electric generating units in 31 states and the District of Columbia.

In August 2011, the Federal EPA issued the final rule, CSAPR.  The 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 beginning in 2012.  Arkansas and Louisiana are subject only to the seasonal NOx program in the final 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 have been reduced significantly in the final 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.

In October 2011, the Federal EPA released a proposed rule revising portions of the final CSAPR.  The proposed rule would correct errors in unit-specific assumptions and make available additional allowances in 10 states, including Louisiana and Texas, and provide additional allowances for the new unit set aside in Arkansas.  In addition, the proposed rule would make the allowance trading assurance provisions which restrict interstate trading of allowances effective January 1, 2014 instead of January 1, 2012.

Numerous affected entities, states and other parties filed petitions to review the CSAPR in the United States Court of Appeals for the District of Columbia Circuit.  Several of the petitioners filed motions to stay the implementation of the rule pending judicial review.  In December 2011, the court granted the motions for stay and ordered the parties to submit schedules for expedited briefing in order to allow the case to be heard in April 2012.  A final supplemental rule addressing seasonal NOx emissions in five states was finalized in December 2011 and has been the subject of separate appeals by certain Oklahoma entities, including PSO.  The Federal EPA has announced that the provisions of the supplemental rule will not be enforced while the stay of the final CSAPR remains in effect.

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The time frames and stringency of the required emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and our electric utility customers.

Mercury and Other Hazardous Air Pollutants Regulation

In February 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 metal) 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 is April 16, 2012 and compliance is required within three years.

The final rule contains a slightly less stringent PM limit than the original proposal and allows operators to exclude periods of startup and shutdown from the emissions averaging periods.  The compliance time frame remains a serious concern.  A one-year administrative extension may be available if the extension is necessary for 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 are concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines.

Regional Haze

In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze SIP submitted by the State of Oklahoma through the Department of Environmental Quality.  The Federal EPA is proposing to approve all of the NOx control measures in the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO.  The Federal EPA is proposing a FIP that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP.  PSO submitted comments on the proposed action demonstrating that the cost-effectiveness calculations performed by the Federal EPA were unsound, challenging the period for compliance with the final rule and showing that the visibility improvements secured by the proposed SIP were significant and cost-effective.  The Federal EPA finalized the FIP in December 2011.  PSO will appeal the FIP and pursue its claims in the Tenth Circuit Court of Appeals.

Coal Combustion Residual Rule

In June 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units.  The rule contains 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 would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule.  In October 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment.

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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.  Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes.  In addition, we currently use surface impoundments and landfills to manage these materials at our generating facilities and will incur significant costs to upgrade or close and replace these existing facilities under the proposed solid waste management alternative.  Regulation of these materials as hazardous wastes would significantly increase these costs.  As the rule is not final, we are unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

Clean Water Act Regulations

In April 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will 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 proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling.  Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority.  We are evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at our facilities.  We submitted comments on the proposal in July and August 2011.

Global Warming

National public policy makers and regulators in the 11 states we serve have conflicting views on global warming.  We are focused on taking, in the short term, actions that we see as prudent, such as improving energy efficiency, investing in developing cost-effective and less carbon-intensive technologies and evaluating our assets across a range of plausible scenarios and outcomes.  We are also active participants in a variety of public policy discussions at state and federal levels to assure that proposed new requirements are feasible and the economies of the states we serve are not placed at a competitive disadvantage.

While comprehensive economy-wide regulation of CO2 emissions might be achieved through future legislation, Congress has yet to enact such legislation.  The Federal EPA continues to take action to regulate CO2 emissions under the existing CAA, permitting programs for new sources, and is expected to propose new source emissions standards for fossil fuel-fired plants in 2012.

Several states have adopted programs that directly regulate CO2 emissions from power plants, but none of these programs are currently in effect in states where we have generating facilities.  Certain of our states have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements (including Michigan, Ohio, Texas and Virginia).  We are taking steps to comply with these requirements.  In order to meet these requirements and as a key part of our corporate sustainability effort, we pledged to increase our wind power from 2007 levels.  By the end of 2011, we secured, through power purchase agreements, 1,893 MW of wind and solar power.

We have taken measurable, voluntary actions to reduce and offset our CO2 emissions.  We participated in a number of voluntary programs to monitor, mitigate and reduce CO2 emissions, but many of these programs have been discontinued due to anticipated legislative or regulatory actions.  Through the end of 2010, we reduced our emissions by a cumulative 96 million metric tons from adjusted baseline levels in 1998 through 2001 under Chicago Climate Exchange (CCX) rules.  Our total CO2 emissions in 2010, as reported to CCX, were 138 million metric tons.  We estimate that our 2011 emissions were approximately 139 million metric tons.

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Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others.  We have been named in pending lawsuits, which we are defending.  It is not possible to predict the outcome of these lawsuits or their impact on our operations or financial condition.  See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 5.

Future federal and state legislation or regulations that mandate limits on the emission of CO2 would 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.  As a result, mandatory limits could have a material adverse impact on our net income, cash flows and financial condition.

Global warming creates the potential for physical and financial risk.  The materiality of the risks depends on whether any physical changes occur quickly or over many decades and the extent and nature of those changes.  The main physical risk from climate change that could affect AEP is changes in weather conditions.  Our customers’ energy needs currently vary with weather conditions, primarily temperature and humidity.  For residential customers, heating and cooling today represent their largest energy use.  To the extent weather patterns change significantly, customers’ energy use could increase or decrease depending on the duration and magnitude of any changes.  Increased energy use due to weather changes could require us to invest in more generating assets, transmission and other infrastructure in the long term to serve increased load, driving the overall cost of electricity higher.  Decreased energy use due to weather changes (i.e. milder winters) could affect our financial condition through lower sales and decreased revenues.  Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions and increased storm restoration costs.  We may not recover all costs related to mitigating these physical and financial risks.  Weather conditions outside of our service territory could also have an impact on our revenues, either directly through changes in the patterns of our off-system power purchases and sales or indirectly through demographic changes as people adapt to changing weather.  We buy and sell electricity depending upon system needs and market opportunities.  Extreme weather conditions that create high energy demand could raise electricity prices, which could increase the cost of energy we provide to our customers and could provide opportunity for increased wholesale sales and higher margins.

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.

For additional information on global warming, see Part I of the Annual Report under the headings entitled “Business – General – Environmental and Other Matters – Global Warming.”

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RESULTS OF OPERATIONS

SEGMENTS

Our primary business is the generation, transmission and distribution of electricity.  Within our Utility Operations 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.

While our Utility Operations segment remains our primary business segment, the advancement of an area of our business prompted us to identify a new reportable segment.  Starting in the fourth quarter of 2011, we established our new Transmission Operations segment as described below:

Utility Operations

· Generation of electricity for sale to U.S. retail and wholesale customers.

· Transmission and distributionof electricity through assets owned and operated by our ten utility operating companies.

Transmission Operations

· Development, construction and operation of transmission facilities through investments in our wholly-owned transmission subsidiaries that were established in 2009 and our transmission joint ventures.  These investments have FERC-approved returns on equity.

AEP River Operations

· Commercial barging operations that transport coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.

Generation and Marketing

· Nonregulated generation in ERCOT.

· Marketing and risk management activities primarily in ERCOT and, to a lesser extent, Ohio in PJM and MISO.

The table below presents our consolidated Income Before Extraordinary Items by segment for the years ended December 31, 2011, 2010 and 2009.  We reclassified prior year amounts to conform to the current year’s presentation.

	Years Ended December 31,
	2011			2010			2009
	(in millions)
Utility Operations	$	1,549		$	1,192		$	1,325
Transmission Operations		30			9			4
AEP River Operations		45			37			47
Generation and Marketing		14			25			41
All Other (a)		(62	)		(45	)		(47	)
Income Before Extraordinary Items	$	1,576		$	1,218		$	1,370

(a)	While not considered a reportable segment, All Other includes:
	·	Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
	·	Tax and interest expense adjustments related to our UK operations which were sold in 2004 and 2002.
	·	Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.  These contracts were financial derivatives which settled and expired in the fourth quarter of 2011.
	·	Revenue sharing related to the Plaquemine Cogeneration Facility which ended in the fourth quarter of 2011.

12

AEP CONSOLIDATED

2011 Compared to 2010

Income Before Extraordinary Items in 2011 increased $358 million compared to 2010 primarily due to:

· An increase in carrying costs income due to the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005 and a related favorable fourth quarter 2011 resolution of contested tax items related to the TCC stranded cost settlement.

· A decrease in expenses as a result of the 2010 cost reduction initiatives.

· Successful rate proceedings in our various jurisdictions.

These increases were partially offset by:

· The loss of retail customers in Ohio to competitive retail electric service providers.

· Various Ohio adjustments in 2011, including:

· The impairments of Sporn Unit 5 and the FGD project at Muskingum River Unit 5.

· A net decrease due to unfavorable Ohio regulatory orders in 2011.

· The recording of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund.

· The elimination of POLR charges, effective June 2011, in Ohio due to an October 2011 PUCO remand order.

· A fourth quarter 2011 write-off related to SWEPCo’s Texas jurisdictional portion of the Turk Plant as a result of the November 2011 Texas Court of Appeals decision upholding the Texas capital cost cap.

Average basic shares outstanding increased to 482 million in 2011 from 479 million in 2010.  Actual shares outstanding were 483 million as of December 31, 2011.

2010 Compared to 2009

Income Before Extraordinary Items in 2010 decreased $152 million compared to 2009 primarily due to charges incurred related to the 2010 cost reduction initiatives.

Average basic shares outstanding increased to 479 million in 2010 from 459 million in 2009.  Actual shares outstanding were 481 million as of December 31, 2010.

Our results of operations are discussed below by operating segment.

13

UTILITY OPERATIONS

We believe that a discussion of the results from our Utility Operations segment on a gross margin basis is most appropriate in order to further understand the key drivers of the segment.  Gross margin represents total revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances and purchased power.

	Years Ended December 31,
	2011			2010			2009
	(in millions)
Revenues	$	14,200		$	13,792		$	12,803
Fuel and Purchased Power		5,455			4,996			4,420
Gross Margin		8,745			8,796			8,383
Other Operation and Maintenance		3,539			3,760			3,410
Asset Impairments and Other Related Charges		139			-			-
Depreciation and Amortization		1,613			1,598			1,561
Taxes Other Than Income Taxes		812			811			751
Operating Income		2,642			2,627			2,661
Interest and Investment Income		29			9			4
Carrying Costs Income		393			70			47
Allowance for Equity Funds Used During Construction		91			77			82
Interest Expense		(886	)		(942	)		(916
Income Before Income Tax Expense and Equity Earnings		2,269			1,841			1,878
Equity Earnings of Unconsolidated Subsidiaries		2			2			-
Income Tax Expense		722			651			553
Income Before Extraordinary Items	$	1,549		$	1,192		$	1,325

Summary of KWH Energy Sales for Utility Operations
	Years Ended December 31,
	2011	2010		2009
	(in millions of KWHs)
Retail:
Residential	61,655		61,944	58,232
Commercial	50,767		50,748	49,925
Industrial	59,667		57,333	54,428
Miscellaneous	3,100		3,083	3,048
Total Retail (a)	175,189		173,108	165,633
Wholesale	40,519		32,581	29,670
Total KWHs	215,708		205,689	195,303
(a) Includes energy delivered to customers served by AEP's Texas Wires Companies.

14

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 Utility Operations
		Years Ended December 31,
		2011		2010		2009
		(in degree days)
Eastern Region
Actual - Heating (a)			2,794		3,222		3,018
Normal - Heating (b)			2,980		2,983		3,040
Actual - Cooling (c)			1,215		1,307		816
Normal - Cooling (b)			1,017		1,002		1,011
Western Region
Actual - Heating (a)			1,029		1,112		970
Normal - Heating (b)			984		980		984
Actual - Cooling (d)			3,020		2,515		2,439
Normal - Cooling (b)			2,349		2,339		2,344
(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 cooling degree days are calculated on a 65 degree temperature base.
(d)	Western Region cooling degree days are calculated on a 65 degree temperature base for PSO/SWEPCo and a 70 degree temperature base for TCC/TNC.

15

2011 Compared to 2010

Reconciliation of Year Ended December 31, 2010 to Year Ended December 31, 2011
Income from Utility Operations Before Extraordinary Items
(in millions)
	Year Ended December 31, 2010	$	1,192
	Changes in Gross Margin:
	Retail Margins		(139)
	Off-system Sales		44
	Transmission Revenues		48
	Other Revenues		(4)
	Total Change in Gross Margin		(51)
	Changes in Expenses and Other:
	Other Operation and Maintenance		221
	Asset Impairments and Other Related Charges		(139)
	Depreciation and Amortization		(15)
	Taxes Other Than Income Taxes		(1)
	Interest and Investment Income		20
	Carrying Costs Income		323
	Allowance for Equity Funds Used During Construction		14
	Interest Expense		56
	Total Change in Expenses and Other		479
	Income Tax Expense		(71)
	Year Ended December 31, 2011	$	1,549

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, and purchased power were as follows:

·	Retail Margins decreased $139 million primarily due to the following:
	·	A $132 million decrease attributable to Ohio customers switching to alternative competitive retail electric service (CRES) providers.
	·	An $87 million decrease in weather-related usage in our eastern region primarily due to a 13% decrease in heating degree days and a 7% decrease in cooling degree days.
	·	An $84 million decrease in rate related margins for APCo due to the expiration of E&R cost recovery in Virginia.
	·	A $60 million decrease due to the elimination of POLR charges, effective June 2011, in Ohio as a result of the October 2011 PUCO remand order.
	·	A $51 million net decrease due to unfavorable Ohio and Virginia regulatory orders.
	·	A $30 million increase in other variable electric generation expenses.
	These decreases were partially offset by:
	·	Successful rate proceedings in our service territories which include:
		·	A $120 million rate increase for OPCo.
		·	A $63 million rate increase for APCo.
		·	A $30 million rate increase for SWEPCo.
		·	A $27 million rate increase for KPCo.
		·	A $27 million rate increase for I&M.
		·	For the rate increases described above, $78 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
	·	A $38 million increase in weather-related usage in our western region primarily due to a 20% increase in cooling degree days, slightly offset by a 7% decrease in heating degree days.

16

· A $30 million increase due to increased SWEPCo gross margin from sales to customers previously served by Valley Electric Membership Corporation (VEMCO).  SWEPCo acquired VEMCO assets and began serving VEMCO customers in October 2010.

· A $14 million increase related to TCC’s Transition Funding.  This increase is offset by an increase in Depreciation and Amortization expenses.

· Margins from Off-system Sales increased $44 million primarily due to an increase in PJM capacity revenues and higher physical sales volumes, partially offset by lower trading and marketing margins.

· Transmission Revenues increased $48 million primarily due to net rate increases in PJM and increased transmission revenues for Ohio customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers partially offsets lost revenues included in Retail Margins above.

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

·	Other Operation and Maintenance expenses decreased $221 million primarily due to the following:
	·	A $280 million decrease due to expenses related to the cost reduction initiatives recorded in 2010.
	·	A $54 million decrease due to the second quarter 2010 write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC.
	·	A $42 million decrease in administrative and general expenses primarily due to a decrease in fringe benefit expenses.
	·	A $33 million decrease due to the first quarter 2011 deferral of 2010 costs related to storms and our cost reduction initiatives as allowed by the WVPSC.
	·	A $27 million decrease due to the favorable fourth quarter 2011 Asset Retirement Obligation adjustment for APCo related to the early closure and previous write-off of the Mountaineer Carbon Capture and Storage Product Validation Facility.
	·	An $11 million gain from the sale of land in January 2011.
	These decreases were partially offset by:
	·	A $54 million increase in demand side management, energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
	·	A $41 million increase due to the first quarter 2011 write-off of a portion of the West Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC.
	·	A $35 million increase related to the fourth quarter 2011 recording of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the approved December 2011 Ohio stipulation agreement.
	·	A $33 million increase in storm-related expenses.
	·	A $33 million increase in plant outage and other plant operating and maintenance expenses.
	·	A $25 million increase due to the second quarter 2010 deferral of 2009 storm costs as allowed by the Virginia SCC.
·	Asset Impairments and Other Related Charges in 2011 included the following:
	·	A third quarter 2011 plant impairment of $48 million for Sporn Unit 5.
	·	A third quarter 2011 plant impairment of $42 million for the FGD project at Muskingum River Unit 5.
	·	A fourth quarter 2011 write-off of $49 million related to SWEPCo’s Texas jurisdictional portion of the Turk Plant as a result of the November 2011 Texas Court of Appeals decision upholding the Texas capital cost cap.
·	Depreciation and Amortization expenses increased $15 million primarily due to the following:
	·	A $23 million increase due to the amortization of carrying costs on deferred fuel as a result of the October 2011 Ohio POLR remand order.
	·	A $20 million increase in depreciation and amortization for TCC primarily due to increased amortization of TCC’s Securitized Transition Assets.  This increase is partially offset by an increase in revenues within Gross Margin.
	·	Overall higher depreciable property balances.

17

	These increases were partially offset by:
	·	A $34 million decrease in depreciation and amortization for APCo primarily due to the expiration of E&R amortization of deferred carrying costs in Virginia.
·	Interest and Investment Income increased $20 million primarily due to interest income recorded in the third quarter of 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
·	Carrying Costs Income increased $323 million due to the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005 and a related favorable fourth quarter 2011 resolution of contested tax items related to the TCC stranded cost settlement.
·	Allowance for Equity Funds Used During Construction increased $14 million primarily due to construction of the Turk and Dresden Plants and various environmental upgrades, partially offset by a decrease due to the completion of the Stall Unit in June 2010.
·	Interest Expense decreased $56 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·	Income Tax Expense increased $71 million primarily due to an increase in pretax book income, partially offset by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits and by the recording of federal and state income tax adjustments resulting from the filing of the prior year tax returns.

18

2010 Compared to 2009

Reconciliation of Year Ended December 31, 2009 to Year Ended December 31, 2010
Income from Utility Operations Before Discontinued Operations and Extraordinary Items
(in millions)
	Year Ended December 31, 2009	$	1,325
	Changes in Gross Margin:
	Retail Margins		602
	Off-system Sales		53
	Transmission Revenues		15
	Other Revenues		(257)
	Total Change in Gross Margin		413
	Changes in Expenses and Other:
	Other Operation and Maintenance		(350)
	Depreciation and Amortization		(37)
	Taxes Other Than Income Taxes		(60)
	Interest and Investment Income		5
	Carrying Costs Income		23
	Allowance for Equity Funds Used During Construction		(5)
	Interest Expense		(26)
	Equity Earnings of Unconsolidated Subsidiaries		2
	Total Change in Expenses and Other		(448)
	Income Tax Expense		(98)
	Year Ended December 31, 2010	$	1,192

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 power were as follows:

·	Retail Margins increased $602 million primarily due to the following:
	·	Successful rate proceedings in our service territories which include:
		·	A $138 million increase in the recovery of E&R costs in Virginia, costs related to the Transmission Rate Adjustment Clause in Virginia and construction financing costs in West Virginia.
		·	A $49 million increase in the recovery of advanced metering costs in Texas.
		·	A $43 million net rate increase for KPCo.
		·	A $42 million net rate increase for SWEPCo.
		·	A $39 million net rate increase for I&M.
		·	A $37 million net rate increase for PSO.
		·	A $14 million net rate increase in our other jurisdictions.
		·	For the increases described above, $183 million of these increases relate to riders/trackers which have corresponding increases in other expense items.
	·	A $229 million increase in weather-related usage primarily due to a 60% increase in cooling degree days in our eastern service territory and 7% and 15% increases in heating degree days in our eastern and western service territories, respectively.
	·	A $78 million increase due to higher fuel and purchased power costs recorded in 2009 related to the Cook Plant Unit 1 (Unit 1) shutdown.  This increase was offset by a corresponding decrease in Other Revenues as discussed below.
	These increases were partially offset by:
	·	A $43 million decrease due to an unfavorable order related to the 2009 Significantly Excessive Earnings Test (SEET).
	·	A $38 million decrease due to the termination of an I&M unit power agreement.

19

· Margins from Off-system Sales increased $53 million primarily due to increased prices and higher physical sales volumes in our eastern service territory, partially offset by lower trading and marketing margins.

· Transmission Revenues increased $15 million primarily due to increased revenues in the ERCOT, PJM and SPP regions.

· Other Revenues decreased $257 million primarily due to the Cook Plant accidental outage insurance proceeds of $185 million which ended when Unit 1 returned to service in December 2009.  I&M reduced customer bills by approximately $78 million in 2009 for the cost of replacement power resulting from the Unit 1 outage.  This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above.  Other Revenues also decreased due to lower gains on sales of emission allowances of $29 million, partially offset by sharing with customers in certain fuel clauses.  This decrease in gains on sales of emission allowances was the result of lower market prices.

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

·	Other Operation and Maintenance expenses increased $350 million primarily due to the following:
	·	A $280 million increase due to expenses related to the cost reduction initiatives in 2010.
	·	A $114 million increase in demand side management, energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
	·	A $54 million increase due to the write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC.
	These increases were partially offset by:
	·	An $89 million decrease in storm expenses.
·	Depreciation and Amortization increased $37 million primarily due to new environmental improvements placed in service at APCo and OPCo and placing the Stall Unit in service at SWEPCo partially offset by lower depreciation in Arkansas and Texas as a result of SWEPCo’s recent base rate orders.
·	Taxes Other Than Income Taxes increased $60 million primarily due to the employer portion of payroll taxes incurred related to the cost reduction initiatives and higher franchise and property taxes.
·	Carrying Costs Income increased $23 million primarily due to environmental construction in Virginia and a higher under-recovered fuel balance for OPCo.
·	Interest Expense increased $26 million primarily due to an increase in long-term debt and a decrease in the debt component of AFUDC due to completed environmental improvements at APCo and OPCo.
·	Income Tax Expense increased $97 million primarily due to the regulatory accounting treatment of state income taxes, other book/tax differences which are accounted for on a flow-through basis and the tax treatment associated with the future reimbursement of Medicare Part D prescription drug benefits, partially offset by a decrease in pretax book income.

20

TRANSMISSION OPERATIONS

Wholly-owned Entities

AEP Transmission Company, LLC (AEP Transco), a subsidiary of AEP, has seven wholly-owned transmission companies.  The transmission companies have been approved by the applicable commissions in Indiana, Michigan, Ohio and Oklahoma.  Applications for approval of the transmission companies have been filed with the APSC, the KPSC, the LPSC, the Virginia SCC and the WVPSC and are pending approval.  These seven companies consist of:

AEP East Transmission Companies

·   AEP Appalachian Transmission Company, Inc. (APTCo) (covering Virginia)

·   AEP Indiana Michigan Transmission Company, Inc. (IMTCo)

·   AEP Kentucky Transmission Company, Inc. (KTCo)

·   AEP Ohio Transmission Company, Inc. (OHTCo)

·   AEP West Virginia Transmission Company, Inc. (WVTCo)

AEP West Transmission Companies

·   AEP Oklahoma Transmission Company, Inc. (OKTCo)

·   AEP Southwestern Transmission Company, Inc. (SWTCo) (covering Arkansas and Louisiana)

The AEP East Transmission Companies and the AEP West Transmission Companies have FERC-approved returns on common equity of 11.49% and 11.20%, respectively.  AEPSC and other AEP subsidiaries provide services to the transmission companies through service agreements.  Therefore, the transmission companies do not have any employees.

All of the transmission companies’ capital needs are provided by Parent, AEP Transco and/or the AEP Utility Money Pool.  The Utility Money Pool is used to meet the short-term borrowing needs of AEP regulated utility subsidiaries.  The Utility Money Pool operates in accordance with the terms and conditions approved in regulatory orders.

21

Joint Venture Initiatives
We are currently participating in the following joint venture initiatives:
				Total
				Estimated			AEP's
		Projected		Project Costs			Investment at			Approved
Project		Completion	Owners	at			December 31,			Return on
Name	Location	Date	(Ownership %)	Completion			2011			Equity
					(in thousands)
ETT	Texas	2017	MEHC Texas	$	3,100,000	(a)	$	223,527		9.96	%
	(ERCOT)		Transco, LLC (50%)
			AEP (50%)
PATH (b)	West	2015 (c)	FirstEnergy (50%)		2,100,000	(d)		28,929		12.4	%
	Virginia		AEP (50%)
Prairie Wind	Kansas	2014	Westar Energy (50%)		225,000			1,986		12.8	%
			ETA (50%) (e)
Pioneer	Indiana	2018	Duke Energy (50%)		1,000,000			-		12.54	%
			AEP (50%)
RITELine IN	Indiana	2019	RTD (25%) (f)		400,000			171	(g)	11.43	%
			ETA (37.5%) (e) (f)
			AEPTHC (37.5%)
RITELine IL	Illinois	2019	Commonwealth		1,200,000			14		11.43	%
			Edison (75%)
			RTD (25%) (f)

(a)	ETT’s current and future estimated project cost in ERCOT over the next several years is expected to be $3.1 billion.  Future projects will be evaluated on a case-by-case basis.
(b)	In September 2007, AEP Transmission Holding Company, LLC (AEPTHC) and AET PATH Company, LLC, a subsidiary of FirstEnergy, Inc. (FirstEnergy), formed a joint venture by creating Potomac-Appalachian Transmission Highline, LLC (PATH) and its subsidiaries.  The PATH subsidiaries will operate as transmission utilities owning certain electric transmission assets within PJM.
(c)	PJM directed AEP and FirstEnergy to suspend current development efforts on the PATH Project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the potential need for the PATH Project as part of its continuing Regional Transmission Expansion Plan (RTEP) process.  PJM’s announcement specifically indicated that PJM was not directing AEP and FirstEnergy to cancel or abandon the PATH Project.
(d)	PATH consists of the “West Virginia Series,” which is owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is wholly-owned by a subsidiary of FirstEnergy.  The total project is estimated to cost approximately $2.1 billion.  AEP’s estimated share of the project cost is approximately $700 million.
(e)	ETA is a 50/50 joint venture with MidAmerican Energy Holdings Company (MEHC) America Transco, LLC and AEP.  ETA will be utilized as a vehicle to invest in selected transmission projects located in North America, outside of ERCOT.  AEP owns 25% of Prairie Wind Transmission, LLC (Prairie Wind) through its ownership interest in ETA.
(f)	RITELine Transmission Development, LLC (RTD) is a 50/50 joint venture with Exelon Transmission Company, LLC and ETA.  AEP owns 62.5% of RITELine Indiana, LLC (RITELine IN) through its ownership interest in ETA and AEPTHC.  AEP owns 6.25% of RITELine Illinois, LLC (RITELine IL) through its ownership interest in ETA.
(g)	RITELine IN is a consolidated variable interest entity.

For the consolidated entities within our Transmission Operations segment, we forecast approximately $350 million, excluding AFUDC, of construction expenditures for 2012.  For the equity investments within our Transmission Operations segment, we forecast approximately $116 million of AEP equity contributions in 2012 to support construction expenditures and the payment of operating expenses.

22

2011 Compared to 2010

Income Before Extraordinary Items from our Transmission Operations segment increased from $9 million in 2010 to $30 million in 2011 primarily due to an increase in transmission investments by ETT and OHTCo.

2010 Compared to 2009

Income Before Extraordinary Items from our Transmission Operations segment increased from $4 million in 2009 to $9 million in 2010 primarily due to an increase in transmission investments by ETT.

AEP RIVER OPERATIONS

2011 Compared to 2010

Income Before Extraordinary Items from our AEP River Operations segment increased from $37 million in 2010 to $45 million in 2011 primarily due to increased coal exports, increased barge fleet size and the cost reduction initiatives in 2010, partially offset by higher fuel, maintenance and flood-related expenses.

2010 Compared to 2009

Income Before Extraordinary Items from our AEP River Operations segment decreased from $47 million in 2009 to $37 million in 2010 primarily due to expenses related to cost reduction initiatives, increased interest expense on new equipment financing, a property casualty loss in 2010 and a gain on the sale of two older towboats in 2009.

GENERATION AND MARKETING

2011 Compared to 2010

Income Before Extraordinary Items from our Generation and Marketing segment decreased from $25 million in 2010 to $14 million in 2011 primarily due to lower gross margins at the Oklaunion Plant.

2010 Compared to 2009

Income Before Extraordinary Items from our Generation and Marketing segment decreased from $41 million in 2009 to $25 million in 2010 primarily due to reduced inception gains from ERCOT marketing activities, reduced plant performance due to lower power prices in ERCOT, partially offset by positive hedging activities on our generation assets and increased income from our wind farm operations.

ALL OTHER

2011 Compared to 2010

Income Before Extraordinary Items from All Other decreased from a loss of $45 million in 2010 to a loss of $62 million in 2011 primarily due to a loss incurred in 2011 related to the settlement of litigation with BOA and Enron and a gain on the sale of our remaining shares of Intercontinental Exchange, Inc. (ICE) in 2010 partially offset by a contribution to AEP’s charitable foundation in 2010.

2010 Compared to 2009

Income Before Extraordinary Items from All Other increased from a loss of $47 million in 2009 to a loss of $45 million in 2010 primarily due to a gain on the sale of our remaining shares of ICE in 2010 and a decrease in various parent related expenses partially offset by a 2010 contribution to AEP’s charitable foundation and losses on the sales of assets.

23

AEP SYSTEM INCOME TAXES

2011 Compared to 2010

Income Tax Expense increased $175 million primarily due to an increase in pretax book income and the unrealized capital loss valuation allowance related to a deferred tax asset associated with the settlement of litigation with BOA and Enron, offset in part by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits and by the recording of federal and state income tax adjustments resulting from the filing of prior year tax returns.

2010 Compared to 2009

Income Tax Expense increased $68 million primarily due to the regulatory accounting treatment of state income taxes, other book/tax differences which are accounted for on a flow-through basis and the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits, offset in part by a decrease in pretax book income.

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,
	2011				2010
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	16,516	50.3	%	$	16,811	52.8	%
Short-term Debt		1,650	5.0			1,346	4.2
Total Debt		18,166	55.3			18,157	57.0
Preferred Stock of Subsidiaries		-	-			60	0.2
AEP Common Equity		14,664	44.7			13,622	42.8
Noncontrolling Interests		1	-			-	-
Total Debt and Equity Capitalization	$	32,831	100.0	%	$	31,839	100.0	%

Our ratio of debt-to-total capital decreased from 57% in 2010 to 55.3% in 2011 primarily due to an increase in common equity.  This increase in common equity is primarily the result of the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005 and a related favorable fourth quarter 2011 resolution of contested tax items related to the TCC stranded cost settlement.

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.  At December 31, 2011, we had $3.25 billion in aggregate credit facility commitments to support our operations.  Additional liquidity is available from cash from operations and a sale of receivables 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.

24

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At December 31, 2011, our available liquidity was approximately $2.4 billion as illustrated in the table below:

		Amount		Maturity
		(in millions)
Commercial Paper Backup:
	Revolving Credit Facility	$	1,500	June 2015
	Revolving Credit Facility		1,750	July 2016
Total			3,250
Cash and Cash Equivalents			221
Total Liquidity Sources			3,471
Less:	AEP Commercial Paper Outstanding		967
	Letters of Credit Issued		134
Net Available Liquidity		$	2,370

We have credit facilities totaling $3.25 billion to support our commercial paper program.  The credit facilities allow us to issue letters of credit in an amount up to $1.35 billion.  In July 2011, we replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015.

In March 2011, we terminated a $478 million credit facility, used for letters of credit to support variable rate debt.  In March 2011, we also issued bilateral letters of credit to support the remarketing of $357 million of variable rate debt and reacquired $115 million which a trustee holds on our behalf.

We use our commercial paper program to meet the short-term borrowing needs of the 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 2011 was $1.2 billion.  The weighted-average interest rate for our commercial paper during 2011 was 0.4%.

Financing Plan

In March 2012, TCC plans to issue $800 million of securitization bonds as approved by the PUCT for recovery of capacity auction true-up amounts over 13 years.  We are also evaluating potential securitization of certain deferred regulatory assets in Ohio and West Virginia.  Recent legislation in Ohio allows the securitization of deferred FAC costs and certain other regulatory assets.  Legislation has been introduced in West Virginia to allow the WVPSC to consider securitization of deferred ENEC costs.

At December 31, 2011, we have $1.4 billion of long-term debt due within one year which includes $572 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 $273 million of securitization bonds and DCC Fuel notes payable which will be repaid.  We plan to refinance a portion of our maturities.  Proceeds from new issuances and the TCC securitization may limit the amount of the remaining long-term debt due within one year that needs to be refinanced.

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Securitized Accounts Receivables

In 2011, we renewed our receivables securitization agreement.  The agreement provides a commitment of $750 million from bank conduits to purchase receivables with an increase to $800 million for the months of July, August and September to accommodate seasonal demand.  A commitment of $375 million with the seasonal increase to $425 million expires in June 2012 and the remaining commitment of $375 million expires in June 2014.  We intend to extend or replace the agreement expiring in June 2012 on or before its maturity.

Debt Covenants and Borrowing Limitations

Our revolving 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 revolving credit agreements.  Debt as defined in the revolving credit agreements excludes junior subordinated debentures, securitization bonds and debt of AEP Credit.  At December 31, 2011, this contractually-defined percentage was 51.1%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  At December 31, 2011, 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 and in a majority of our non-exchange traded commodity contracts which would permit the lenders and counterparties to declare the outstanding amounts payable.  However, a default under our non-exchange traded commodity contracts does not cause an event of default under our revolving 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.  At December 31, 2011, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.47 per share in January 2012.  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.

We have the option to defer interest payments on the AEP Junior Subordinated Debentures for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.

We do not believe restrictions related to our various financing arrangements and regulatory requirements 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.

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CASH FLOW

Managing our cash flows is a major factor in maintaining our liquidity strength.

	Years Ended December 31,
	2011			2010			2009
	(in millions)
Cash and Cash Equivalents at Beginning of Period	$	294		$	490		$	411
Net Cash Flows from Operating Activities		3,788			2,662			2,475
Net Cash Flows Used for Investing Activities		(2,890	)		(2,523	)		(2,916	)
Net Cash Flows from (Used for) Financing Activities		(971	)		(335	)		520
Net Increase (Decrease) in Cash and Cash Equivalents		(73	)		(196	)		79
Cash and Cash Equivalents at End of Period	$	221		$	294		$	490

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,
	2011			2010				2009
	(in millions)
Net Income		$	1,949		$	1,218			$	1,365
Depreciation and Amortization			1,655			1,641				1,597
Other			184			(197	)			(487	)
Net Cash Flows from Operating Activities		$	3,788		$	2,662			$	2,475

Net Cash Flows from Operating Activities were $3.8 billion in 2011 consisting primarily of Net Income of $1.9 billion and $1.7 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.  Following a Supreme Court of Texas reversal of the PUCT’s capacity auction true-up disallowance and the PUCT’s approval of a stipulation agreement, we recorded Extraordinary Items, Net of Tax of $373 million for the 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts and the reversal of tax related regulatory credits.  We also recorded $393 million in Carrying Costs Income primarily related to the Texas restructuring appeals.  A significant change in other items includes the favorable impact of a decrease in fuel inventory.  Deferred Income Taxes increased primarily due to bonus depreciation provisions in the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Jobs Creation Act, the settlement with BOA and Enron and an increase in tax versus book temporary differences from operations.  In February 2011, we paid $425 million to BOA of which $211 million was used to settle litigation with BOA and Enron. The remaining $214 million was used to acquire cushion gas as discussed in Investing Activities below.  During 2011, we also contributed $450 million to our qualified pension trust.

Net Cash Flows from Operating Activities were $2.7 billion in 2010 consisting primarily of Net Income of $1.2 billion and $1.6 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.  Other includes a $656 million increase in securitized receivables under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement.  Significant changes in other items include an increase in under-recovered fuel primarily due to the deferral of fuel under the FAC in Ohio and higher fuel costs in Oklahoma, accrued tax benefits and the favorable impact of a decrease in fuel inventory.  Deferred Income Taxes increased primarily due to a change in tax versus book temporary differences from operations.  Accrued Taxes, Net increased primarily as a result of the receipt of a federal income tax refund of $419 million related to a net operating loss in 2009 that was carried back to 2007 and 2008.  We also contributed $500 million to our qualified pension trust in 2010.

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Net Cash Flows from Operating Activities were $2.5 billion in 2009 consisting primarily of Net Income of $1.4 billion and $1.6 billion of noncash Depreciation and Amortization.  Other represents 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.  Significant changes in other items include the negative impact on cash of an increase in coal inventory reflecting decreased customer demand for electricity, an increase in under-recovered fuel primarily in Ohio and West Virginia and an increase in accrued tax benefits resulting from a net income tax operating loss in 2009.  Deferred Income Taxes increased primarily due to the American Recovery and Reinvestment Act of 2009 extending bonus depreciation provisions, a one-time change in tax accounting method and an increase in tax versus book temporary differences from operations.

Investing Activities

	Years Ended December 31,
	2011			2010			2009
	(in millions)
Construction Expenditures	$	(2,669	)	$	(2,345	)	$	(2,792	)
Acquisitions of Nuclear Fuel		(106	)		(91	)		(169	)
Acquisitions of Assets		(19	)		(155	)		(104	)
Acquisitions of Cushion Gas from BOA		(214	)		-			-
Proceeds from Sales of Assets		123			187			278
Other		(5	)		(119	)		(129	)
Net Cash Flows Used for Investing Activities	$	(2,890	)	$	(2,523	)	$	(2,916	)

Net Cash Flows Used for Investing Activities were $2.9 billion in 2011 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments.  We paid $214 million to BOA for cushion gas as part of a litigation settlement.

Net Cash Flows Used for Investing Activities were $2.5 billion in 2010 primarily due to Construction Expenditures for environmental, new generation, distribution and transmission investments.  Proceeds from Sales of Assets in 2010 include $139 million for sales of Texas transmission assets to ETT.

Net Cash Flows Used for Investing Activities were $2.9 billion in 2009 primarily due to Construction Expenditures for our new generation, environmental, distribution and transmission investments.  Proceeds from Sales of Assets in 2009 includes $104 million relating to the sale of a portion of Turk Plant to joint owners as planned and $95 million for sales of Texas transmission assets to ETT.

Financing Activities

	Years Ended December 31,
	2011			2010			2009
	(in millions)
Issuance of Common Stock, Net	$	92		$	93		$	1,728
Issuance/Retirement of Debt, Net		(33	)		497			(360	)
Retirement of Cumulative Preferred Stock		(64	)		-			-
Dividends Paid on Common Stock		(898	)		(824	)		(758	)
Other		(68	)		(101	)		(90	)
Net Cash Flows from (Used for) Financing Activities	$	(971	)	$	(335	)	$	520

Net Cash Flows Used for Financing Activities in 2011 were $971 million.  Our net debt retirements were $33 million. The net retirements included retirements of $727 million of senior unsecured and other debt notes, $778 million of pollution control bonds and $159 million of securitization bonds offset by issuances of $710 million of notes, $627 million of pollution control bonds and an increase in short-term borrowing of $304 million.  We paid common stock dividends of $898 million and $64 million to retire all of our subsidiaries’ preferred stocks.  See Note 13  – Financing Activities.

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Net Cash Flows Used for Financing Activities were $335 million in 2010.  Our net debt issuances were $497 million.  The net issuances included issuances of $952 million of notes and $326 million of pollution control bonds, a $­­­531 million increase in commercial paper outstanding and retirements of $1.6 billion of notes, $148 million of securitization bonds and $222 million of pollution control bonds.  Our short-term debt securitized by receivables increased $656 million under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement.  We paid common stock dividends of $824 million.

Net Cash Flows from Financing Activities were $520 million in 2009.  Issuance of Common Stock, Net of $1.7 billion is comprised of our issuance of 69 million shares of common stock with net proceeds of $1.64 billion and additional shares through our dividend reinvestment, employee savings and incentive programs.  Our net debt retirements were $360 million. The net retirements included the repayment of $2 billion outstanding under our credit facilities and retirement of $816 million of long-term debt and issuances of $1.9 billion of senior unsecured and debt notes and $431 million of pollution control bonds.  We paid common stock dividends of $758 million.

The following financing activities occurred during 2011:

AEP Common Stock:

·   During 2011, we issued 2.6 million shares of common stock under our incentive compensation, employee savings and dividend reinvestment plans and received net proceeds of $92 million.

Preferred Stock of Subsidiaries:

·   During 2011, we paid $64 million to retire all outstanding shares of our subsidiaries’ preferred stock.

Debt:

·   During 2011, we issued approximately $1.3 billion of long-term debt, including $600 million of senior notes at interest rates ranging from 4.4% to 4.6%.  We also issued $627 million of pollution control revenue bonds, including $225 million at interest rates ranging from 1.125% to 2% and $402 million at variable interest rates.  The proceeds from these issuances were used to fund long-term debt maturities and our construction programs.

·   During 2011, we entered into $975 million of interest rate derivatives and settled $974 million of such transactions.  The settlements resulted in net cash receipts of $34 million.  As of December 31, 2011, we had in place $907 million of notional interest rate derivatives designated as cash flow and fair value hedges.

In 2012:

·   In January 2012, TCC retired $98 million of its outstanding Securitization Bonds.

·   In January and February 2012, I&M retired $14 million of Notes Payable related to DCC Fuel.

·   In February 2012, APCo retired $30 million of 6.05% Pollution Control Bonds due in 2024 and $ 19.5 million of 5% Pollution Control Bonds due in 2021.

·   In February 2012, SWEPCo issued $275 million of 3.55% Senior Unsecured Notes due in 2022 and $65 million of 4.58% Notes Payable due in 2032.

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BUDGETED CONSTRUCTION EXPENDITURES

We forecast approximately $3.1 billion of construction expenditures excluding equity AFUDC and capitalized interest for 2012.  For 2013 and 2014, we forecast construction expenditures ranging from $3.4 billion to $3.5 billion each year.  The projected increases are generally the result of required environmental investment to comply with Federal EPA rules and additional transmission spending.  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 estimated expenditures include amounts for completion of the Turk Plant.  APCo’s Dresden Plant was completed and placed in service in January 2012.  SWEPCo’s Turk Plant is expected to be in-service in the fourth quarter of 2012.  The 2012 estimated construction expenditures include generation, transmission and distribution related investments, as well as expenditures for compliance with environmental regulations as follows:

	Budgeted
	Construction
	Expenditures
	(in millions)
Environmental	$	511
Generation		781
Transmission		812
Distribution		847
Other		114
Total	$	3,065

OFF-BALANCE SHEET ARRANGEMENTS

In prior periods, under a limited set of circumstances, we entered into off-balance sheet arrangements for various reasons including reducing operational expenses and spreading risk of loss to third parties.  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 $813 million and $813 million, respectively, as of December 31, 2011.

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 12.  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.

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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 $34 million for the remaining railcars as of December 31, 2011.  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.  At December 31, 2011, the maximum potential loss was approximately $25 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 at December 31, 2011:

Payments Due by Period
		Less Than						After
Contractual Cash Obligations		1 year		2-3 years		4-5 years		5 years		Total
		(in millions)
Short-term Debt (a)		$	1,650	$	-	$	-	$	-	$	1,650
Interest on Fixed Rate Portion of Long-term
	Debt (b)		788		1,402		1,169		6,382		9,741
Fixed Rate Portion of Long-term Debt (c)			888		2,346		2,202		10,457		15,893
Variable Rate Portion of Long-term Debt (d)			545		111		6		-		662
Capital Lease Obligations (e)			96		148		102		285		631
Noncancelable Operating Leases (e)			316		552		471		1,235		2,574
Fuel Purchase Contracts (f)			2,867		3,918		2,574		3,108		12,467
Energy and Capacity Purchase Contracts (g)			104		213		217		1,066		1,600
Construction Contracts for Capital Assets (h)			682		918		821		1,663		4,084
Total		$	7,936	$	9,608	$	7,562	$	24,196	$	49,302

(a)	Represents principal only excluding interest.
(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2011 and do not reflect anticipated future refinancing, early redemptions or debt issuances.
(c)	See “Long-term Debt” section of Note 13.  Represents principal only excluding interest.
(d)	See “Long-term Debt” section of Note 13.  Represents principal only excluding interest.  Variable rate debt had interest rates that ranged between 0.06% and 0.955% at December 31, 2011.
(e)	See Note 12.
(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 contractual obligations for energy and capacity purchase contracts.
(h)	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 $68 million liability related to uncertainty in Income Taxes is not included above because we cannot reasonably estimate the cash flows by period.

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Our pension funding requirements are not included in the above table.  As of December 31, 2011, we expect to make contributions to our pension plans totaling $208 million in 2012.  Estimated contributions of $107 million in 2013 and $107 million in 2014 may vary significantly based on market returns, changes in actuarial assumptions and other factors.  Based upon the benefit obligation and fair value of assets available to pay pension benefits, our pension plans were 86.2% funded as of December 31, 2011.

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.  At December 31, 2011, our commitments outstanding under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period
	Less Than						After
Other Commercial Commitments	1 year		2-3 years		4-5 years		5 years		Total
	(in millions)
Standby Letters of Credit (a)	$	134	$	-	$	-	$	-	$	134
Guarantees of the Performance of Outside Parties (b)		-		-		-		100		100
Guarantees of Our Performance (c)		402		7		20		36		465
Total Commercial Commitments	$	536	$	7	$	20	$	136	$	699

(a)	We enter into standby letters of credit (LOCs) with third parties.  These LOCs cover items such as 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 $134 million with maturities ranging from January 2012 to October 2012.  Subsequent to December 31, 2011, standby LOCs have increased approximately $100 million as a result of declining market prices related to our risk management contracts.  This increase is partially offset by a reduction of posted cash collateral of approximately $20 million.  See “Letters of Credit” section of Note 5.
(b)	See “Guarantees of Third-Party Obligations” section of Note 5.
(c)	We issued performance guarantees and indemnifications for energy trading and various sale agreements.

SIGNIFICANT TAX LEGISLATION

TheAmerican Recovery and Reinvestment Tax Act of 2009 provided for several new grant programs, expanded tax credits and extended the 50% bonus depreciation provision enacted in the Economic Stimulus Act of 2008.  The Small Business Jobs Act, enacted in September 2010, included a one-year extension of the 50% bonus depreciation provision.  The Tax Relief, Unemployment Insurance Reauthorization and the Job Creation Act of 2010 extended the life of research and development, employment and several energy tax credits originally scheduled to expire at the end of 2010.  In addition, this act extended the time for claiming bonus depreciation and increased the deduction to 100% starting in September 2010 through 2011 and decreasing the deduction to 50% for 2012.

These enacted provisions did not have a material impact on net income or financial condition but had a favorable impact on cash flows in 2010 and 2011 and are expected to result in material future cash flow benefits in 2012.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW 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 our consolidated net income or financial condition.

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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 disclosure relating to them.

We believe that the current assumptions and other considerations used to estimate amounts reflected in our consolidated 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.

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 4 for further detail related to regulatory assets and 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 included in Revenue on our statements of income were $(81) million, $46 million and $55 million for the years ended December 31, 2011, 2010 and 2009, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather and rate increases.  Accrued unbilled revenues for the Utility Operations segment were $468 million and $549 million as of December 31, 2011 and 2010, respectively.

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Assumptions and Approach Used

For each operating company, we compute the monthly estimate for unbilled revenues as net generation 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.

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 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.

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.

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For additional information regarding derivatives, hedging and fair value measurements, see Notes 9 and 10.  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.  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.  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.

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 deductible amounts as permitted under the provisions of the tax law to be paid to 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 medical and life insurance benefits for retired employees (Postretirement Plans).  The Pension Plans and Postretirement Plans are collectively the Plans.

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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 7 for information regarding costs and assumptions for employee retirement and postretirement benefits.

The following table shows the net periodic cost of the Plans:

		Years Ended December 31,
Net Periodic Benefit Cost	2011		2010		2009
	(in millions)
Pension Plans	$	118	$	141	$	96
Postretirement Plans		73		111		141

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 2012, 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.  We anticipate that the investment managers we employ for the Plans will invest the assets to generate future returns averaging 7.25%.

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:

							Other Postretirement
	Pension Plans						Benefit Plans
				Assumed/						Assumed/
	2012			Expected			2012			Expected
	Target			Long-Term			Target			Long-Term
	Asset			Rate of			Asset			Rate of
	Allocation			Return			Allocation			Return
Equity		45	%		8.75	%		66	%		8.50	%
Fixed Income		45	%		5.25	%		33	%		5.08	%
Other Investments		10	%		8.75	%		-	%		-	%
Cash and Cash Equivalents		-	%		-	%		1	%		1.55	%
Total		100	%					100	%

We regularly review the actual asset allocation and periodically rebalance the investments to our targeted allocation.  We believe that 7.25% is a reasonable estimate of the long-term rate of return on the Plans’ assets despite the recent market volatility.  The Pension Plans’ assets had an actual gain of 8.1% and 13.4% for the years ended December 31, 2011 and 2010, respectively.  The Postretirement Plans’ assets had an actual gain of 0.4% and 11.3% for the years ended December 31, 2011 and 2010, 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, 2011, we had cumulative losses of approximately $104 million that remain to be recognized in the calculation of the market-related value of assets.  These unrecognized net actuarial losses may result in increases in the future pension costs depending on several factors, including whether such losses at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance.

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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 similar to those included in the Moody’s Aa bond index is constructed with a duration 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 at December 31, 2011 under this method was 4.55% for the Qualified Plan, 4.4% for the Nonqualified Plans and 4.75% for the Postretirement Plans.  Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on the Pension Plans’ assets of 7.25%, discount rates of 4.55% and 4.4% and various other assumptions, we estimate that the pension costs for the Pension Plans will approximate $127 million, $150 million and $125 million in 2012, 2013 and 2014, respectively.  Based on an expected rate of return on the Postretirement Plans’ assets of 7.25%, a discount rate of 4.75% and various other assumptions, we estimate costs will approximate $95 million, $88 million and $81 million in 2012, 2013 and 2014, respectively.  Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans.  The actuarial assumptions used may differ materially from actual results.  The effects of a 50 basis point change to selective actuarial assumptions are included in the “Effect if Different Assumptions Used” section below.

The value of the Pension Plans’ assets increased to $4.3 billion at December 31, 2011 from $3.9 billion at December 31, 2010 primarily due to $450 million of contributions.  During 2011, the Qualified Plan paid $287 million and the Nonqualified Plans paid $7 million in benefits to plan participants.  The value of the Postretirement Plans’ assets decreased to $1.4 billion at December 31, 2011 from $1.5 billion at December 31, 2010 primarily due to benefits paid exceeding contributions by the company and the participants.  The Postretirement Plans paid $150 million in benefits to plan participants during 2011.

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.

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Effect if Different Assumptions Used

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

					Other Postretirement
	Pension Plans				Benefit Plans
	+0.5%		-0.5%		+0.5%		-0.5%
	(in millions)
Effect on December 31, 2011 Benefit Obligations
Discount Rate	$	(256)	$	281	$	(142)	$	159
Compensation Increase Rate		11		(10)		-		-
Cash Balance Crediting Rate		45		(40)		NA		NA
Health Care Cost Trend Rate		NA		NA		120		(109)
Effect on 2011 Periodic Cost
Discount Rate		(18)		19		(11)		12
Compensation Increase Rate		4		(4)		-		-
Cash Balance Crediting Rate		13		(12)		NA		NA
Health Care Cost Trend Rate		NA		NA		18		(16)
Expected Return on Plan Assets		(20)		20		(7)		7
NA   Not Applicable

NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Pronouncements Adopted During 2011

We adopted ASU 2011-5 “Presentation of Comprehensive Income” effective for the 2011 Annual Report including the deferral of  the reclassification adjustment presentation provisions of ASU 2011-05 under the terms in ASU 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income.”  The standard requires other comprehensive income be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income.  This standard changed the presentation of our financial statements but did not affect the calculation of net income, comprehensive income or earnings per share.

See Note 2 for further discussion of accounting pronouncements.

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 revenue recognition, contingencies, financial instruments, leases, insurance, hedge accounting and consolidation policy.  We also expect to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP.  The ultimate pronouncements resulting from these and future projects could have an impact on our future net income and financial position.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

Our Utility Operations segment is exposed to certain market risks as a major power producer and through its transactions in wholesale electricity, coal and emission allowance trading 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 because occasionally we 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 Generation and Marketing segment primarily transacts in wholesale energy marketing within ERCOT and, to a lesser extent, wholesale and retail energy contracts in Ohio within PJM and MISO.  This segment is exposed to certain market risks as a marketer of wholesale and retail electricity.  These risks 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.

All Other included natural gas operations which held forward natural gas contracts that were not sold with the natural gas pipeline and storage assets.  These contracts were financial derivatives, which settled and expired in the fourth quarter of 2011.

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 and natural gas and, to a lesser degree, heating oil and gasoline, emission allowance 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 group in accordance with the market risk policy 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 (CORC) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures.  The CORC consists of our Chief Operating Officer, Chief Financial Officer, Senior Vice President of Commercial Operations and Chief Risk Officer.  When commercial activities exceed predetermined limits, we modify the positions to reduce the risk to be within the limits unless specifically approved by the CORC.

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The following table summarizes the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2010:

	MTM Risk Management Contract Net Assets (Liabilities)
	Year Ended December 31, 2011
				Generation
		Utility		and
		Operations		Marketing		All Other		Total
		(in millions)
Total MTM Risk Management Contract Net Assets
	at December 31, 2010	$	91	$	140	$	2	$	233
(Gain) Loss from Contracts Realized/Settled During the Period and
	Entered in a Prior Period		(21)		(22)		(2)		(45)
Fair Value of New Contracts at Inception When Entered During the
	Period (a)		6		16		-		22
Net Option Premiums Received for Unexercised or Unexpired
	Option Contracts Entered During the Period		-		-		-		-
Changes in Fair Value Due to Market Fluctuations During the
	Period (b)		-		(2)		-		(2)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)			(17)		-		-		(17)
Total MTM Risk Management Contract Net Assets
	at December 31, 2011	$	59	$	132	$	-		191
Commodity Cash Flow Hedge Contracts									(5)
Interest Rate and Foreign Currency Cash Flow HedgeContracts									(42)
Fair Value HedgeContracts									-
Collateral Deposits									107
Total MTM Derivative Contract Net Assets at December 31, 2011								$	251

(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.

See Note 9 – Derivatives and Hedging and Note 10 – 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.

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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, 2011, our credit exposure net of collateral to sub investment grade counterparties was approximately 5.9%, 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, 2011, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

		Exposure						Number of		Net Exposure
		Before						Counterparties		of
		Credit		Credit		Net		>10% of		Counterparties
Counterparty Credit Quality		Collateral		Collateral		Exposure		Net Exposure		>10%
		(in millions, except number of counterparties)
Investment Grade		$	611	$	2	$	609		1	$	172
Split Rating			1		-		1		1		1
Noninvestment Grade			14		2		12		1		12
No External Ratings:
	Internal Investment Grade		280		4		276		1		128
	Internal Noninvestment Grade		54		11		43		1		35
Total as of December 31, 2011		$	960	$	19	$	941		5	$	348
Total as of December 31, 2010		$	946	$	33	$	913		7	$	347

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, 2011, a near term typical change in commodity prices is not expected to have a material effect on our net income, cash flows or financial condition.

The following table shows the end, high, average and low market risk as measured by VaR for the trading portfolio for the periods indicated:

VaR Model

Twelve Months Ended								Twelve Months Ended
December 31, 2011								December 31, 2010
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	-	$	2	$	-	$	-	$	-	$	2	$	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.

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As our VaR calculation captures recent price movements, we also perform regular stress testing of the portfolio to understand our exposure to extreme price movements.  We employ a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four 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 or the CORC 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, 2011 and 2010, the estimated EaR on our debt portfolio for the following twelve months was $29 million and $5 million, respectively.

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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, 2011 and 2010, 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, 2011.  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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, in 2011 the Company changed its method of presenting comprehensive income due to the adoption of FASB Accounting Standards Update No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income.  The change in presentation has been applied retrospectively to all periods presented. As discussed in Note 2 to the consolidated financial statements, on January 1, 2010, the Company adopted FASB Accounting Standards Update No. 2009-16, Transfers and Servicing (Topic 860): Accounting for Transfers of Financial Assets.

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, 2011, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2012 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/   Deloitte & Touche LLP

Columbus, Ohio

February 27, 2012

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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, 2011, based on criteria established in Internal Control — Integrated Framework 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, 2011, based on the criteria established in Internal Control — Integrated Framework 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, 2011 of the Company and our report dated February 27, 2012 expressed an unqualified opinion on those financial statements and included an explanatory paragraph relating to the Company’s adoption of new accounting pronouncements in 2011 and 2010.

/s/   Deloitte & Touche LLP

Columbus, Ohio

February 27, 2012

44

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, 2011.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework.  Based on management’s assessment, AEP’s internal control over financial reporting was effective as of December 31, 2011.

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.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2011, 2010 and 2009
(in millions, except per-share and share amounts)
	2011			2010			2009
REVENUES
Utility Operations	$	14,091		$	13,687		$	12,733
Other Revenues		1,025			740			756
TOTAL REVENUES		15,116			14,427			13,489
EXPENSES
Fuel and Other Consumables Used for Electric Generation		4,421			4,029			3,478
Purchased Electricity for Resale		1,191			1,000			1,053
Other Operation		2,868			3,132			2,620
Maintenance		1,236			1,142			1,205
Asset Impairments and Other Related Charges		139			-			-
Depreciation and Amortization		1,655			1,641			1,597
Taxes Other Than Income Taxes		824			820			765
TOTAL EXPENSES		12,334			11,764			10,718
OPERATING INCOME		2,782			2,663			2,771
Other Income (Expense):
Interest and Investment Income		27			38			11
Carrying Costs Income		393			70			47
Allowance for Equity Funds Used During Construction		98			77			82
Interest Expense		(933	)		(999	)		(973	)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		2,367			1,849			1,938
Income Tax Expense		818			643			575
Equity Earnings of Unconsolidated Subsidiaries		27			12			7
INCOME BEFORE EXTRAORDINARY ITEMS		1,576			1,218			1,370
EXTRAORDINARY ITEMS, NET OF TAX		373			-			(5	)
NET INCOME		1,949			1,218			1,365
Net Income Attributable to Noncontrolling Interests		3			4			5
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS		1,946			1,214			1,360
Preferred Stock Dividend Requirements of Subsidiaries Including Capital Stock Expense		5			3			3
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1,941		$	1,211		$	1,357
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING		482,169,282			479,373,306			458,677,534
BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
Income Before Extraordinary Items	$	3.25		$	2.53		$	2.97
Extraordinary Items, Net of Tax		0.77			-			(0.01	)
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	4.02		$	2.53		$	2.96
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING		482,460,328			479,601,442			458,982,292
DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
Income Before Extraordinary Items	$	3.25		$	2.53		$	2.97
Extraordinary Items, Net of Tax		0.77			-			(0.01	)
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
SHAREHOLDERS	$	4.02		$	2.53		$	2.96
CASH DIVIDENDS DECLARED PER SHARE	$	1.85		$	1.71		$	1.64
See Notes to Consolidated Financial Statements beginning on page 52.

46

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2011, 2010 and 2009
(in millions)
	2011			2010			2009
NET INCOME	$	1,949		$	1,218		$	1,365
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $18 in 2011, $14 in 2010 and $4 in 2009		(34	)		26			7
Securities Available for Sale, Net of Tax of $1 in 2011, $4 in 2010 and $6 in 2009		(2	)		(8	)		11
Reapplication of Regulated Operations Accounting Guidance for Pensions, Net of
Tax of $8 in 2009		-			-			15
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $13 in 2011,
$12 in 2010 and $13 in 2009		24			22			23
Pension and OPEB Funded Status, Net of Tax of $41 in 2011, $25 in 2010 and
$12 in 2009		(77	)		(47	)		22
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(89	)		(7	)		78
TOTAL COMPREHENSIVE INCOME		1,860			1,211			1,443
Total Comprehensive Income Attributable to Noncontrolling Interests		3			4			5
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
SHAREHOLDERS		1,857			1,207			1,438
Preferred Stock Dividend Requirements Including Capital Stock Expense		5			3			3
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
COMMON SHAREHOLDERS	$	1,852		$	1,204		$	1,435
See Notes to Consolidated Financial Statements beginning on page 52.

47

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2011, 2010 and 2009
(in millions)
	AEP Common Shareholders
	Common Stock								Accumulated
									Other
					Paid-in		Retained		Comprehensive		Noncontrolling
	Shares		Amount		Capital		Earnings		Income (Loss)		Interests		Total
TOTAL EQUITY – DECEMBER 31, 2008		426	$	2,771	$	4,527	$	3,847	$	(452)	$	17	$	10,710
Issuance of Common Stock		72		468		1,311								1,779
Common Stock Dividends								(753)				(5)		(758)
Preferred Stock Dividend Requirements of Subsidiaries								(3)						(3)
Purchase of JMG						37						(18)		19
Other Changes in Equity						(51)						1		(50)
SUBTOTAL – EQUITY														11,697
NET INCOME								1,360				5		1,365
OTHER COMPREHENSIVE INCOME										78				78
TOTAL EQUITY – DECEMBER 31, 2009		498		3,239		5,824		4,451		(374)		-		13,140
Issuance of Common Stock		3		18		75								93
Common Stock Dividends								(820)				(4)		(824)
Preferred Stock Dividend Requirements of Subsidiaries								(3)						(3)
Other Changes in Equity						5								5
SUBTOTAL – EQUITY														12,411
NET INCOME								1,214				4		1,218
OTHER COMPREHENSIVE LOSS										(7)				(7)
TOTAL EQUITY – DECEMBER 31, 2010		501		3,257		5,904		4,842		(381)		-		13,622
Issuance of Common Stock		3		17		75								92
Common Stock Dividends								(894)				(4)		(898)
Preferred Stock Dividend Requirements of Subsidiaries								(2)						(2)
Loss on Reacquired Preferred Stock						(4)								(4)
Capital Stock Expense						(16)								(16)
Other Changes in Equity						11		(2)				2		11
SUBTOTAL – EQUITY														12,805
NET INCOME								1,946				3		1,949
OTHER COMPREHENSIVE LOSS										(89)				(89)
TOTAL EQUITY – DECEMBER 31, 2011		504	$	3,274	$	5,970	$	5,890	$	(470)	$	1	$	14,665
See Notes to Consolidated Financial Statements beginning on page 52.

48

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2011 and 2010
(in millions)
			2011		2010
CURRENT ASSETS
Cash and Cash Equivalents			$	221	$	294
Other Temporary Investments
	(December 31, 2011 and 2010 amounts include $281 and $287, respectively, related to Transition Funding and EIS)			294		416
Accounts Receivable:
	Customers			690		683
	Accrued Unbilled Revenues			106		195
	Pledged Accounts Receivable - AEP Credit			920		949
	Miscellaneous			150		137
	Allowance for Uncollectible Accounts			(32)		(41)
		Total Accounts Receivable		1,834		1,923
Fuel				657		837
Materials and Supplies				635		611
Risk Management Assets				193		232
Accrued Tax Benefits				51		389
Regulatory Asset for Under-Recovered Fuel Costs				65		81
Margin Deposits				67		88
Prepayments and Other Current Assets				165		145
TOTAL CURRENT ASSETS				4,182		5,016
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			24,938		24,352
	Transmission			9,048		8,576
	Distribution			14,783		14,208
Other Property, Plant and Equipment (including nuclear fuel and coal mining)				3,780		3,846
Construction Work in Progress				3,121		2,758
Total Property, Plant and Equipment				55,670		53,740
Accumulated Depreciation and Amortization				18,699		18,066
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET				36,971		35,674
OTHER NONCURRENT ASSETS
Regulatory Assets				6,026		4,943
Securitized Transition Assets				1,627		1,742
Spent Nuclear Fuel and Decommissioning Trusts				1,592		1,515
Goodwill				76		76
Long-term Risk Management Assets				403		410
Deferred Charges and Other Noncurrent Assets				1,346		1,079
TOTAL OTHER NONCURRENT ASSETS				11,070		9,765
TOTAL ASSETS			$	52,223	$	50,455
See Notes to Consolidated Financial Statements beginning on page 52.

49

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2011 and 2010
(dollars in millions)
					2011		2010
CURRENT LIABILITIES
Accounts Payable					$	1,095	$	1,061
Short-term Debt:
	Securitized Debt for Receivables - AEP Credit					666		690
	Other Short-term Debt					984		656
		Total Short-term Debt				1,650		1,346
Long-term Debt Due Within One Year
	(December 31, 2011 and 2010 amounts include $293 and $237, respectively, related to Transition Funding, DCC Fuel and Sabine)					1,433		1,309
Risk Management Liabilities						150		129
Customer Deposits						289		273
Accrued Taxes						717		702
Accrued Interest						279		281
Regulatory Liability for Over-Recovered Fuel Costs						8		17
Deferred Gain and Accrued Litigation Costs						-		448
Other Current Liabilities						990		952
TOTAL CURRENT LIABILITIES						6,611		6,518
NONCURRENT LIABILITIES
Long-term Debt
	(December 31, 2011 and 2010 amounts include $1,674 and $1,857, respectively, related to Transition Funding, DCC Fuel and Sabine)					15,083		15,502
Long-term Risk Management Liabilities						195		141
Deferred Income Taxes						8,227		7,359
Regulatory Liabilities and Deferred Investment Tax Credits						3,195		3,171
Asset Retirement Obligations						1,472		1,394
Employee Benefits and Pension Obligations						1,801		1,893
Deferred Credits and Other Noncurrent Liabilities						974		795
TOTAL NONCURRENT LIABILITIES						30,947		30,255
TOTAL LIABILITIES						37,558		36,773
Cumulative Preferred Stock Not Subject to Mandatory Redemption						-		60
Rate Matters (Note 3)
Commitments and Contingencies (Note 5)
EQUITY
Common Stock – Par Value – $6.50 Per Share:
			2011	2010
	Shares Authorized		600,000,000	600,000,000
	Shares Issued		503,759,460	501,114,881
(20,336,592 shares and 20,307,725 shares were held in treasury at December 31, 2011 and
	2010, respectively)					3,274		3,257
Paid-in Capital						5,970		5,904
Retained Earnings						5,890		4,842
Accumulated Other Comprehensive Income (Loss)						(470)		(381)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY						14,664		13,622
Noncontrolling Interests						1		-
TOTAL EQUITY						14,665		13,622
TOTAL LIABILITIES AND EQUITY					$	52,223	$	50,455
See Notes to Consolidated Financial Statements beginning on page 52.

50

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2011, 2010 and 2009
(in millions)
				2011		2010		2009
OPERATING ACTIVITIES
Net Income				$	1,949	$	1,218	$	1,365
Adjustments to Reconcile Net Income to Net Cash Flows
	from Operating Activities:
		Depreciation and Amortization			1,655		1,641		1,597
		Deferred Income Taxes			794		809		1,244
		Gain on Settlement with BOA and Enron			(51)		-		-
		Settlement of Litigation with BOA and Enron			(211)		-		-
		Extraordinary Items, Net of Tax			(373)		-		5
		Asset Impairments and Other Related Charges			139		-		-
		Carrying Costs Income			(393)		(70)		(47)
		Allowance for Equity Funds Used During Construction			(98)		(77)		(82)
		Mark-to-Market of Risk Management Contracts			37		30		(59)
		Amortization of Nuclear Fuel			137		139		63
		Pension Contributions to Qualified Plan Trust			(450)		(500)		-
		Property Taxes			(15)		(21)		(17)
		Fuel Over/Under-Recovery, Net			(25)		(253)		(474)
		Change in Other Noncurrent Assets			(112)		(89)		(152)
		Change in Other Noncurrent Liabilities			307		202		244
	Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		107		(866)		41
			Fuel, Materials and Supplies		176		221		(475)
			Accounts Payable		(44)		(36)		8
			Accrued Taxes, Net		193		179		(470)
			Other Current Assets		37		73		(73)
			Other Current Liabilities		29		62		(243)
Net Cash Flows from Operating Activities					3,788		2,662		2,475
INVESTING ACTIVITIES
Construction Expenditures					(2,669)		(2,345)		(2,792)
Change in Other Temporary Investments, Net					8		(4)		16
Purchases of Investment Securities					(1,321)		(1,918)		(853)
Sales of Investment Securities					1,379		1,817		748
Acquisitions of Nuclear Fuel					(106)		(91)		(169)
Acquisitions of Assets					(19)		(155)		(104)
Acquisition of Cushion Gas from BOA					(214)		-		-
Proceeds from Sales of Assets					123		187		278
Other Investing Activities					(71)		(14)		(40)
Net Cash Flows Used for Investing Activities					(2,890)		(2,523)		(2,916)
FINANCING ACTIVITIES
Issuance of Common Stock, Net					92		93		1,728
Issuance of Long-term Debt					1,328		1,270		2,306
Commercial Paper and Credit Facility Borrowings					488		565		127
Change in Short-term Debt, Net					744		770		119
Retirement of Long-term Debt					(1,665)		(1,993)		(816)
Retirement of Cumulative Preferred Stock					(64)		-		-
Commercial Paper and Credit Facility Repayments					(928)		(115)		(2,096)
Principal Payments for Capital Lease Obligations					(71)		(95)		(82)
Dividends Paid on Common Stock					(898)		(824)		(758)
Dividends Paid on Cumulative Preferred Stock					(2)		(3)		(3)
Other Financing Activities					5		(3)		(5)
Net Cash Flows from (Used for) Financing Activities					(971)		(335)		520
Net Increase (Decrease) in Cash and Cash Equivalents					(73)		(196)		79
Cash and Cash Equivalents at Beginning of Period					294		490		411
Cash and Cash Equivalents at End of Period				$	221	$	294	$	490
See Notes to Consolidated Financial Statements beginning on page 52.

51

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Organization and Summary of Significant Accounting Policies
2.	New Accounting Pronouncements and Extraordinary Items
3.	Rate Matters
4.	Effects of Regulation
5.	Commitments, Guarantees and Contingencies
6.	Acquisitions, Dispositions and Impairments
7.	Benefit Plans
8.	Business Segments
9.	Derivatives and Hedging
10.	Fair Value Measurements
11.	Income Taxes
12.	Leases
13.	Financing Activities
14.	Stock-Based Compensation
15.	Property, Plant and Equipment
16.	Cost Reduction Initiatives
17.	Unaudited Quarterly Financial Information
18.	Goodwill and Other Intangible Assets

52

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

The principal business conducted by six of our electric utility operating companies is the generation, transmission and distribution of electric power.  KGPCo, TCC and WPCo provide only transmission and distribution services.  TNC engages in the transmission and distribution of electric power and is a part owner of the Oklaunion Plant operated by PSO.  TNC leases its entire portion of the output of the plant through 2027 to a nonutility affiliate.  AEGCo, a regulated electricity generation company, provides power to three of our regulated electric utility operating companies.  These companies are subject to regulation by the FERC under the Federal Power Act and the Energy Policy Act of 2005.  These companies maintain accounts in accordance with the FERC and other regulatory guidelines.  These companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.

Seven wholly-owned transmission companies and several joint ventures have been approved by the FERC for our new transmission investments.  These companies are subject to regulation by the FERC and maintain their accounts accordingly.

We also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States.  In addition, our operations include nonregulated wind farms and barging operations and we provide various energy-related services.

CSPCo-OPCo Merger

On December 31, 2011, CSPCo merged into OPCo with OPCo being the surviving entity.  All prior disclosed amounts have been recast as if the merger occurred on the first day of the earliest reporting period.   All contracts and operations of CSPCo and its subsidiary are now part of OPCo.  The merger had no impact on our prior reported net income, cash flow or financial condition.

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 that a nonregulated affiliate can bill an affiliated public utility company 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.  Our wholesale power transactions in the SPP region are cost-based due to PSO and SWEPCo having market power in the SPP region.

53

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 aligning generation/power supply rates over time with 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.  Effective November 2009, we had no active REPs in ERCOT.  SWEPCo operates in the SPP area which includes a portion of Texas.  In 2009, the Texas legislature amended its restructuring legislation for the generation portion of SWEPCo’s Texas retail jurisdiction to delay indefinitely restructuring requirements.  As a result, SWEPCo reapplied accounting guidance for “Regulated Operations” to its Texas generation operations.

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 the FERC’s Open Access Transmission Tariff (OATT) rates 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.

In addition, the FERC regulates the SIA, the Interconnection Agreement, the CSW Operating Agreement, the System Transmission Integration Agreement, the Transmission Agreement, the Transmission Coordination Agreement and the AEP System Interim Allowance Agreement, all of which allocate shared system costs and revenues to the utility subsidiaries that are parties to each agreement.

Principles of Consolidation

Our consolidated financial statements include our wholly-owned and majority-owned subsidiaries and variable interest entities (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 recorded as Deferred Charges and Other Noncurrent Assets on our balance sheets; equity earnings are included in Equity Earnings of Unconsolidated Subsidiaries on our statements of income.  We have ownership interests in generating units that are jointly-owned with nonaffiliated companies.  Our proportionate share of the operating costs associated with such facilities is included on our statements of income and our proportionate share of the assets and liabilities are reflected on our balance sheets.

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 and a protected cell of EIS.  In addition, we have not provided material financial or other support to Sabine, DCC Fuel, Transition Funding, our protected cell of EIS and AEP Credit 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).

54

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, 2011, 2010 and 2009 were $128 million, $ 133 million and $99 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on our 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 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 and EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate its assets and liabilities.  Our insurance premium expense to the protected cell for the years ended December 31, 2011, 2010 and 2009 were $ 48 million, $35 million and $ 30 million, respectively.  See the tables below for the classification of the protected cell’s assets and liabilities on our balance sheets.  The amount reported as equity is the protected cell’s policy holders’ surplus.

I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC and DCC IV LLC (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.  DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC and DCC Fuel IV LLC are separate legal entities from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the DCC Fuel LLC and DCC Fuel II LLC leases are made semi-annually and began in April 2010 and October 2010, respectively.  Payments on the DCC Fuel III LLC lease are made monthly and began in January 2011.  Payments on the DCC Fuel IV LLC lease are made quarterly and began in February 2012.  Payments on the leases for the years ended December 31, 2011 and 2010 were $85 million and $ 59 million, respectively.  No payments were made to DCC Fuel in 2009.  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 48, 54, 54 and 54 month lease term, respectively.  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.  See the tables below for the classification of DCC Fuel’s assets and liabilities on our 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 has concluded that we are the primary beneficiary and are required to consolidate its assets and liabilities.  See the tables below for the classification of AEP Credit’s assets and liabilities on our balance sheets.  See “Securitized Accounts Receivables – AEP Credit” section of Note 13.

55

Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas restructuring law.  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 $1.7 billion and $ 1.8 billion at December 31, 2011 and 2010, respectively, and are included in current and long-term debt on the balance sheets.  Transition Funding has securitized transition assets of $1.6 billion and $1.7 billion at December 31, 2011 and 2010, respectively, which are presented separately on the face of the balance sheets.  The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from 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 our 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, 2011
(in millions)
													TCC
	SWEPCo			I&M			Protected Cell						Transition
	Sabine			DCC Fuel			of EIS			AEP Credit			Funding
ASSETS
Current Assets		$	48		$	118		$	121		$	910		$	220
Net Property, Plant and Equipment			154			188			-			-			-
Other Noncurrent Assets			42			118			6			1			1,580
Total Assets		$	244		$	424		$	127		$	911		$	1,800
LIABILITIES AND EQUITY
Current Liabilities		$	68		$	103		$	40		$	864		$	229
Noncurrent Liabilities			176			321			71			1			1,557
Equity			-			-			16			46			14
Total Liabilities and Equity		$	244		$	424		$	127		$	911		$	1,800
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2010
(in millions)
													TCC
	SWEPCo			I&M			Protected Cell						Transition
	Sabine			DCC Fuel			of EIS			AEP Credit			Funding
ASSETS
Current Assets		$	50		$	92		$	131		$	924		$	214
Net Property, Plant and Equipment			139			173			-			-			-
Other Noncurrent Assets			34			112			1			10			1,746
Total Assets		$	223		$	377		$	132		$	934		$	1,960
LIABILITIES AND EQUITY
Current Liabilities		$	33		$	79		$	33		$	886		$	221
Noncurrent Liabilities			190			298			85			1			1,725
Equity			-			-			14			47			14
Total Liabilities and Equity		$	223		$	377		$	132		$	934		$	1,960

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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, 2011, 2010 and 2009 were $62 million, $56 million and $ 43 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 our balance sheets.

Our investment in DHLC was:

	December 31,
	2011				2010
	As Reported on		Maximum		As Reported on		Maximum
	the Balance Sheet		Exposure		the Balance Sheet		Exposure
	(in millions)
Capital Contribution from SWEPCo	$	8	$	8	$	6	$	6
Retained Earnings		1		1		2		2
SWEPCo's Guarantee of Debt		-		52		-		48
Total Investment in DHLC	$	9	$	61	$	8	$	56

We and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH).  In February 2011, PJM directed that work on the PATH project be suspended.  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 our 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.  As of December 31, 2011, PATH-WV had no debt outstanding.  However, when debt is issued, the debt to equity ratio in each series should be consistent with other regulated utilities.  The entities recover costs through regulated rates.

Given the structure of the entity, we may be required to provide future financial support to PATH-WV in the form of a capital call.  This would be considered an increase to our investment in the entity.  Our maximum exposure to loss is to the extent of our investment.  The likelihood of such a loss is remote since the FERC approved PATH-WV’s request for regulatory recovery of cost and a return on the equity invested.

Our investment in PATH-WV was:

	December 31,
	2011					2010
	As Reported on			Maximum		As Reported on		Maximum
	the Balance Sheet			Exposure		the Balance Sheet		Exposure
			(in millions)
Capital Contribution from AEP	$	19		$	19	$	18	$	18
Retained Earnings		10			10		6		6
Total Investment in PATH-WV	$	29		$	29	$	24	$	24

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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 (future revenue reductions or refunds) to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues and income with its passage to customers through the reduction of regulated revenues.  Due to the passage of legislation requiring restructuring and a transition to customer choice and market-based rates, we discontinued the application of “Regulated Operations” accounting treatment for the generation portion of our business in Ohio for OPCo and in Texas for TNC.  In 2009, the Texas legislature amended its restructuring legislation for the generation portion of SWEPCo’s Texas retail jurisdiction to delay indefinitely restructuring requirements.  As a result, SWEPCo reapplied accounting guidance for “Regulated Operations” to its Texas generation operations.

Accounting guidance for “Discontinuation of Rate-Regulated Operations” requires the recognition of an impairment of stranded net regulatory assets and stranded plant costs if they are not recoverable in regulated rates.  In addition, an enterprise is required to eliminate from its balance sheet the effects of any actions of regulators that had been recognized as regulatory assets and regulatory liabilities.  Such impairments and adjustments are classified as an extraordinary item.

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, 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.

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 10.

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Inventory

Fossil fuel inventories are generally carried at average cost.  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 our 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.  In Ohio, we record allowances at the lower of cost or market for the period after our FAC expires in May 2015.  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 our balance sheets.  We record the consumption of allowances in the production of energy in Fuel and Other Consumables Used for Electric Generation on our statements of income at an average cost.  We record allowances held for speculation in Prepayments and Other Current Assets on our balance sheets.  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 Utility Operations Revenue on our 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 and Equity Investments

Regulated

Electric utility property, plant and equipment for our rate-regulated operations are stated at original purchase cost. Additions, major replacements and betterments are added to the plant accounts.  Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation under the group composite method of 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.  Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in the original cost, less salvage, being charged to accumulated depreciation.  The depreciation rates that are established take into account the past history of interim capital replacements and the amount of 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.  Equity investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value.

The fair value of an asset or investment is the amount at which that asset or investment 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 or investments 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 cost-based rate-regulated operations listed above but with the following exceptions.  Property, plant and equipment of nonregulated operations and equity investments (included in Deferred Charges and Other Noncurrent Assets) 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 (AFUDC) and Interest Capitalization

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.  For nonregulated operations, including generating assets owned by OPCo and certain generating assets in Texas, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest”.  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.

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Accounts Receivable, Short-term Debt and Accounts Payable 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.

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 non-binding 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 and 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.  Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.

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 do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.  Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals.

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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 revenues billed to customers over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel revenues billed to customers) are generally deferred as current regulatory assets.  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 fuel cost disallowance becomes probable, we adjust our FAC deferrals and record provisions for estimated refunds to recognize these probable outcomes.  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 or terminated.

Changes in fuel costs, including purchased power in Kentucky for KPCo, in Indiana and Michigan for I&M, in Ohio (beginning in 2012 through May 2015) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO and in Virginia for APCo are reflected in rates in a timely manner through the FAC.  Changes in fuel costs, including purchased power in Ohio (beginning in 2009 through 2011) for OPCo and in West Virginia for APCo are reflected in rates through FAC phase-in plans.  The FAC generally includes some sharing of off-system sales.  In West Virginia for APCo, all of the profits from off-system sales are given to customers through the FAC.  None of the profits from off-system sales are given to customers through the FAC in Ohio for OPCo.  A portion of profits 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, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan (all areas of Michigan beginning in December 2010) 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 impacted 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.

When regulatory assets are probable of recovery through regulated rates, we record them as assets on our 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.

Traditional Electricity Supply and Delivery Activities

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services.  We recognize the revenues on our 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.

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Most of the power produced at the generation plants of the AEP East companies is sold to PJM, the RTO operating in the east service territory.  We purchase power from PJM to supply our customers.  Generally, these power sales and purchases are reported on a net basis as revenues on our statements of income.  However, purchases of power in excess of sales to PJM, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on our statements of income.  Other RTOs in which we participate do not function in the same manner as PJM.  They function as balancing organizations and not as exchanges.

Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on our statements of income.  Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s economic substance.  Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on our 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 electricity, natural gas, coal and emission allowances 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 and the buying and selling of financial energy contracts, which include exchange traded futures and options, as well as OTC options and swaps.  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 the unrealized and realized gains and losses on wholesale marketing and risk management transactions that are accounted for using MTM in Revenues on our statements of income on a net basis.  In jurisdictions subject to cost-based regulation, we defer the 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 our 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 within the same financial statement line item as the forecasted transaction on our 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 our 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 9.

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.

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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.

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.

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.

Government Grants

For APCo’s commercial scale Carbon Capture and Sequestration facility at the Mountaineer Plant and OPCo’s gridSMART® demonstration program, APCo and OPCo are reimbursed by the Department of Energy for allowable costs incurred during the billing period.  These reimbursements result in the reduction of Other Operation and Maintenance expenses on our statements of income or a reduction in Construction Work in Progress on our balance sheets.

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.  Some jurisdictions require that these costs be expensed upon reacquisition.  We report gains and losses on the reacquisition of debt for operations not subject to cost-based rate regulation in Interest Expense on our statements of income.

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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 our 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.

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.

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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	45.0	%
Fixed Income	45.0	%
Other Investments	10.0	%
OPEB Plans Assets	Target
Equity	66.0	%
Fixed Income	33.0	%
Cash	1.0	%

The investment policy for each benefit plan contains various investment limitations.  The investment policies establish concentration limits for securities.  Investment policies prohibit the benefit trust funds from purchasing 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% of each manager's equity portfolio.

·   No investment in excess of 5% of an outstanding class of any company.

·   No securities may be bought or sold on margin or other use of leverage.

For fixed income investments, the concentration limits must not exceed:

·   3% in any single issuer

·   5% private placements

·   5% 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, 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 classified as Level 1.

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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 11 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 cash collateral.  All loans are collateralized by at least 102% of the loaned asset’s market value and the cash collateral is invested.  The difference between the rebate owed to the borrower and the cash 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.

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. The trust assets may not be used for another jurisdiction’s liabilities.  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 our 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 equity and debt 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

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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 spent nuclear fuel 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 5 for additional discussion of nuclear matters.  See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 10 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).

Accumulated Other Comprehensive Income (Loss) (AOCI)

AOCI is included on our balance sheets in our equity section.  Our components of AOCI as of December 31, 2011 and 2010 are shown in the following table:

	December 31,
Components	2011		2010
	(in millions)
Cash Flow Hedges, Net of Tax	$	(23)	$	11
Securities Available for Sale, Net of Tax		2		4
Amortization of Pension and OPEB Deferred Costs, Net of Tax		81		57
Pension and OPEB Funded Status, Net of Tax		(530)		(453)
Total	$	(470)	$	(381)

Stock-Based Compensation Plans

At December 31, 2011, we had stock options, performance units, restricted shares 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.

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 HR 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 do not become payable to executives until after their service ends.  Dividends paid on career shares are reinvested as additional career shares.

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.

In January 2006, we adopted accounting guidance for “Compensation - Stock Compensation” which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including stock options, based on estimated fair values.

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We recognize compensation expense for all share-based awards with service only vesting conditions granted on or after January 2006 using the straight-line single-option method.  Stock-based compensation expense recognized on our statements of income for the years ended December 31, 2011, 2010 and 2009 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, 2011, 2010 and 2009, compensation expense is included in Net Income for the performance units, career shares, restricted 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	2011		2010		2009
	(in millions)
Income Before Extraordinary Items	$	1,568	$	1,211	$	1,362
Extraordinary Items, Net of Tax		373		-		(5)
Net Income	$	1,941	$	1,211	$	1,357

Basic earnings per common share is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period.  Diluted earnings per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.

The following table presents our basic and diluted EPS calculations included on our statements of income:

			Years Ended December 31,
			2011				2010				2009
			(in millions, except per share data)
					$/share				$/share				$/share
Earnings Attributable to AEP Common
	Shareholders		$	1,941			$	1,211			$	1,357
Weighted Average Number of Basic Shares
	Outstanding			482.2	$	4.02		479.4	$	2.53		458.7	$	2.96
Weighted Average Dilutive Effect of:
		Performance Share Units		-		-		0.1		-		0.3		-
		Stock Options		0.1		-		-		-		-		-
		Restricted Stock Units		0.2		-		0.1		-		-		-
Weighted Average Number of Diluted Shares
	Outstanding			482.5	$	4.02		479.6	$	2.53		459.0	$	2.96

Options to purchase 136,250 and 452,216 shares of common stock were outstanding at December 31, 2010 and 2009, respectively, but were not included in the computation of diluted earnings per share attributable to AEP common shareholders.  Since the options’ exercise prices were greater than the average market price of the common shares, the effect would have been antidilutive.  There were no antidilutive shares outstanding at December 31, 2011.

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OPCo Revised Depreciation Rates

Effective December 1, 2011, we revised book depreciation rates for certain of OPCo’s generating plants consistent with shortened depreciable lives for the generating units.  This change in depreciable lives is expected to result in a $54 million increase in depreciation expense in 2012.

Supplementary Information
 

			Years Ended December 31,
Related Party Transactions			2011			2010			2009
			(in millions)
AEP Consolidated Revenues – Utility Operations:
	Ohio Valley Electric Corporation (43.47% owned)		$	-		$	(20)	(a)	$	-
AEP Consolidated Revenues – Other Revenues:
	Ohio Valley Electric Corporation – Barging and Other
		Transportation Services (43.47% Owned)		37			29			31
AEP Consolidated Expenses – Purchased Electricity
for Resale:
	Ohio Valley Electric Corporation (43.47% Owned)			383	(b)		302	(b)		286

(a) The AEP Power Pool purchased power from OVEC to serve off-system sales through an agreement that began in January 2010 and ended in June 2010.

(b) The AEP Power Pool purchased power from OVEC to serve retail sales in 2011 and 2010.  The total amount reported in 2011 and 2010 includes $66 million and $10 million, respectively, related to these agreements.

		Years Ended December 31,
Cash Flow Information		2011		2010		2009
		(in millions)
Cash Paid (Received) for:
	Interest, Net of Capitalized Amounts	$	900	$	958	$	924
	Income Taxes		(118)		(268)		(98)
Noncash Investing and Financing Activities:
Acquisitions Under Capital Leases			54		225		86
Construction Expenditures Included in Current Liabilities at December 31,			380		267		348

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2.  NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEMS

NEW ACCOUNTING PRONOUNCEMENTS

We review the new accounting literature to determine its relevance, if any, to our business.  The following represents a summary of final pronouncements that impact our financial statements.

Pronouncements Adopted During 2011

The following standards were adopted during 2011.  Consequently, their impact is reflected in the financial statements.  The following paragraphs discuss their impact.

ASU 2011-05 “Presentation of Comprehensive Income” (ASU 2011-05)

We adopted ASU 2011-05 effective for the 2011 Annual Report.  The standard requires other comprehensive income be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income.

This standard requires retrospective application to all reporting periods presented in the financial statements.  This standard changed the presentation of our financial statements but did not affect the calculation of net income, comprehensive income or earnings per share.  The FASB deferred the reclassification adjustment presentation provisions of ASU 2011-05 under the terms in ASU 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income.”

EXTRAORDINARY ITEMS

TCC Texas Restructuring

In February 2006, the PUCT issued an order that denied recovery of capacity auction true-up amounts.  Based on the February 2006 PUCT order, TCC recorded the disallowance as a $421 million ($273 million, net of tax) extraordinary loss in the December 31, 2005 financial statements.  In July 2011, the Supreme Court of Texas reversed the PUCT’s February 2006 disallowance of capacity auction true-up amounts and remanded for reconsideration the treatment of certain tax balances under normalization rules.  Based upon the Supreme Court of Texas reversal of the PUCT’s capacity auction true-up disallowance, TCC recorded a pretax gain of $421 million ($273 million, net of tax) in Extraordinary Items, Net of Tax on the statements of income in the third quarter of 2011.

Following a remand proceeding, the PUCT allowed TCC to retain contested tax balances in full satisfaction of its true-up proceeding, including carrying charges.  Based upon the PUCT order, TCC recorded the reversal of regulatory credits of $65 million ($42 million, net of tax) and the reversal of $89 million of accumulated deferred investment tax credits ($58 million, net of tax) in Extraordinary Items, Net of Tax on the statements of income in the fourth quarter of 2011.  See “Texas Restructuring” section of Note AEP_RM.

SWEPCo Texas Restructuring

In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in SWEPCo’s SPP area of Texas until no sooner than January 1, 2011.  In May 2009, the governor of Texas signed a bill related to SWEPCo’s SPP area of Texas that requires continued cost of service regulation until certain stages have been completed and approved by the PUCT such that fair competition is available to all Texas retail customer classes.  Based upon the signing of the bill, SWEPCo re-applied “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction effective second quarter of 2009.  Management believes that a return to competition in the SPP area of Texas will not occur.  The reapplication of “Regulated Operations” accounting guidance resulted in an $8 million ($5 million, net of tax) extraordinary loss.

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3.  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 Filing

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 or until securitized.  The net FAC deferral as of December 31, 2011 was $521 million, excluding unrecognized equity carrying costs.  Collection of the FAC began in January 2012.  If OPCo is not ultimately permitted to fully recover its FAC deferral, it would reduce future net income and cash flows and impact financial condition.  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.  The order required OPCo to cease POLR billings and apply POLR collections since June 2011 first to the FAC deferral with any remaining balance to be credited to OPCo’s customers in November and December 2011.  As a result, OPCo recorded a pretax write-off of $47 million on the statement of income related to POLR for the period June 2011 through October 2011.  OPCo ceased collection of POLR billings in November 2011.  The PUCO order also agreed with OPCo’s position that the ESP statute provided a legal basis for reflecting an environmental carrying charge in OPCo’s base generation rates.  In addition, the PUCO rejected the intervenors’ proposed adjustments to the FAC deferral balance for POLR charges and environmental carrying charges for the period from April 2009 through May 2011.  In February 2012, the Ohio Consumers’ Counsel (OCC) and the Industrial Energy Users-Ohio (IEU) filed appeals with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which if ordered could total up to $698 million, excluding carrying costs.

In January 2011, the PUCO issued an order on the 2009 Significantly Excessive Earnings Test (SEET) filing and determined that 2009 earnings exceeded the PUCO determined threshold by 2.13%.  As a result, the PUCO ordered a $ 43 million refund of pretax earnings to customers, which was recorded in OPCo’s 2010 statement of income.  The PUCO ordered that the significantly excessive earnings be applied first to the FAC deferral, as of the date of the order, with any remaining balance to be credited to customers on a per kilowatt basis.  That credit began with the first billing cycle in February 2011 and continued through December 2011.  In May 2011, the IEU and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO’s SEET decision.  The OEG’s appeal seeks the inclusion of off-system sales (OSS) in the calculation of SEET, which, if ordered, could require an additional refund of $22 million based on the PUCO approved SEET calculation.  The IEU’s appeal also sought the inclusion of OSS as well as other items in the determination of SEET, but did not quantify the amount.  Management is unable to predict the outcome of the appeals.  If the Supreme Court of Ohio ultimately determines that additional amounts should be refunded, it could reduce future net income and cash flows and impact financial condition.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings, which included OSS in the SEET calculation.  In December 2011, the PUCO staff filed testimony that recommended a $23 million refund of 2010 earnings.  In the fourth quarter of 2011, OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO ordered SEET refund.

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OPCo is required to file its 2011 SEET filing with the PUCO in 2012.  Management does not currently believe that there are significantly excessive earnings in 2011.  Management is unable to predict the outcome of the unresolved litigation discussed above.  If these proceedings, including future SEET filings, result in adverse rulings, it could reduce future net income and cash flows and impact financial condition.

January 2012 – May 2016 ESP

In January 2011, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation.  The filed ESP also included alternative energy resource requirements and addressed provisions regarding distribution service, energy efficiency requirements, economic development, job retention in Ohio, generation resources and other matters.

In December 2011, a modified stipulation was approved by the PUCO which involved various issues pending before the PUCO.  Various parties, including OPCo, filed requests for rehearing with the PUCO.  In February 2012, the PUCO issued an entry on rehearing which rejected the modified stipulation and ordered a return to the 2011 ESP rates until a new rate plan is approved.  Under the February 2012 rehearing order, OPCo has 30 days to notify the PUCO whether it plans to modify or withdraw its original application as filed in January 2011.  Management is currently evaluating its options and the potential financial and operational impacts on OPCo.

2011 Ohio Distribution Base Rate Case

In February 2011, OPCo filed with the PUCO for an annual increase in distribution rates of $94 million based upon an 11.15% return on common equity to be effective January 2012.  In December 2011, a stipulation was approved by the PUCO which provided for no change in distribution rates and a new rider for a $15 million annual credit to residential ratepayers due principally to the inclusion of the rate base distribution investment in the Distribution Investment Rider (DIR).  See the “January 2012 – May 2016 ESP” section above.  The stipulation also approved recovery of certain distribution regulatory assets of $ 173 million as of December 31, 2011, excluding $154 million of unrecognized equity carrying costs.  These assets and unrecognized carrying costs will be recovered in a distribution asset recovery rider over seven years with an additional long term debt carrying charge, effective January 2012.

Due to the February 2012 PUCO ESP entry on rehearing which rejected the modified stipulation for a new ESP, collection of the DIR terminated.  OPCo has the right to withdraw from the stipulation in the distribution base rate case.  Management is currently evaluating all its options.  If OPCo is not ultimately permitted to fully recover its costs and deferrals, it would reduce future net income and cash flows and impact financial condition.

Sporn Unit 5

In October 2010, OPCo filed an application with the PUCO for the approval of a December 2010 closure of Sporn Unit 5 and the simultaneous establishment of a new non-bypassable distribution rider outside the rate caps established in the 2009 – 2011 ESP proceeding.

In the third quarter of 2011, management decided to no longer offer the output of Sporn Unit 5 into the PJM market.  Sporn Unit 5 is not expected to operate in the future, resulting in the removal of Sporn Unit 5 from the AEP Power Pool.  As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $48 million in Asset Impairments and Other Related Charges on the statement of income.  In January 2012, the PUCO issued an order which denied recovery of a new non-bypassable distribution rider and declined to exercise jurisdiction over the closure of Sporn Unit 5.

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2009 Fuel Adjustment Clause Audit

As required under the ESP orders, the PUCO selected an outside consultant to conduct the audit of the FAC for OPCo for the period of January 2009 through December 2009.  In May 2010, the outside consultant provided its confidential audit report to the PUCO.  The audit report included a recommendation that the PUCO review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo’s FAC under-recovery balance.  Of the total proceeds, approximately $ 58 million was recognized as a reduction to fuel expense prior to 2009 and $14 million was recognized as a reduction to fuel expense in 2009 and 2010, of which approximately $ 7 million was the retail jurisdictional share which reduced the FAC deferral in 2009 and 2010.

In January 2012, the PUCO ordered that the remaining $65 million in proceeds from the 2008 coal contract settlement be applied against OPCo’s under-recovered fuel balance pending a PUCO decision in OPCo's February 2012 rehearing request.  OPCo’s rehearing request stated that no additional gain should be credited to the FAC or at most only the retail share of the $58 million gain be applied to the FAC, which approximated $ 30 million.  Further, the January 2012 PUCO order stated that a consultant be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.  Management is unable to predict the outcome of the consultant’s recommendation.  If the PUCO ultimately determines that additional amounts related to the coal reserve valuation should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition.

2010 Fuel Adjustment Clause Audit

In May 2011, the PUCO-selected outside consultant issued its results of the 2010 FAC audit for OPCo.  The audit report 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.  As of December 31, 2011, the amount of OPCo’s carrying costs that could potentially be at risk is estimated to be $15 million, excluding $ 17 million of unrecognized equity carrying costs.  A decision from the PUCO is pending.  Management is unable to predict the outcome of this proceeding.  If the PUCO order results in a reduction in the carrying charges related to the FAC deferrals, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet.  This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009.  In March 2009, the PUCO approved a FAC in the ESP filing and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio.  The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record a regulatory asset for the difference between the approved market price and the rate paid by Ormet.  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.  In November 2009, OPCo requested that the PUCO approve recovery of the deferral under the interim agreement plus a weighted average cost of capital carrying charge.  The interim arrangement deferral is included in OPCo’s FAC phase-in deferral balance.  In the ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related regulatory asset and requested that the PUCO prevent OPCo from collecting the Ormet-related revenues in the future.  The PUCO did not take any action on this request in the 2009-2011 ESP proceeding.  The intervenors raised the issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement and this issue remains pending before the PUCO.  If OPCo is not ultimately permitted to fully recover its requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Economic Development Rider

In April 2010, the Industrial Energy Users-Ohio (IEU) filed a notice of appeal of the 2009 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio.  The EDR collects from ratepayers the difference between the standard tariff and lower contract billings to qualifying industrial customers, subject to PUCO approval.  In June 2011, the Supreme Court of Ohio affirmed the PUCO’s decision and dismissed the IEU’s appeal.

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In June 2010, the IEU filed a notice of appeal of the 2010 PUCO-approved EDR with the Supreme Court of Ohio raising the same issues as in the 2009 EDR appeal.  In addition, the IEU added a claim that OPCo should not be able to take the benefits of the higher ESP rates while simultaneously challenging the ESP orders.  In June 2011, the IEU voluntarily dismissed the 2010 EDR appeal issues that were the same issues dismissed by the Supreme Court of Ohio in its 2009 EDR appeal referenced above.  In August 2011, the Supreme Court of Ohio affirmed the PUCO’s decision on the remaining issues.

Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  Through December 31, 2011, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order and has incurred pre-construction costs.  Intervenors have filed motions with the PUCO requesting all collected pre-construction costs be refunded to Ohio ratepayers with interest.

Management cannot predict the outcome of any cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, such litigation would have on future net income and cash flows.  However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in service in the fourth quarter of 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.8 billion, excluding AFUDC, plus an additional $ 122 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $122 million for transmission, excluding AFUDC.  As of December 31, 2011, excluding costs attributable to its joint owners and a provision for a Texas capital costs cap, SWEPCo has capitalized approximately $1.4 billion of expenditures (including AFUDC and capitalized interest of $ 220 million and related transmission costs of $104 million).  As of December 31, 2011, the joint owners and SWEPCo have contractual construction obligations of approximately $ 125 million (including related transmission costs of $8 million).  SWEPCo’s share of the contractual construction obligations is $ 94 million.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the 88 MW SWEPCo Arkansas jurisdictional share of the Turk Plant.  Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN.  SWEPCo filed a notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates.

The PUCT issued an order approving a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $ 28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers.  SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful.  The Texas Industrial Energy Consumers filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers.  In February 2010, the Texas District Court affirmed the PUCT’s order in all respects.  In March 2010, SWEPCo and the Texas Industrial Energy Consumers appealed this decision to the Texas Court of Appeals.  In November 2011, the Texas Court of Appeals affirmed the PUCT’s order in all respects.  As a result, in the fourth quarter of 2011, SWEPCo recorded a pretax write-off of $49 million in Asset Impairments and Other Related Charges on the statement of income related to the estimated excess of the Texas jurisdictional portion of the Turk Plant above the Texas jurisdictional capital costs cap.  In December 2011, SWEPCo and the Texas Industrial Energy Consumers filed motions for rehearing at the Texas Court of Appeals which were denied in January 2012.  SWEPCo intends to seek review of the Texas Court of Appeals decision at the Supreme Court of Texas.

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Several parties, including the Hempstead County Hunting Club, the Sierra Club and the National Audubon Society had challenged the air permit, the wastewater discharge permit and the wetlands permit that were issued for the Turk Plant.  Those parties also sought a temporary restraining order and preliminary injunction to stop construction of the Turk Plant.  The motion for preliminary injunction was partially granted in 2010.  In 2011, SWEPCo entered into settlement agreements with these parties which resolved all outstanding issues related to the permits and the APSC’s grant of a CECPN.  The parties dismissed all pending permit and CECPN challenges at the APSC, other administrative agencies and the courts.

If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.

Texas Turk Plant Rate Plan

In August 2011, SWEPCo requested approval of a plan from the PUCT for including the Turk Plant investment in Texas retail rates.  SWEPCo’s application was dismissed in December 2011.  The PUCT stated that, as a matter of policy, the PUCT would not order a return on CWIP outside of a full base rate case proceeding.    SWEPCo intends to file a full base rate case in 2012 with a proposed rate increase closely aligned with the commercial operation date of the Turk Plant.

TCC Rate Matters

TEXAS RESTRUCTURING

Texas Restructuring Appeals

Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $ 2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020.  TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders.  TCC and intervenors appealed the PUCT’s true-up related orders.  After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Supreme Court of Texas.  In July 2011, the Supreme Court of Texas issued its opinion reversing the PUCT’s 2006 order denying recovery of capacity auction true-up amounts and remanding for reconsideration the treatment of certain tax balances under normalization rules.  In December 2011, the PUCT approved an unopposed stipulation allowing TCC to recover $ 800 million, including carrying charges, and retain contested tax balances in full satisfaction of its true-up proceeding.  The following actions resulted from these decisions:

·   Based upon the Supreme Court of Texas’ reversal of the PUCT’s capacity auction true-up disallowance, TCC recorded $421 million of pretax income ($ 273 million, net of tax) in Extraordinary Items, Net of Tax on the statement of income in the third quarter of 2011.

·   In 2011, TCC recorded $271 million in pretax Carrying Costs Income on the statement of income related to the debt component of carrying costs for the period from January 2002 through December 2011.  This carrying costs income represents previously unrecorded earnings associated with restructuring in Texas since 2002.  The total regulatory asset related to the capacity auction true-up as of December 31, 2011 was $692 million, excluding unrecognized equity carrying costs.  TCC plans to continue to recognize debt carrying costs income until securitization occurs and plans to recognize equity carrying costs income as collected from customers over the life of the securitization.

·   The PUCT allowed TCC to retain contested tax balances in full satisfaction of its true-up proceeding, including carrying charges.  TCC recorded the reversal of regulatory credits of $65 million ($ 42 million, net of tax) in Extraordinary Items, Net of Tax on the statement of income in the fourth quarter of 2011.  Also, in the fourth quarter of 2011, TCC recorded $52 million in pretax Carrying Costs Income on the statement of income.  TCC also recorded the reversal of $ 89 million of accumulated deferred investment tax credits ($58 million, net of tax) in Extraordinary Items, Net of Tax on the statement of income in the fourth quarter of 2011.  See the “TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes” section below.

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·   The Supreme Court of Texas reversed the Texas Court of Appeals’ decision and found that the PUCT could adjust the net book value for what it determined to be commercially unreasonable conduct.  This portion of the decision is unfavorable, but was already reflected in the financial statements.

·   The Supreme Court of Texas affirmed the PUCT’s finding that the sales price should be used to value TCC’s nuclear generation.  This portion of the decision is favorable, but this issue will have no impact on TCC’s rate recovery as this was already reflected in the financial statements.

·   The Supreme Court of Texas reversed the Texas Court of Appeals’ decision and found it was appropriate for the PUCT to take into account previously refunded excess mitigation credits to affiliate retail electricity providers.  This portion of the decision upheld the PUCT’s decision.

·   The PUCT decisions allowing recovery of construction work in progress balances and specifying the interest rate on stranded costs were upheld.  These decisions are already reflected in the financial statements and were not addressed in the remand proceeding.

The approved stipulation resolved all remaining issues in these dockets.  In December 2011, TCC filed an application with the PUCT for a financing order to recover the $800 million through the issuance of securitization bonds as permitted by Texas statutory provisions.  In January 2012, the PUCT approved the request.  TCC anticipates issuing the bonds in March 2012.

TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

In 2006, the PUCT reduced recovery of the amount securitized by $ 103 million of tax benefits including associated carrying costs related to TCC’s generation assets.  In 2006, TCC obtained a private letter ruling from the IRS which confirmed that such a reduction was an IRS normalization violation.  In 2008, the IRS issued final regulations, which supported the IRS’s private letter ruling which would make the refunding of or the reduction of the amount securitized by such tax benefits a normalization violation.  After the IRS issued its final regulations, the tax normalization issue was remanded to the PUCT for its consideration of additional evidence including the IRS regulations.  In December 2011, the PUCT approved an unopposed stipulation allowing TCC to retain contested tax balances in full satisfaction of its true-up proceeding, including carrying charges, in final resolution of this issue.  See the “Texas Restructuring Appeals” section above.

TCC Excess Earnings

In 2005, a Texas appellate court issued a decision finding that a PUCT order requiring TCC to refund to the Texas Retail Electric Providers excess earnings prior to and outside of the true-up process was unlawful under the Texas Restructuring Legislation.   From 2002 to 2005, TCC refunded $ 55 million of excess earnings, including interest, under the overturned PUCT order.  In the true-up proceeding, the PUCT adjusted stranded costs for TCC’s payment of excess earnings under the PUCT order.  However, the PUCT did not properly recognize TCC’s payment of interest under the prior order, causing TCC to refund interest twice.  The Supreme Court of Texas approved the PUCT treatment of these matters in the true-up case, noting that TCC could pursue its additional interest claim in further proceedings related to the excess earnings order.  TCC agreed to dismiss its claims as part of the stipulation approved by the PUCT in the true-up proceeding.  See the “Texas Restructuring Appeals” section above.  The dismissal did not have any impact on TCC’s rate recovery as this was already reflected in the financial statements.

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APCo and WPCo Rate Matters

2011 Virginia Biennial Base Rate Case

In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity.  The return on common equity included a requested 0.5% renewable portfolio standards (RPS) incentive as allowed by law.

In November 2011, the Virginia SCC issued an order which approved a $ 55 million increase in generation and distribution base rates, effective February 2012, and a 10.9% return on common equity, which included a 0.5% RPS incentive.   The $55 million increase included $ 39 million related to an increase in depreciation rates.

Rate Adjustment Clauses

In 2007, the Virginia law governing the regulation of electric utility service was amended to, among other items, provide for rate adjustment clauses (RACs) beginning in January 2009 for the timely and current recovery of costs of: (a) transmission services billed by an RTO, (b) demand side management and energy efficiency programs, (c) renewable energy programs, (d) environmental compliance projects and (e) new generation facilities, including major unit modifications.  In accordance with Virginia law, APCo is deferring incremental environmental costs incurred after December 2008 and renewable energy costs incurred after December 2007 which are not being recovered in current revenues.  As of December 31, 2011, APCo has deferred $24 million of environmental costs, excluding $ 6 million of unrecognized equity carrying costs, incurred from January 2009 through December 2010, $18 million of environmental costs, excluding $ 4 million of unrecognized equity carrying costs, incurred in 2011 and $44 million of renewable energy costs.

In March 2011, APCo filed for approval of an environmental RAC, a renewable energy program RAC and a generation RAC.  The environmental RAC requested recovery of $ 77 million of incremental environmental compliance costs incurred from January 2009 through December 2010.  The renewable energy program RAC requested recovery of $6 million for the incremental portion of deferred wind power costs for the Camp Grove and Fowler Ridge projects through December 2010.  The generation RAC requested recovery of the Dresden Plant, which was placed into service in January 2012.  With Virginia SCC approval, APCo purchased the Dresden Plant from AEGCo in August 2011 for $302 million. 

In August 2011, a stipulation was filed with the Virginia SCC related to the generation RAC.  The stipulation requested recovery of the Dresden Plant costs totaling up to $27 million annually, effective March 2012.  In January 2012, the Virginia SCC issued an order which modified and approved the stipulation to allow APCo to recover $ 26 million annually, effective March 2012.

In November 2011, the Virginia SCC issued an order which approved recovery of $6 million for the incremental portion of deferred wind power costs for the Camp Grove and Fowler Ridge projects, effective February 2012.  In addition, the order found that APCo can recover the non-incremental deferred wind power costs of $ 27 million as of December 31, 2011 through the FAC.

Also in November 2011, the Virginia SCC issued an order which approved environmental RAC recovery of $30 million to be collected over one year beginning in February 2012.  The Virginia SCC denied recovery of certain environmental costs.  As a result, in the fourth quarter of 2011, APCo recorded a pretax write-off of $ 31 million on the statement of income related to environmental compliance costs incurred from January 2009 through December 2010.  In December 2011, APCo filed a notice of appeal with the Supreme Court of Virginia regarding the Virginia SCC’s environmental RAC decision.  If the Virginia SCC were to disallow a portion of APCo’s deferred environmental compliance costs incurred since January 2011, it would reduce future net income and cash flows.

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2010 West Virginia Base Rate Case

In May 2010, APCo and WPCo filed a request with the WVPSC to increase annual base rates by $ 156 million based upon an 11.75% return on common equity.  In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $ 51 million based upon a 10% return on common equity, effective April 2011.  The settlement agreement also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in March 2011.  See “Mountaineer Carbon Capture and Storage Project” section below.  In addition, the WVPSC allowed APCo to defer and amortize $ 18 million of previously expensed 2009 incremental storm expenses and allowed APCo and WPCo to defer and amortize $15 million of previously expensed costs related to the 2010 cost reduction initiatives, each over a period of seven years.

Mountaineer Carbon Capture and Storage Project

Product Validation Facility (PVF)

APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009.  APCo also constructed and owns the necessary facilities to store the CO2.  In October 2009, APCo started injecting CO2 into the underground storage facilities.  The injection of CO2 required the recording of an asset retirement obligation and an offsetting regulatory asset.  In May 2011, the PVF ended operations.

In APCo’s and WPCo’s May 2010 West Virginia base rate filing, APCo and WPCo requested rate base treatment of the PVF, including recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In March 2011, a WVPSC order denied the request for rate base treatment of the PVF largely due to its experimental operation.  The base rate order provided that should APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the PVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base.  See “2010 West Virginia Base Rate Case” section above.  In 2011, APCo recorded a net pretax write-off of $14 million in Other Operation expense on the statement of income related to the write-off of a portion of the West Virginia jurisdictional share of the PVF offset by an asset retirement obligation adjustment.  As of December 31, 2011, APCo has recorded $14 million in Regulatory Assets on the balance sheet related to the PVF.  If APCo cannot recover its remaining PVF investment and related accretion expenses, it would reduce future net income and cash flows.

Carbon Capture and Sequestration Project with the Department of Energy (DOE) (Commercial Scale Project)

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility at the Mountaineer Plant.  The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million.  A Front-End Engineering and Design (FEED) study was completed during the third quarter of 2011.  Management postponed any further CCS project activities because of the uncertainty about the regulation of CO2.  In June 2011, the FEED study costs were allocated among the AEP East companies, PSO and SWEPCo based on eligible plants that could potentially benefit from the carbon capture.  As of December 31, 2011, APCo has incurred $34 million in total project costs and has received $ 20 million of DOE and other eligible funding resulting in $14 million of net costs, of which $ 8 million was written off.  The remaining $6 million in net costs are recorded in Regulatory Assets on the balance sheet.  If the costs of the CCS project cannot be recovered, it would reduce future net income and cash flows.

APCo’s Filings for an IGCC Plant

Through December 31, 2011, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $ 2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction.  APCo will not start construction of the IGCC plant until sufficient assurance of full cost recovery exists in Virginia and West Virginia.  If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs.  If the costs are not recoverable, it would reduce future net income and cash flows and impact financial condition.

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APCo’s and WPCo’s Expanded Net Energy Charge (ENEC) Filing

In September 2009, the WVPSC issued an order approving APCo’s and WPCo’s March 2009 ENEC request.  The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $355 million and a first-year increase of $124 million, effective October 2009.

In June 2010, the WVPSC approved a settlement agreement for $ 96 million, including $10 million of construction surcharges related to APCo’s and WPCo’s second year ENEC increase.  The settlement agreement allows APCo to accrue a weighted average cost of a capital carrying charge on the excess under-recovery balance due to the ENEC phase-in as adjusted for the impacts of accumulated deferred income taxes.  The new rates became effective in July 2010.

In June 2011, the WVPSC issued an order approving a $ 98 million annual increase including $8 million of construction surcharges and $ 8 million of carrying charges related to APCo’s and WPCo’s third year ENEC increase.  The order also allows APCo to accrue a fixed annual carrying cost rate of 4%.  The new rates became effective in July 2011.  Additionally, the order approved APCo’s request to purchase the Dresden Plant from AEGCo and approved deferral of post in-service Dresden Plant costs, including a return, for future recovery.  APCo purchased the Dresden Plant from AEGCo in August 2011 for $302 million.  As of December 31, 2011, APCo’s ENEC under-recovery balance of $ 359 million was recorded in Regulatory Assets on the balance sheet, excluding $7 million of unrecognized equity carrying costs.  If the WVPSC were to disallow a portion of APCo’s and WPCo’s deferred ENEC costs, it could reduce future net income and cash flows and impact financial condition.

PSO Rate Matters

PSO 2008 Fuel and Purchased Power

In July 2009, the OCC initiated a proceeding to review PSO’s fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudence review of the related costs.  In March 2010, the Oklahoma Attorney General and the Oklahoma Industrial Energy Consumers (OIEC) recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of off-system sales margins decrease from 25% to 10%.  The OIEC also recommended that the OCC conduct a comprehensive review of all affiliate fuel transactions during 2007 and 2008.  In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEPEP was filed.  The testimony included unquantified refund recommendations relating to re-pricing of those ERCOT trading contracts.  Hearings were held in June 2011.  If the OCC were to issue an unfavorable decision, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

Michigan 2009 and 2010 Power Supply Cost Recovery (PSCR) Reconciliation (Cook Plant Unit 1 Fire and Shutdown)

In March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC.  The filing included an adjustment to exclude from the PSCR the incremental fuel cost of replacement power due to the Cook Plant Unit 1 (Unit 1) outage from mid-December 2008 through December 2009, the period during which I&M received and recognized accidental outage insurance proceeds.  In October 2010, a settlement agreement was filed with the MPSC which included deferring the Unit 1 outage issue to the 2010 PSCR reconciliation.  In November 2011, the MPSC approved a settlement agreement for the 2010 PSCR reconciliation which resolved the Unit 1 outage issue by ordering no disallowances associated with the Unit 1 outage issue.  See the “Cook Plant Unit 1 Fire and Shutdown” section of Note 5.

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2011 Michigan Base Rate Case

In July 2011, I&M filed a request with the MPSC for an annual increase in Michigan base rates of $25 million and a return on common equity of 11.15%.  The request included an increase in depreciation rates that would result in a $6 million increase in annual depreciation expense.  An interim rate increase of $ 16 million annually was implemented in January 2012, subject to refund.

In February 2012, the MPSC approved a settlement agreement which increased annual base rates by approximately $15 million, effective April 2012, based upon a return on common equity of 10.2% and included a $5 million annual increase in depreciation rates.  The approved settlement agreement also excluded the Michigan jurisdictional share of the net costs of the Cook Plant Unit 1 (Unit 1) turbine replacement from rate base but provided for a return on and of the net cost as a regulatory asset, effective February 2012.  As of December 31, 2011, the Michigan jurisdictional share of the net costs of the Unit 1 turbine replacement was $9 million.  Future rate recovery of the regulatory asset will be reviewed in a future rate proceeding.

2011 Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on common equity of 11.15%.  The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund

In 2004, AEP eliminated transaction-based through-and-out transmission service charges and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA through March 2006.  Intervenors objected and the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund.  The AEP East companies recognized gross SECA revenues of $ 220 million.  In 2006, a FERC Administrative Law Judge issued an initial decision finding that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.

AEP filed briefs jointly with other affected companies asking the FERC to reverse the decision.  In May 2010, the FERC issued an order that generally supported AEP’s position and required a compliance filing to be filed with the FERC by August 2010.  In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC.  If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $ 5 million.  The AEP East companies could also potentially receive payments up to approximately $10 million including estimated interest of $ 3 million.  A decision is pending from the FERC.

The FERC has approved settlements applicable to $112 million of SECA revenue.  The AEP East companies provided reserves for net refunds for SECA settlements applicable to the remaining $ 108 million of SECA revenues collected.  Based on the analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the compliance filing be made final.  Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.

Possible Termination of the Interconnection Agreement

In December 2010, each of the AEP Power Pool members gave notice to AEPSC and each other of their decision to terminate the Interconnection Agreement effective January 2014 or such other date approved by FERC, subject to state regulatory input.  In February 2012, an application was filed with the FERC proposing to establish a new power cost sharing agreement between APCo, I&M and KPCo.  If any of the AEP Power Pool members experience decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.  As a result of the February 2012 ESP rehearing order, management is in the process of withdrawing the PUCO and FERC applications.  See “January 2012 – May 2016 ESP” section of the OPCo rate matters.

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PJM/MISO Market Flow Calculation Settlement Adjustments

During 2009, an analysis conducted by MISO and PJM discovered several instances of unaccounted for power flows on numerous coordinated flowgates.  These flows affected the settlement data for congestion revenues and expenses and dated back to the start of the MISO market in 2005.  In January 2011, PJM and MISO reached a settlement agreement where the parties agreed to net various issues to zero.  In June 2011, the FERC approved the settlement agreement.

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4.  EFFECTS OF REGULATION

Regulatory assets are comprised of the following items:

			December 31,				Remaining
			2011		2010		Recovery Period
Current Regulatory Assets			(in millions)
Under-recovered Fuel Costs - earns a return			$	56	$	73	1 year
Under-recovered Fuel Costs - does not earn a return				9		8	1 year
Total Current Regulatory Assets			$	65	$	81
Noncurrent Regulatory Assets
Regulatory assets not yet being recovered pending future
	proceedings to determine the recovery method and timing:
	Regulatory Assets Currently Earning a Return
		Storm Related Costs	$	24	$	55
		Economic Development Rider		13		6
		Customer Choice Deferrals		-		59
		Line Extension Carrying Costs		-		55
		Acquisition of Monongahela Power		-		8
		Other Regulatory Assets Not Yet Being Recovered		-		1
	Regulatory Assets Currently Not Earning a Return
		Deferred Wind Power Costs		38		29
		Environmental Rate Adjustment Clause		18		56
		Mountaineer Carbon Capture and Storage Product Validation Facility		14		60
		Special Rate Mechanism for Century Aluminum		13		13
		Litigation Settlement		11		-
		Storm Related Costs		10		45
		Acquisition of Monongahela Power		-		4
		Other Regulatory Assets Not Yet Being Recovered		14		4
Total Regulatory Assets Not Yet Being Recovered				155		395
Regulatory assets being recovered:
	Regulatory Assets Currently Earning a Return
		Capacity Auction True-Up		692		-	13 years
		Fuel Adjustment Clause		521		476	7 years
		Expanded Net Energy Charge		327		361	2 years
		Distribution Asset Recovery Rider		173		-	7 years
		Unamortized Loss on Reacquired Debt		92		93	32 years
		Storm Related Costs		65		38	7 years
		Meter Replacement Costs		39		4	29 years
		Transmission Cost Recovery Rider		28		-	2 years
		RTO Formation/Integration Costs		18		21	8 years
		Economic Development Rider		12		1	1 year
		Red Rock Generating Facility		10		10	45 years
		Other Regulatory Assets Being Recovered		15		17	various
	Regulatory Assets Currently Not Earning a Return
		Pension and OPEB Funded Status		2,308		2,161	13 years
		Income Taxes, Net		1,237		1,097	37 years
		Postemployment Benefits		47		51	4 years
		Cook Nuclear Plant Refueling Outage Levelization		41		54	2 years
		Storm Related Costs		35		21	7 years
		Expanded Net Energy Charge		32		-	6 years
		Environmental Rate Adjustment Clause		24		-	2 years
		Deferred PJM Fees		22		7	1 year
		Transmission Rate Adjustment Clause		20		19	2 years
		Deferred Restructuring Costs		18		6	7 years
		Unrealized Loss on Forward Commitments		16		10	2 years
		Asset Retirement Obligation		14		15	9 years
		Vegetation Management		11		13	1 year
		Restructuring Transition Costs		8		14	5 years
		Off-system Sales Margin Sharing		-		13
		Other Regulatory Assets Being Recovered		46		46	various
Total Regulatory Assets Being Recovered				5,871		4,548
Total Noncurrent Regulatory Assets			$	6,026	$	4,943

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Regulatory liabilities are comprised of the following items:

				December 31,				Remaining
				2011		2010		Refund Period
Current Regulatory Liabilities				(in millions)
Over-recovered Fuel Costs - pays a return				$	5	$	16	1 year
Over-recovered Fuel Costs - does not pay a return					3		1	1 year
Total Current Regulatory Liabilities				$	8	$	17
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits
Regulatory liabilities not yet being paid:
	Regulatory Liabilities Currently Paying a Return
		Refundable Construction Financing Costs		$	53	$	20
		Other Regulatory Liabilities Not Yet Being Paid			5		-
	Regulatory Liabilities Currently Not Paying a Return
		Over-recovery of Costs Related to gridSMART®			4		10
		Other Regulatory Liabilities Not Yet Being Paid			4		11
Total Regulatory Liabilities Not Yet Being Paid					66		41
Regulatory liabilities being paid:
	Regulatory Liabilities Currently Paying a Return
		Asset Removal Costs			2,270		2,222	(a)
		Advanced Metering Infrastructure Surcharge			78		61	9 years
		Deferred Investment Tax Credits			27		32	11 years
		Excess Earnings			13		13	42 years
		Other Regulatory Liabilities Being Paid			4		4	various
	Regulatory Liabilities Currently Not Paying a Return
		Excess Asset Retirement Obligations for Nuclear Decommissioning
			Liability		377		354	(b)
		Deferred Investment Tax Credits			144		242	75 years
		Spent Nuclear Fuel Liability			43		42	(b)
		Unrealized Gain on Forward Commitments			41		60	5 years
		Over-recovery of Transition Charges			41		38	10 years
		Energy Efficiency/Peak Demand Reduction			40		10	1 year
		Deferred State Income Tax Coal Credits			29		29	10 years
		Over-recovery of PJM Expenses			-		12
		Other Regulatory Liabilities Being Paid			22		11	various
Total Regulatory Liabilities Being Paid					3,129		3,130
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax
	Credits			$	3,195	$	3,171
(a)			Relieved as removal costs are incurred.
(b)			Relieved when plant is decommissioned.

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5.  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 adverse 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.  We forecast approximately $3.1 billion of construction expenditures, excluding equity AFUDC and capitalized interest, for 2012.  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 at December 31, 2011:

		Less Than 1						After
Contractual Commitments		year		2-3 years		4-5 years		5 years		Total
		(in millions)
Fuel Purchase Contracts (a)		$	2,867	$	3,918	$	2,574	$	3,108	$	12,467
Energy and Capacity Purchase Contracts (b)			104		213		217		1,066		1,600
Construction Contracts for Capital Assets (c)			60		-		-		-		60
Total		$	3,031	$	4,131	$	2,791	$	4,174	$	14,127
(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 contractual commitments for energy and capacity purchase contracts.
(c)	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 gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

We have credit facilities totaling $3.25 billion, under which we may issue up to $1.35 billion as letters of credit.  In July 2011, we replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015.  As of December 31, 2011, the maximum future payments for letters of credit issued under the two credit facilities were $134 million with maturities ranging from January 2012 to October 2012.

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In March 2011, we terminated a $478 million credit agreement that was scheduled to mature in April 2011 and was used to support $472 million of variable rate Pollution Control Bonds.  In March 2011, we remarketed $357 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $361 million.  The letters of credit have maturities ranging from March 2013 to March 2014.  The remaining $115 million of Pollution Control Bonds were reacquired and are held by trustees.

In July 2011, we remarketed $45 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $46 million.  The letters of credit mature in July 2014.

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.  In July 2011, SWEPCo’s guarantee was increased from $65 million to $100 million due to expansion of the mining area.  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, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  As of December 31, 2011, SWEPCo has collected approximately $54 million through a rider for final mine closure and reclamation costs, of which $2 million is recorded in Other Current Liabilities, $22 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $ 30 million is recorded in Asset Retirement Obligations on our balance sheets.

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.  The status of certain sale agreements is discussed in the “Dispositions” section of Note 6.  As of December 31, 2011, 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 12 for disclosure of lease residual value guarantees.

ENVIRONMENTAL CONTINGENCIES

Carbon Dioxide Public Nuisance Claims

In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority.  The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants.  The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming and sought injunctive relief in the form of specific emission reduction commitments from the defendants.  The trial court dismissed the lawsuits.

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In September 2009, the Second Circuit Court of Appeals issued a ruling on appeal remanding the cases to the Federal District Court for the Southern District of New York.  The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate CO2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s administration to secure the relief sought in their complaints.  In 2010, the U.S. Supreme Court granted the defendants’ petition for review.  In June 2011, the U.S. Supreme Court reversed and remanded the case to the Court of Appeals, finding that plaintiffs’ federal common law claims are displaced by the regulatory authority granted to the Federal EPA under the CAA.  After the remand, the plaintiffs asked the Second Circuit to return the case to the district court so that they could withdraw their complaints.  The cases were returned to the district court and the plaintiffs’ federal common law claims were dismissed in December 2011.

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing.  An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place.  Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision.  The petition was denied in January 2011.  Plaintiffs refiled their complaint in federal district court.  The court ordered all defendants to respond to the refiled complaints in October 2011.  We believe the claims are without merit, and in addition to other defenses, are barred by the doctrine of collateral estoppel and the applicable statute of limitations.  We intend to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Alaskan Villages’ Claims

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  The plaintiffs appealed the decision.  The defendants requested that the court defer setting this case for oral argument until after the Supreme Court issues its decision in the CO2 public nuisance case discussed above.  The court accepted supplemental briefing on the impact of the Supreme Court’s decision and heard oral argument in November 2011.  We believe the action is without merit and intend to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

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 generating 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.  At December 31, 2011, 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 four 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.  I&M’s provision is approximately $10 million.  As the remediation work is completed, I&M’s cost may continue to increase as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ.  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 site discussed above.

Amos Plant – State and Federal Enforcement Proceedings

In March 2010, we received a letter from the West Virginia Department of Environmental Protection, Division of Air Quality (DAQ), alleging that at various times in 2007 through 2009 the units at Amos Plant reported periods of excess opacity (indicator of compliance with PM emission limits) that lasted for more than 30 consecutive minutes in a 24-hour period and that certain required notifications were not made.  We met with representatives of DAQ to discuss these occurrences and the steps we have taken to prevent a recurrence.  DAQ indicated that additional enforcement action may be taken, including imposition of a civil penalty of approximately $240 thousand.  We have denied that violations of the reporting requirements occurred and maintain that the proper reporting was done.  In March 2011, we resolved these issues through the entry of a consent order that included the payment of a $75 thousand civil penalty and certain improvements in our opacity reports.

In March 2010, we received a request to show cause from the Federal EPA alleging that certain reporting requirements under Superfund and the Emergency Planning and Community Right-to-Know Act had been violated and inviting us to engage in settlement negotiations.  The request includes a proposed civil penalty of approximately $300 thousand.  We provided additional information to representatives of the Federal EPA.  Based on the information we submitted, the Federal EPA determined that it will not further pursue enforcement for several alleged violations and we agreed to resolve the remaining allegations through a consent order that includes payment of a $36 thousand civil penalty.

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.

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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 2009.  According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste ranges from $831 million to $1.5 billion in 2009 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 amount recovered in rates was $14 million in 2011, $14 million in 2010 and $16 million in 2009.  Reduced annual decommissioning cost recovery amounts reflect the units’ longer estimated life and operating licenses granted by the NRC.  Decommissioning costs recovered from customers are deposited in external trusts.

At December 31, 2011 and 2010, the total decommissioning trust fund balance was $1.3 billion and $1.2 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.

I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant.  However, future net income, cash flows and possibly financial condition would be adversely affected 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 is being collected from customers and remitted to the U.S. Treasury.  At December 31, 2011 and 2010, fees and related interest of $265 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 $308 million and $307 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 $14 million to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2013.  The proceeds reduced capital costs for dry cask storage.

See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 10 for disclosure of the fair value of assets within the trusts.

Nuclear Incident Liability

I&M carries insurance coverage for property damage, decommissioning and decontamination at the Cook Plant in the amount of $1.8 billion.   I&M purchases $ 1 billion of excess coverage for property damage, decommissioning and decontamination.  Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage.  I&M utilizes an industry mutual insurer for the placement of this insurance coverage.  Participation in this mutual insurance requires a contingent financial obligation of up to $41 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 $12.6 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 $117.5 million on each licensed reactor in the U.S. payable in annual installments of $17.5 million.  As a result, I&M could be assessed $235 million per nuclear incident payable in annual installments of $35 million.  The number of incidents for which payments could be required is not limited.

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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 $12.2 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, net income, cash flows and financial condition could be adversely affected.

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator.  This equipment, located in the turbine building, is separate and isolated from the nuclear reactor.  The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period.  The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship.  Repair of the property damage and replacement of the turbine rotors and other equipment cost approximately $400 million.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  Due to the extensive lead time required to manufacture and install new turbine rotors, I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The installation of the new turbine rotors and other equipment occurred as planned during the fall 2011 refueling outage of Unit 1.

I&M maintains insurance through NEIL.  As of December 31, 2011, we recorded $64 million in Prepayments and Other Current Assets on our balance sheets representing amounts due from NEIL under the insurance policies.  Through December 31, 2011, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage.

I&M also maintains a separate accidental outage policy with NEIL.  In 2009, I&M recorded $185 million in revenue under the policy and reduced the cost of replacement power in customers’ bills by $78 million.

NEIL is reviewing claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies.  The review by NEIL includes the timing of the unit’s return to service and whether the return should have occurred earlier reducing the amount received under the accidental outage policy.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

We maintain insurance coverage normal and customary for an integrated electric utility, subject to various deductibles.  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 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 have a material adverse effect on our net income, cash flows and financial condition.

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Fort Wayne Lease

Since 1975, I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expired on February 28, 2010.  I&M negotiated with Fort Wayne to purchase the assets at the end of the lease and reached an agreement (subject to IURC approval) in 2010.  The agreement required I&M to purchase the remaining leased property and settled claims Fort Wayne asserted.  The agreement provided that I&M pay Fort Wayne a total of $39 million, including interest, over 15 years and Fort Wayne recognized that I&M is the exclusive electricity supplier in the Fort Wayne area.   In August 2011, the IURC approved a settlement agreement with the Indiana Office of Utility Consumer Counselor.  The transaction is final.

Enron Bankruptcy

In 2001, we purchased Houston Pipeline Company (HPL) from Enron.  Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.  In connection with our acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 55 billion cubic feet (BCF) of cushion gas required for the normal operation of the Bammel gas storage facility.  At the time of our acquisition of HPL, BOA and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of the cushion gas.  Also at the time of our acquisition, Enron and the BOA Syndicate released HPL from all prior and future liabilities and obligations in connection with the financing arrangement.  After the Enron bankruptcy, the BOA Syndicate informed HPL of a purported default by Enron under the terms of the financing arrangement.  This dispute was litigated in the Enron bankruptcy proceedings and in federal courts in Texas and New York.

In 2007, the judge in the New York action issued a decision on all claims, including those that were pending trial in Texas, granting BOA summary judgment and dismissing our claims.  In August 2008, the New York court entered a final judgment of $346 million.  In May 2009, the judge awarded $20 million of attorneys’ fees to BOA.  We appealed these awards.  In October 2010, the Court of Appeals affirmed the New York district court’s decision as to the final judgment of $346 million plus interest and reversed the New York district court decision as to the judgment dismissing our claims against BOA in the Southern District of Texas.

In 2005, we sold our interest in HPL for approximately $1 billion.  Although the assets were legally transferred, we were unable to determine all costs associated with the transfer until the BOA litigation was resolved.  We indemnified the buyer of HPL against any damages up to the purchase price resulting from the BOA litigation, including the right to use the 55 BCF of natural gas through 2031.  As a result, we deferred the entire gain related to the sale of HPL (approximately $380 million) pending resolution of the Enron and BOA disputes.

The deferred gain related to the sale of HPL, plus accrued interest and attorneys’ fees related to the New York court’s judgment, was $448 million at December 31, 2010 and was included in Current Liabilities – Deferred Gain and Accrued Litigation Costs on the balance sheet.

In February 2011, we reached a settlement covering all claims with BOA and Enron for $425 million.  As part of the settlement, we received title to the 55 BCF of natural gas in the Bammel storage facility and recorded this asset at fair value.  Under the HPL sales agreement, we have a service obligation to the buyer for the right to use the cushion gas through May 2031.  We recognized the obligation as a liability and will amortize it over the life of the agreement.

The settlement resulted in a pretax gain of $51 million and a net loss after tax of $22 million primarily due to an unrealized capital loss valuation allowance of $ 56 million.

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At the time of the settlement, the following table sets forth its impact on our 2011 financial statements:

Statement of Income:	(in millions)
Other Operation Expense - Pretax Gain on Settlement	$	51
Income Tax Expense		73
Net Loss After Tax	$	(22	)
Cash Flow Statement:
Net Income - Loss on Settlement with BOA and Enron	$	(22	)
Deferred Income Taxes		91
Gain on Settlement with BOA and Enron		(51	)
Settlement of Litigation with BOA and Enron		(211	)
Accrued Taxes, Net		(18	)
Acquisition of Cushion Gas from BOA		(214	)
Cash Paid	$	(425	)
Balance Sheet:
Deferred Charges and Other Noncurrent Assets - Gas Acquired	$	214
Deferred Credits and Other Noncurrent Liabilities - Gas Service Liability		187
Accrued Taxes - Tax Benefit on Settlement with BOA and Enron		18
Deferred Income Taxes - Deferred Tax Benefit on Gas Service Liability		66

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.  In 2008, we settled all of the cases pending against us in California.  In July 2011, the judge in the Federal District Court in Las Vegas granted summary judgment dismissing the cases where AEP companies were defendants.  Also in July 2011, the plaintiffs in these cases filed notices of appeal to the Ninth Circuit Court of Appeals.  We will continue to defend the remaining cases where an AEP company is a defendant, all of which were dismissed by the Federal District Court in Las Vegas and are currently on appeal.  We believe the provision we have for the remaining cases is adequate and the remaining exposure is immaterial.

6.  ACQUISITIONS, DISPOSITIONS AND IMPAIRMENTS

ACQUISITIONS

Acquisition Anticipated Being Completed During the First Quarter of 2012

BlueStar Energy (Generation and Marketing segment)

In January 2012, we entered into an agreement to acquire BlueStar Energy Holdings, Inc. (BlueStar) and its independent retail electric supplier BlueStar Energy Solutions for approximately $70 million.  BlueStar provides electric supply for retail customers in Ohio, Illinois and other deregulated electricity markets and also provides energy solutions, including demand response and energy efficiency services, nationwide.  BlueStar has approximately 21,000 customer accounts.  Consummation of the transaction is subject to regulatory and other approvals.  The transaction is expected to close in the first quarter of 2012.

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2010

Valley Electric Membership Corporation (Utility Operations segment)

In October 2010, SWEPCo purchased certain transmission and distribution assets of Valley Electric Membership Corporation (VEMCO) for approximately $102 million and began serving VEMCO’s 30,000 customers in Louisiana.

2009

Oxbow Lignite Company and Red River Mining Company (Utility Operations segment)

In December 2009, SWEPCopurchased 50% of the Oxbow Lignite Company, LLC (OLC) membership interest for $13 million.  CLECO acquired the remaining 50% membership interest in the OLC for $13 million.  The Oxbow Mine is located near Coushatta, Louisiana and is used as one of the fuel sources for SWEPCo’s and CLECO’s jointly-owned Dolet Hills Generating Station.  SWEPCo accounts for OLC as an equity investment.  Also, in  December 2009, DHLC purchased mining equipment and assets for $16 million from the Red River Mining Company.

DISPOSITIONS

2010

Electric Transmission Texas LLC (ETT) (Utility Operations segment)

In 2010, TCC and TNC sold $66 million and $73 million, respectively, of transmission facilities to ETT.  There were no gains or losses recorded on these sale transactions.

Intercontinental Exchange, Inc. (ICE) (All Other)

In April 2010, we sold our remaining 138,000 shares of ICE and recognized a $16 million gain.  We recorded the gain in Interest and Investment Income on our statements of income for the year ended December 31, 2010.

2009

Electric Transmission Texas LLC (ETT) (Utility Operations segment)

In 2009, TCC and TNC sold $93 million and $2 million, respectively, of transmission facilities to ETT.  There were no gains or losses recorded on these sale transactions.

IMPAIRMENTS

2011

Turk Plant (Utility Operations segment)

In the fourth quarter of 2011, SWEPCo recorded a pretax write-off of $49 million in Asset Impairments and Other Related Charges on the statements of income related to the Texas jurisdictional portion of the Turk Plant as a result of the November 2011 Texas Court of Appeals decision upholding the Texas capital cost cap.

Muskingum River Plant Unit 5 FGD Project (MR5) (Utility Operations segment)

In September 2011, subsequent to the stipulation agreement filed with the PUCO, management determined that OPCo was not likely to complete the previously suspended MR5 project and that the project’s preliminary engineering costs were no longer probable of being recovered.  As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $42 million in Asset Impairments and Other Related Charges on the statements of income.

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Sporn Plant Unit 5 (Utility Operations segment)

In the third quarter of 2011, management decided to no longer offer the output of Sporn Unit 5 into the PJM market.  Sporn Unit 5 is not expected to operate in the future, resulting in the removal of Sporn Unit 5 from the AEP Power Pool.  As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $48 million in Asset Impairments and Other Related Charges on the statements of income.

7.  BENEFIT PLANS

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “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 medical 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:

							Other Postretirement
	Pension Plans						Benefit Plans
Assumptions	2011			2010			2011		2010
Discount Rate	4.55	%		5.05	%		4.75	%	5.25	%
Rate of Compensation Increase	4.85	%	(a)	4.95	%	(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 similar to those included in the Moody’s Aa bond index is constructed with a duration matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.

For 2011, the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 11.5% per year, with an average increase of 4.85%.

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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:

							Other Postretirement
	Pension Plans						Benefit Plans
	2011		2010		2009		2011		2010		2009
Discount Rate	5.05	%	5.60	%	6.00	%	5.25	%	5.85	%	6.10	%
Expected Return on Plan Assets	7.75	%	8.00	%	8.00	%	7.50	%	8.00	%	7.75	%
Rate of Compensation Increase	4.85	%	4.60	%	5.90	%	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	2011		2010
Initial	7.50	%	8.00	%
Ultimate	5.00	%	5.00	%
Year Ultimate Reached	2016		2016

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	$	23	$	(18)
Effect on the Health Care Component of the
	Accumulated Postretirement Benefit Obligation		274		(223)

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.  At December 31, 2011, 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.

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Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2011 and 2010

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.

							Other Postretirement
	Pension Plans						Benefit Plans
	2011			2010			2011			2010
Change in Benefit Obligation	(in millions)
Benefit Obligation at January 1	$	4,807		$	4,701		$	2,125		$	1,941
Service Cost		72			111			42			47
Interest Cost		237			253			109			113
Actuarial Loss		169			222			253			164
Plan Amendment Prior Service Credit		-			-			(196	)		(36	)
Curtailment		-			-			1			-
Benefit Payments		(294	)		(480	)		(150	)		(142	)
Participant Contributions		-			-			34			29
Medicare Subsidy		-			-			9			9
Benefit Obligation at December 31	$	4,991		$	4,807		$	2,227		$	2,125
Change in Fair Value of Plan Assets
Fair Value of Plan Assets at January 1	$	3,858		$	3,403		$	1,461		$	1,308
Actual Gain (Loss) on Plan Assets		282			420			(14	)		149
Company Contributions		457			515			79			117
Participant Contributions		-			-			34			29
Benefit Payments		(294	)		(480	)		(150	)		(142	)
Fair Value of Plan Assets at December 31	$	4,303		$	3,858		$	1,410		$	1,461
Underfunded Status at December 31	$	(688	)	$	(949	)	$	(817	)	$	(664	)

Benefit Amounts Recognized on the Balance Sheets as of December 31, 2011 and 2010
									Other Postretirement
	Pension Plans								Benefit Plans
	December 31,
	2011				2010				2011				2010
	(in millions)
Other Current Liabilities - Accrued Short-term
Benefit Liability		$	(8	)		$	(8	)		$	(4	)		$	(4	)
Employee Benefits and Pension Obligations -
Accrued Long-term Benefit Liability			(680	)			(941	)			(813	)			(660	)
Underfunded Status		$	(688	)		$	(949	)		$	(817	)		$	(664	)

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Amounts Included in AOCI and Regulatory Assets as of December 31, 2011 and 2010
							Other Postretirement
	Pension Plans						Benefit Plans
	December 31,
	2011			2010			2011				2010
Components	(in millions)
Net Actuarial Loss		$	2,208		$	2,129		$	979			$	638
Prior Service Cost (Credit)			10			11			(210	)			(20	)
Transition Obligation			-			-			1				3
Recorded as
Regulatory Assets		$	1,818		$	1,764		$	479			$	388
Deferred Income Taxes			140			132			102				81
Net of Tax AOCI			260			244			189				152

Components of the change in amounts included in AOCI and Regulatory Assets during the years ended December 31, 2011 and 2010 are as follows:

									Other Postretirement
	Pension Plans								Benefit Plans
	Years Ended December 31,
	2011				2010				2011				2010
Components	(in millions)
Actuarial Loss During the Year		$	201			$	121			$	370			$	121
Prior Service Credit			-				-				(191	)			(36	)
Amortization of Actuarial Loss			(122	)			(89	)			(29	)			(29	)
Amortization of Prior Service Credit (Cost)			(1	)			-				1				-
Amortization of Transition Obligation			-				-				(2	)			(27	)
Change for the Year		$	78			$	32			$	149			$	29

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Pension and Other Postretirement Plans’ Assets

The following table presents the classification of pension plan assets within the fair value hierarchy at December 31, 2011:

													Year End
Asset Class	Level 1		Level 2		Level 3		Other			Total			Allocation
	(in millions)
Equities:
Domestic	$	1,455	$	-	$	-	$	-		$	1,455			33.8	%
International		399		-		-		-			399			9.3	%
Real Estate Investment Trusts		104		-		-		-			104			2.4	%
Common Collective Trust -
International		-		128		-		-			128			3.0	%
Subtotal - Equities		1,958		128		-		-			2,086			48.5	%
Fixed Income:
Common Collective Trust - Debt		-		26		-		-			26			0.6	%
United States Government and
Agency Securities		-		566		-		-			566			13.2	%
Corporate Debt		-		985		6		-			991			23.0	%
Foreign Debt		-		190		-		-			190			4.4	%
State and Local Government		-		48		-		-			48			1.1	%
Other - Asset Backed		-		26		-		-			26			0.6	%
Subtotal - Fixed Income		-		1,841		6		-			1,847			42.9	%
Real Estate		-		-		163		-			163			3.8	%
Alternative Investments		-		-		161		-			161			3.7	%
Securities Lending		-		215		-		-			215			5.0	%
Securities Lending Collateral (a)		-		-		-		(236	)		(236	)		(5.5	) %
Cash and Cash Equivalents		-		93		-		-			93			2.2	%
Other - Pending Transactions and
Accrued Income (b)		-		-		-		(26	)		(26	)		(0.6	) %
Total	$	1,958	$	2,277	$	330	$	(262	)	$	4,303			100.0	%

(a)   Amounts in "Other" column primarily represent an obligation to repay cash 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 AEP’s pension assets:

	Corporate		Real		Alternative		Total
	Debt		Estate		Investments		Level 3
	(in millions)
Balance as of January 1, 2011	$	-	$	83	$	130	$	213
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		-		22		9		31
Relating to Assets Sold During the Period		-		-		3		3
Purchases and Sales		-		58		19		77
Transfers into Level 3		6		-		-		6
Transfers out of Level 3		-		-		-		-
Balance as of December 31, 2011	$	6	$	163	$	161	$	330

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The following table presents the classification of OPEB plan assets within the fair value hierarchy at December 31, 2011:

													Year End
Asset Class	Level 1		Level 2		Level 3		Other			Total			Allocation
	(in millions)
Equities:
Domestic	$	348	$	-	$	-	$	-		$	348			24.7	%
International		380		-		-		-			380			27.0	%
Common Collective Trust -
Global		-		99		-		-			99			7.0	%
Subtotal - Equities		728		99		-		-			827			58.7	%
Fixed Income:
Common Collective Trust - Debt		-		69		-		-			69			4.9	%
United States Government and
Agency Securities		-		81		-		-			81			5.7	%
Corporate Debt		-		152		-		-			152			10.8	%
Foreign Debt		-		32		-		-			32			2.3	%
State and Local Government		-		9		-		-			9			0.6	%
Other - Asset Backed		-		2		-		-			2			0.1	%
Subtotal - Fixed Income		-		345		-		-			345			24.4	%
Trust Owned Life Insurance:
International Equities		-		46		-		-			46			3.3	%
United States Bonds		-		158		-		-			158			11.2	%
Cash and Cash Equivalents		17		23		-		-			40			2.9	%
Other - Pending Transactions and
Accrued Income (a)		-		-		-		(6	)		(6	)		(0.5	) %
Total	$	745	$	671	$	-	$	(6	)	$	1,410			100.0	%

(a)   Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

99

The following table presents the classification of pension plan assets within the fair value hierarchy at December 31, 2010:

													Year End
Asset Class	Level 1		Level 2		Level 3		Other			Total			Allocation
	(in millions)
Equities:
Domestic	$	1,350	$	2	$	-	$	-		$	1,352			35.1	%
International		403		-		-		-			403			10.4	%
Real Estate Investment Trusts		112		-		-		-			112			2.9	%
Common Collective Trust -
International		-		163		-		-			163			4.2	%
Subtotal - Equities		1,865		165		-		-			2,030			52.6	%
Fixed Income:
United States Government and
Agency Securities		-		634		-		-			634			16.4	%
Corporate Debt		-		672		-		-			672			17.4	%
Foreign Debt		-		127		-		-			127			3.3	%
State and Local Government		-		23		-		-			23			0.6	%
Other - Asset Backed		-		51		-		-			51			1.3	%
Subtotal - Fixed Income		-		1,507		-		-			1,507			39.0	%
Real Estate		-		-		83		-			83			2.2	%
Alternative Investments		-		-		130		-			130			3.4	%
Securities Lending		-		254		-		-			254			6.6	%
Securities Lending Collateral (a)		-		-		-		(276	)		(276	)		(7.1	)%
Cash and Cash Equivalents (b)		-		127		-		2			129			3.3	%
Other - Pending Transactions and
Accrued Income (c)		-		-		-		1			1			-	%
Total	$	1,865	$	2,053	$	213	$	(273	)	$	3,858			100.0	%

(a)  Amounts in "Other" column primarily represent an obligation to repay cash collateral received as part of the Securities Lending Program.

(b)   Amounts in "Other" column primarily represent foreign currency holdings.

(c)   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 real estate and alternative investments classified as Level 3 in the fair value hierarchy for the pension assets:

				Alternative		Total
	Real Estate			Investments		Level 3
	(in millions)
Balance as of January 1, 2010	$	90		$	106	$	196
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		(7	)		4		(3	)
Relating to Assets Sold During the Period		-			1		1
Purchases and Sales		-			19		19
Transfers into Level 3		-			-		-
Transfers out of Level 3		-			-		-
Balance as of December 31, 2010	$	83		$	130	$	213

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The following table presents the classification of OPEB plan assets within the fair value hierarchy at December 31, 2010:

													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in millions)
Equities:
	Domestic		$	584	$	-	$	-	$	-	$	584	40.0	%
	International			220		-		-		-		220	15.1	%
	Common Collective Trust -
		Global		-		115		-		-		115	7.9	%
Subtotal - Equities				804		115		-		-		919	63.0	%
Fixed Income:
	Common Collective Trust - Debt			-		48		-		-		48	3.3	%
	United States Government and
		Agency Securities		-		93		-		-		93	6.4	%
	Corporate Debt			-		110		-		-		110	7.5	%
	Foreign Debt			-		25		-		-		25	1.7	%
	State and Local Government			-		3		-		-		3	0.2	%
	Other - Asset Backed			-		1		-		-		1	0.1	%
Subtotal - Fixed Income				-		280		-		-		280	19.2	%
Trust Owned Life Insurance:
	International Equities			-		49		-		-		49	3.3	%
	United States Bonds			-		163		-		-		163	11.1	%
Cash and Cash Equivalents (a)				21		25		-		1		47	3.2	%
Other - Pending Transactions and
	Accrued Income (b)			-		-		-		3		3	0.2	%
Total			$	825	$	632	$	-	$	4	$	1,461	100.0	%

(a)  Amounts in "Other" column primarily represent foreign currency holdings.

(b)  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 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.

	December 31,
Accumulated Benefit Obligation	2011			2010
	(in millions)
Qualified Pension Plan		$	4,808		$	4,659
Nonqualified Pension Plans			89			80
Total		$	4,897		$	4,739

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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 at December 31, 2011 and 2010 were as follows:

	Underfunded Pension Plans
	December 31,
	2011				2010
	(in millions)
Projected Benefit Obligation		$	4,991			$	4,807
Accumulated Benefit Obligation		$	4,897			$	4,739
Fair Value of Plan Assets			4,303				3,858
Underfunded Accumulated Benefit Obligation		$	(594	)		$	(881	)

Estimated Future Benefit Payments and Contributions

We expect contributions and payments for the pension plans of $208 million and the OPEB plans of $99 million during 2012.  The estimated pension benefit payments for the unfunded plan and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits.  For the qualified pension plan, we may make additional discretionary contributions to maintain the funded status of the plan.  The contribution to the OPEB plans is generally based on the amount of the OPEB plans’ periodic benefit costs for accounting purposes as provided in agreements with state regulatory authorities, plus the additional discretionary contribution of our Medicare subsidy receipts.

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.  In December 2011, we amended the prescription drug program for certain participants.  The impact of the change is reflected in the Benefit Plan Obligation table as a plan amendment.  As a result of this amendment to the plan, the Medicare subsidy receipts in the following table are reduced from prior published estimates.  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		Benefit		Medicare Subsidy
	Payments		Payments		Receipts
	(in millions)
2012	$	327	$	145		$	9
2013		334		148			-
2014		354		153			-
2015		356		160			-
2016		360		168			-
Years 2017 to 2021, in Total		1,864		955			2

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Components of Net Periodic Benefit Cost

The following table provides the components of our net periodic benefit cost for the plans for the years ended December 31, 2011, 2010 and 2009:

								Other Postretirement
		Pension Plans						Benefit Plans
		Years Ended December 31,
		2011		2010		2009		2011		2010		2009
		(in millions)
Service Cost		$	72	$	111	$	104	$	42	$	47	$	42
Interest Cost			237		253		254		109		113		110
Expected Return on Plan Assets			(314)		(312)		(321)		(109)		(105)		(80)
Curtailment			-		-		-		1		-		-
Amortization of Transition Obligation			-		-		-		2		27		27
Amortization of Prior Service Cost (Credit)			1		-		-		(1)		-		-
Amortization of Net Actuarial Loss			122		89		59		29		29		42
Net Periodic Benefit Cost			118		141		96		73		111		141
Capitalized Portion			(37)		(44)		(30)		(22)		(35)		(44)
Net Periodic Benefit Cost Recognized as
	Expense	$	81	$	97	$	66	$	51	$	76	$	97

Estimated amounts expected to be amortized to net periodic benefit costs and the impact on the balance sheet during 2012 are shown in the following table:

			Other
			Postretirement
	Pension Plans		Benefit Plans
Components	(in millions)
Net Actuarial Loss	$	145	$	59
Prior Service Credit		(1)		(18)
Transition Obligation		-		1
Total Estimated 2012 Amortization	$	144	$	42
Expected to be Recorded as
Regulatory Asset	$	116	$	25
Deferred Income Taxes		10		6
Net of Tax AOCI		18		11
Total	$	144	$	42

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 members 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 $64 million in 2011, $61 million in 2010 and $74 million in 2009.

UMWA Benefits

We provide UMWA pension, health and welfare benefits for certain unionized mining 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.

103

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 an 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 002), which under the Pension Protection Act of 2006 (PPA) was in Seriously Endangered Status for the plan years ending June 30, 2011 and 2010, without utilization of extended amortization provisions.  The Plan is required under the PPA to adopt a funding improvement plan by May 25, 2012.  Contributions in 2011, 2010 and 2009, which were made under a collective bargaining agreement that expires December 31, 2012, were immaterial and represent less than 5% of the total contributions in the plan’s latest annual report for the years ended June 30, 2011, 2010 and 2009.  Contributions did not include a surcharge, and there are no minimum contributions for future years.

8.  BUSINESS SEGMENTS

Our primary business is the generation, transmission and distribution of electricity.  Within our Utility Operations 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.

While our Utility Operations segment remains our primary business segment, the advancement of an area of our business prompted us to identify a new reportable segment.  Starting in the fourth quarter of 2011, we established our new Transmission Operations segment as described below:

Utility Operations

·   Generation of electricity for sale to U.S. retail and wholesale customers.

·   Transmission and distribution of electricity through assets owned and operated by our ten utility operating companies.

Transmission Operations

·   Development, construction and operation of transmission facilities through investments in our wholly-owned transmission subsidiaries that were established in 2009 and our transmission joint ventures.  These investments have FERC-approved returns on equity.

AEP River Operations

·   Commercial barging operations that transport coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.

Generation and Marketing

·   Nonregulated generation in ERCOT.

·   Marketing and risk management activities primarily in ERCOT and, to a lesser extent, Ohio in PJM and MISO.

The remainder of our activities is presented as All Other.  While not considered a reportable segment, All Other includes:

·   Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

·   Tax and interest expense adjustments related to our UK operations which were sold in 2004 and 2002.

·   Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.  These contracts were financial derivatives which settled and expired in the fourth quarter of 2011.

·   Revenue sharing related to the Plaquemine Cogeneration Facility which ended in the fourth quarter of 2011.

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The tables below present our reportable segment information for the years ended December 31, 2011, 2010 and 2009 and balance sheet information as of December 31, 2011 and 2010.  These amounts include certain estimates and allocations where necessary.  We reclassified prior year amounts to conform to the current year’s presentation.

							Nonutility Operations
									Generation
			Utility		Transmission		AEP River		and		All Other		Reconciling
			Operations		Operations		Operations		Marketing		(a)		Adjustments			Consolidated
			(in millions)
Year Ended December 31, 2011
Revenues from:
		External Customers	$	14,088	$	3	$	696	$	305	$	24	$	-		$	15,116
		Other Operating Segments		112		5		20		1		8		(146)			-
Total Revenues			$	14,200	$	8	$	716	$	306	$	32	$	(146)		$	15,116
Depreciation and Amortization			$	1,613	$	-	$	28	$	25	$	2	$	(13)	(b)	$	1,655
Interest Income				29		-		-		(1)		17		(18)			27
Carrying Costs Income				393		-		-		-		-		-			393
Interest Expense				886		1		18		18		43		(33)	(b)		933
Income Tax Expense (Credit)				722		2		24		(18)		88		-			818
Income (Loss) Before Extraordinary
	Items		$	1,549	$	30	$	45	$	14	$	(62)	$	-		$	1,576
Extraordinary Items, Net of Tax				373		-		-		-		-		-			373
Net Income (Loss)			$	1,922	$	30	$	45	$	14	$	(62)	$	-		$	1,949
Gross Property Additions			$	2,405	$	263	$	18	$	2	$	214	$	-		$	2,902
							Nonutility Operations
									Generation
			Utility		Transmission		AEP River		and		All Other		Reconciling
			Operations		Operations		Operations		Marketing		(a)		Adjustments			Consolidated
			(in millions)
Year Ended December 31, 2010
Revenues from:
		External Customers	$	13,687	$	-	$	566	$	173	$	1	$	-		$	14,427
		Other Operating Segments		105		1		22		-		14		(142)			-
Total Revenues			$	13,792	$	1	$	588	$	173	$	15	$	(142)		$	14,427
Depreciation and Amortization			$	1,598	$	-	$	24	$	30	$	2	$	(13)	(b)	$	1,641
Interest Income				8		-		-		2		31		(20)			21
Carrying Costs Income				70		-		-		-		-		-			70
Interest Expense				942		-		14		20		58		(35)	(b)		999
Income Tax Expense (Credit)				651		(1)		19		(20)		(6)		-			643
Net Income (Loss)				1,192		9		37		25		(45)		-			1,218
Gross Property Additions				2,440		35		23		1		1		-			2,500

105

								Nonutility Operations
										Generation
			Utility			Transmission		AEP River		and		All Other		Reconciling
			Operations			Operations		Operations		Marketing		(a)		Adjustments			Consolidated
			(in millions)
Year Ended December 31, 2009
Revenues from:
		External Customers	$	12,733	(d)	$	-	$	490	$	281	$	(15)	$	-		$	13,489
		Other Operating Segments		70	(d)		-		18		5		36		(129)			-
Total Revenues			$	12,803		$	-	$	508	$	286	$	21	$	(129)		$	13,489
Depreciation and Amortization			$	1,561		$	-	$	17	$	29	$	2	$	(12)	(b)	$	1,597
Interest Income				4			-		-		-		47		(40)			11
Carrying Costs Income				47			-		-		-		-		-			47
Interest Expense				916			-		5		21		86		(55)	(b)		973
Income Tax Expense (Credit)				553			-		23		-		(1)		-			575
Income (Loss) Before Extraordinary
	Items		$	1,325		$	4	$	47	$	41	$	(47)	$	-		$	1,370
Extraordinary Items, Net of Tax				(5)			-		-		-		-		-			(5)
Net Income (Loss)			$	1,320		$	4	$	47	$	41	$	(47)	$	-		$	1,365
Gross Property Additions			$	2,812		$	1	$	81	$	1	$	1	$	-		$	2,896

							Nonutility Operations
									Generation				Reconciling
			Utility		Transmission		AEP River		and		All Other		Adjustments
			Operations		Operations		Operations		Marketing		(a)		(b)			Consolidated
			(in millions)
December 31, 2011
Total Property, Plant and Equipment			$	54,396	$	323	$	608	$	590	$	11	$	(258)		$	55,670
Accumulated Depreciation and
	Amortization			18,393		-		136		219		10		(59)			18,699
Total Property, Plant and
	Equipment - Net		$	36,003	$	323	$	472	$	371	$	1	$	(199)		$	36,971
Total Assets			$	50,093	$	594	$	659	$	868	$	16,751	$	(16,742)	(c)	$	52,223
Investments in Equity Method Investees				24		256		17		-		2		-			299
							Nonutility Operations
									Generation				Reconciling
			Utility		Transmission		AEP River		and		All Other		Adjustments
			Operations		Operations		Operations		Marketing		(a)		(b)			Consolidated
			(in millions)
December 31, 2010
Total Property, Plant and Equipment			$	52,771	$	51	$	574	$	584	$	11	$	(251)		$	53,740
Accumulated Depreciation and
		Amortization		17,795		-		110		198		9		(46)			18,066
Total Property, Plant and
	Equipment - Net		$	34,976	$	51	$	464	$	386	$	2	$	(205)		$	35,674
Total Assets			$	48,658	$	230	$	621	$	881	$	15,942	$	(15,877)	(c)	$	50,455
Investments in Equity Method Investees				22		135		3		-		-		-			160

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(a) All Other includes:

·   Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

·   Tax and interest expense adjustments related to our UK operations which were sold in 2004 and 2002.

·   Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.  These contracts were financial derivatives which settled and expired in the fourth quarter of 2011.

·   Revenue sharing related to the Plaquemine Cogeneration Facility which ended in the fourth quarter of 2011.

(b) Includes eliminations due to an intercompany capital lease.

(c) 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.

(d) PSO and SWEPCo transferred certain existing ERCOT energy marketing contracts to AEP Energy Partners, Inc. (AEPEP) (Generation and Marketing segment) and entered into intercompany financial and physical purchase and sales agreements with AEPEP.  As a result, we reported third-party net purchases or sales activity for these energy marketing contracts as Revenues from External Customers for the Utility Operations segment.  This was offset by the Utility Operations segment's related net purchases for these contracts with AEPEP in Revenues from Other Operating Segments of $5 million for the years ended December 31, 2009.  The Generation and Marketing segment also reported these purchase or sales contracts with Utility Operations as Revenues from Other Operating Segments.  These affiliated contracts between PSO and SWEPCo with AEPEP ended in December 2009.

9.  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, 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

Trading Strategies

Our strategy surrounding the use of derivative instruments for trading purposes focuses on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact.

Risk Management Strategies

Our strategy surrounding the use of derivative instruments focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  To accomplish our objectives, we primarily employ risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments.  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 degree, heating oil and gasoline, emission allowance 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.

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The following table represents the gross notional volume of our outstanding derivative contracts as of December 31, 2011 and 2010:

Notional Volume of Derivative Instruments
		Volume
			December 31,			Unit of
Primary Risk Exposure			2011		2010	Measure
		(in millions)
Commodity:
	Power		609		652	MWHs
	Coal		21		63	Tons
	Natural Gas		100		94	MMBtus
	Heating Oil and Gasoline		6		6	Gallons
	Interest Rate	$	226	$	171	USD
Interest Rate and Foreign Currency		$	907	$	907	USD

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, coal, natural gas and heating oil and gasoline (“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 fuel or 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.  For disclosure purposes, these contracts are included with other hedging activities as “Commodity.”  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.

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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.

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, 2011 and 2010 balance sheets, we netted $26 million and $8 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $133 million and $109 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

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The following tables represent the gross fair value impact of our derivative activity on our balance sheets as of December 31, 2011 and 2010:

Fair Value of Derivative Instruments
December 31, 2011
		Risk Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in millions)
Current Risk Management Assets		$	852	$	24	$	-	$	(683)	$	193
Long-term Risk Management Assets			641		15		-		(253)		403
Total Assets			1,493		39		-		(936)		596
Current Risk Management Liabilities			847		29		20		(746)		150
Long-term Risk Management Liabilities			483		15		22		(325)		195
Total Liabilities			1,330		44		42		(1,071)		345
Total MTM Derivative Contract Net Assets
	(Liabilities)	$	163	$	(5)	$	(42)	$	135	$	251
Fair Value of Derivative Instruments
December 31, 2010
		Risk Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in millions)
Current Risk Management Assets		$	1,023	$	18	$	30	$	(839)	$	232
Long-term Risk Management Assets			546		12		2		(150)		410
Total Assets			1,569		30		32		(989)		642
Current Risk Management Liabilities			995		13		2		(881)		129
Long-term Risk Management Liabilities			387		6		3		(255)		141
Total Liabilities			1,382		19		5		(1,136)		270
Total MTM Derivative Contract Net Assets
	(Liabilities)	$	187	$	11	$	27	$	147	$	372

(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 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.

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The table below presents our activity of derivative risk management contracts for the years ended December 31, 2011, 2010 and 2009:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
	Years Ended December 31,
Location of Gain (Loss)	2011		2010		2009
	(in millions)
Utility Operations Revenues	$	46	$	85	$	144
Other Revenues		20		9		19
Regulatory Assets (a)		(22)		(9)		(28)
Regulatory Liabilities (a)		(3)		38		(7)
Total Gain (Loss) on Risk Management Contracts	$	41	$	123	$	128

(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 our statements of income.  During 2011 and 2010, we recognized gains of $3 million and $6 million, respectively, on our hedging instruments and offsetting losses of $6 million and $6 million, respectively, on our long-term debt.  For 2011 and 2010, hedge ineffectiveness was immaterial.  During 2009, we did not employ any fair value hedging strategies.

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 our 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).

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Realized gains and losses on derivative contracts for the purchase and sale of power, coal, natural gas, and heating oil and gasoline designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our statements of income or in Regulatory Assets or Regulatory Liabilities on our balance sheets, depending on the specific nature of the risk being hedged.  During 2011, 2010 and 2009, we designated commodity derivatives as cash flow hedges.

We reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our statements of income.  During 2011, 2010 and 2009, we designated heating oil and gasoline derivatives as cash flow hedges.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur.  During 2011, 2010 and 2009, 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 our balance sheets into Depreciation and Amortization expense on our statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.  During 2011, 2010 and 2009, we designated foreign currency derivatives as cash flow hedges.

During 2009, we recognized a $6 million gain in Interest Expense related to hedge ineffectiveness on interest rate derivatives designated in cash flow hedge strategies.  During 2011, 2010 and 2009, hedge ineffectiveness was immaterial or nonexistent for all of the other cash flow hedge strategies disclosed above.

The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our balance sheets and the reasons for changes in cash flow hedges for the years ended December 31, 2011, 2010 and 2009.  All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Year Ended December 31, 2011
					Interest Rate
					and Foreign
			Commodity		Currency		Total
			(in millions)
Balance in AOCI as of December 31, 2010			$	7	$	4	$	11
Changes in Fair Value Recognized in AOCI				(5)		(28)		(33)
Amount of (Gain) or Loss Reclassified from AOCI
	to Statement of Income/within Balance Sheet:
		Utility Operations Revenues		3		-		3
		Other Revenues		(5)		-		(5)
		Purchased Electricity for Resale		(2)		-		(2)
		Other Operation Expense		(1)		-		(1)
		Maintenance Expense		(1)		-		(1)
		Interest Expense		-		4		4
		Property, Plant and Equipment		(1)		-		(1)
		Regulatory Assets (a)		2		-		2
		Regulatory Liabilities (a)		-		-		-
Balance in AOCI as of December 31, 2011			$	(3)	$	(20)	$	(23)

112

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Year Ended December 31, 2010
					Interest Rate
					and Foreign
			Commodity		Currency		Total
			(in millions)
Balance in AOCI as of December 31, 2009			$	(2)	$	(13)	$	(15)
Changes in Fair Value Recognized in AOCI				9		13		22
Amount of (Gain) or Loss Reclassified from AOCI
	to Statement of Income/within Balance Sheet:
		Utility Operations Revenues		-		-		-
		Other Revenues		(7)		-		(7)
		Purchased Electricity for Resale		4		-		4
		Interest Expense		-		4		4
		Regulatory Assets (a)		3		-		3
		Regulatory Liabilities (a)		-		-		-
Balance in AOCI as of December 31, 2010			$	7	$	4	$	11
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Year Ended December 31, 2009
					Interest Rate
					and Foreign
			Commodity		Currency		Total
			(in millions)
Balance in AOCI as of December 31, 2008			$	7	$	(29)	$	(22)
Changes in Fair Value Recognized in AOCI				(6)		11		5
Amount of (Gain) or Loss Reclassified from AOCI
	to Statement of Income/within Balance Sheet:
		Utility Operations Revenues		(15)		-		(15)
		Other Revenues		(15)		-		(15)
		Purchased Electricity for Resale		29		-		29
		Interest Expense		-		5		5
		Regulatory Assets (a)		5		-		5
		Regulatory Liabilities (a)		(7)		-		(7)
Balance in AOCI as of December 31, 2009			$	(2)	$	(13)	$	(15)

  (a)  Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

113

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our balance sheets at December 31, 2011 and 2010 were:

Impact of Cash Flow Hedges on the Balance Sheet
December 31, 2011
				Interest Rate
				and Foreign
		Commodity		Currency		Total
		(in millions)
Hedging Assets (a)		$	20	$	-	$	20
Hedging Liabilities (a)			25		42		67
AOCI Gain (Loss) Net of Tax			(3)		(20)		(23)
Portion Expected to be Reclassified to Net
	Income During the Next Twelve Months		(3)		(2)		(5)
Impact of Cash Flow Hedges on the Balance Sheet
December 31, 2010
				Interest Rate
				and Foreign
		Commodity		Currency		Total
		(in millions)
Hedging Assets (a)		$	13	$	25	$	38
Hedging Liabilities (a)			2		4		6
AOCI Gain (Loss) Net of Tax			7		4		11
Portion Expected to be Reclassified to Net
	Income During the Next Twelve Months		3		(2)		1

(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on our 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, 2011, 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 is 30 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.

We use standardized master agreements which 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.

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Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, we are obligated to post an additional amount of collateral if our credit ratings decline below investment grade.  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 investment grade.  The following table represents: (a) our aggregate fair value of such derivative contracts, (b) the amount of collateral we would have been required to post for all derivative and non-derivative contracts if our credit ratings had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of December 31, 2011 and 2010:

		December 31,
		2011		2010
		(in millions)
Liabilities for Derivative Contracts with Credit Downgrade Triggers		$	32	$	20
Amount of Collateral AEP Subsidiaries Would Have Been
	Required to Post		39		45
Amount Attributable to RTO and ISO Activities			38		44

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.  We do not anticipate a non-performance event under these provisions.  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, 2011 and 2010:

	December 31,
	2011		2010
	(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual
Netting Arrangements	$	515	$	401
Amount of Cash Collateral Posted		56		81
Additional Settlement Liability if Cross Default Provision is Triggered		291		213

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10.  FAIR VALUE MEASUREMENTS

Fair Value Measurements of Long-term Debt

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities.  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, 2011 and 2010 are summarized in the following table:

	December 31,
	2011				2010
	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
Long-term Debt	$	16,516	$	19,259	$	16,811	$	18,285

Fair Value Measurements of Other Temporary Investments

Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds, 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, 2011
			Gross		Gross		Estimated
			Unrealized		Unrealized		Fair
Other Temporary Investments	Cost		Gains		Losses		Value
	(in millions)
Restricted Cash (a)	$	216	$	-	$	-	$	216
Fixed Income Securities:
Mutual Funds		64		-		-		64
Equity Securities - Mutual Funds		11		3		-		14
Total Other Temporary Investments	$	291	$	3	$	-	$	294
	December 31, 2010
			Gross		Gross		Estimated
			Unrealized		Unrealized		Fair
Other Temporary Investments	Cost		Gains		Losses		Value
	(in millions)
Restricted Cash (a)	$	225	$	-	$	-	$	225
Fixed Income Securities:
Mutual Funds		69		-		-		69
Variable Rate Demand Notes		97		-		-		97
Equity Securities - Mutual Funds		18		7		-		25
Total Other Temporary Investments	$	409	$	7	$	-	$	416

(a) Primarily represents amounts held for the payment of debt.

116

The following table provides the activity for our debt and equity securities within Other Temporary Investments for the years ended December 31, 2011, 2010 and 2009:

	Years Ended December 31,
	2011			2010			2009
	(in millions)
Proceeds from Investment Sales		$	268		$	455		$	35
Purchases of Investments			154			503			82
Gross Realized Gains on Investment Sales			4			16			-
Gross Realized Losses on Investment Sales			-			-			-

At December 31, 2011 and 2010, we had no Other Temporary Investments with an unrealized loss position.  In 2009, we recorded $9 million ($6 million, net of tax) of other-than-temporary impairments of Other Temporary Investments for equity investments of our protected cell captive insurance company.  At December 31, 2011, fixed income securities are primarily debt based mutual funds with short and intermediate maturities.  Mutual funds may be sold and do not contain maturity dates.

The following table provides details of Other Temporary Investments included in Accumulated Other Comprehensive Income (Loss) on our balance sheet and the reasons for changes for the year ended December 31, 2011.  All amounts in the following table are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Other Temporary Investments
Year Ended December 31, 2011
	(in millions)
Balance in AOCI as of December 31, 2010		$	4
Changes in Fair Value Recognized in AOCI			1
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income:
Interest Income			(3	)
Balance in AOCI as of December 31, 2011		$	2

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 at December 31, 2011 and December 31, 2010:

	December 31,
	2011										2010
	Estimated			Gross			Other-Than-				Estimated			Gross				Other-Than-
	Fair			Unrealized			Temporary				Fair			Unrealized				Temporary
	Value			Gains			Impairments				Value			Gains				Impairments
	(in millions)
Cash and Cash Equivalents		$	18		$	-		$	-			$	20		$	-			$	-
Fixed Income Securities:
United States Government			544			61			(1	)			461			23				(1	)
Corporate Debt			54			5			(2	)			59			4				(2	)
State and Local Government			330			-			(2	)			341			(1	)			-
Subtotal Fixed Income Securities			928			66			(5	)			861			26				(3	)
Equity Securities - Domestic			646			215			(80	)			634			183				(123	)
Spent Nuclear Fuel and
Decommissioning Trusts		$	1,592		$	281		$	(85	)		$	1,515		$	209			$	(126	)

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The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2011, 2010 and 2009:

	Years Ended December 31,
	2011			2010			2009
	(in millions)
Proceeds from Investment Sales		$	1,111		$	1,362		$	713
Purchases of Investments			1,167			1,415			771
Gross Realized Gains on Investment Sales			33			12			28
Gross Realized Losses on Investment Sales			22			2			1

The adjusted cost of debt securities was $862 million and $835 million as of December 31, 2011 and 2010, respectively.  The adjusted cost of equity securities was $431 million and $451 million as of December 31, 2011 and 2010, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at December 31, 2011 was as follows:

	Fair Value
	of Debt
	Securities
	(in millions)
Within 1 year	$	62
1 year – 5 years		285
5 years – 10 years		350
After 10 years		231
Total	$	928

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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, 2011 and 2010.  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 AEP’s valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2011
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Cash and Cash Equivalents (a)	$	6	$	-	$	-	$	215		$	221
Other Temporary Investments
Restricted Cash (a)		191		-		-		25			216
Fixed Income Securities:
Mutual Funds		64		-		-		-			64
Equity Securities - Mutual Funds (b)		14		-		-		-			14
Total Other Temporary Investments		269		-		-		25			294
Risk Management Assets
Risk Management Commodity Contracts (c) (f)		47		1,299		147		(945	)		548
Cash Flow Hedges:
Commodity Hedges (c)		15		23		-		(18	)		20
De-designated Risk Management Contracts (d)		-		-		-		28			28
Total Risk Management Assets		62		1,322		147		(935	)		596
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)		-		5		-		13			18
Fixed Income Securities:
United States Government		-		544		-		-			544
Corporate Debt		-		54		-		-			54
State and Local Government		-		330		-		-			330
Subtotal Fixed Income Securities		-		928		-		-			928
Equity Securities - Domestic (b)		646		-		-		-			646
Total Spent Nuclear Fuel and Decommissioning Trusts		646		933		-		13			1,592
Total Assets	$	983	$	2,255	$	147	$	(682	)	$	2,703
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)	$	43	$	1,209	$	78	$	(1,052	)	$	278
Cash Flow Hedges:
Commodity Hedges (c)		-		43		-		(18	)		25
Interest Rate/Foreign Currency Hedges		-		42		-		-			42
Total Risk Management Liabilities	$	43	$	1,294	$	78	$	(1,070	)	$	345

119

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2010
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Cash and Cash Equivalents (a)	$	170	$	-	$	-	$	124		$	294
Other Temporary Investments
Restricted Cash (a)		184		-		-		41			225
Fixed Income Securities:
Mutual Funds		69		-		-		-			69
Variable Rate Demand Notes		-		97		-		-			97
Equity Securities - Mutual Funds (b)		25		-		-		-			25
Total Other Temporary Investments		278		97		-		41			416
Risk Management Assets
Risk Management Commodity Contracts (c) (g)		20		1,432		112		(1,013	)		551
Cash Flow Hedges:
Commodity Hedges (c)		11		17		-		(15	)		13
Interest Rate/Foreign Currency Hedges		-		25		-		-			25
Fair Value Hedges		-		7		-		-			7
De-designated Risk Management Contracts (d)		-		-		-		46			46
Total Risk Management Assets		31		1,481		112		(982	)		642
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)		-		8		-		12			20
Fixed Income Securities:
United States Government		-		461		-		-			461
Corporate Debt		-		59		-		-			59
State and Local Government		-		341		-		-			341
Subtotal Fixed Income Securities		-		861		-		-			861
Equity Securities - Domestic (b)		634		-		-		-			634
Total Spent Nuclear Fuel and Decommissioning Trusts		634		869		-		12			1,515
Total Assets	$	1,113	$	2,447	$	112	$	(805	)	$	2,867
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	25	$	1,325	$	27	$	(1,114	)	$	263
Cash Flow Hedges:
Commodity Hedges (c)		4		13		-		(15	)		2
Interest Rate/Foreign Currency Hedges		-		4		-		-			4
Fair Value Hedges		-		1		-		-			1
Total Risk Management Liabilities	$	29	$	1,343	$	27	$	(1,129	)	$	270

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(a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties.  Level 1 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) 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.

(e) Amounts in "Other" column primarily represent accrued interest receivables from financial institutions.  Level 2 amounts primarily represent investments in money market funds.

(f) The December 31, 2011 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $3 million in 2012, $7 million in periods 2013-2015 and ($6) million in periods 2016-2018;  Level 2 matures $21 million in 2012, $50 million in periods 2013-2015, $11 million in periods 2016-2017 and $8 million in periods 2018-2030;  Level 3 matures ($19) million in 2012, $44 million in periods 2013-2015, $18 million in periods 2016-2017 and $26 million in periods 2018-2030.  Risk management commodity contracts are substantially comprised of power contracts.

(g) The December 31, 2010 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures ($2) million in 2011, $2 million in periods 2012-2014 and ($5) million in periods 2015-2018;  Level 2 matures $13 million in 2011, $66 million in periods 2012-2014, $12 million in periods 2015-2016 and $16 million in periods 2017-2028;  Level 3 matures $18 million in 2011, $24 million in periods 2012-2014, $16 million in periods 2015-2016 and $27 million in periods 2017-2028.  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, 2011 and 2010.

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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:

		Net Risk Management
Year Ended December 31, 2011		Assets (Liabilities)
		(in millions)
Balance as of December 31, 2010		$	85
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)			(10)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		9
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			-
Purchases, Issuances and Settlements (c)			(3)
Transfers into Level 3 (d) (f)			13
Transfers out of Level 3 (e) (f)			(12)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			(13)
Balance as of December 31, 2011		$	69
		Net Risk Management
Year Ended December 31, 2010		Assets (Liabilities)
		(in millions)
Balance as of December 31, 2009		$	62
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)			5
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		63
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			-
Purchases, Issuances and Settlements (c)			(25)
Transfers into Level 3 (d) (f)			18
Transfers out of Level 3 (e) (f)			(53)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			15
Balance as of December 31, 2010		$	85
		Net Risk Management
Year Ended December 31, 2009		Assets (Liabilities)
		(in millions)
Balance as of December 31, 2008		$	49
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)			(4)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		44
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			-
Purchases, Issuances and Settlements (c)			(17)
Transfers in and/or out of Level 3 (h)			(25)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			15
Balance as of December 31, 2009		$	62

(a) Included in revenues on our 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) Represents existing assets or liabilities that were previously categorized as Level 3.

(f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

(g) Relates to the net gains (losses) of those contracts that are not reflected on our statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets.

(h) Represents existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.

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11.  INCOME TAXES

The details of our consolidated income taxes before extraordinary items as reported are as follows:

	Years Ended December 31,
	2011			2010			2009
	(in millions)
Federal:
Current	$	20		$	(134	)	$	(575	)
Deferred		786			760			1,171
Total Federal		806			626			596
State and Local:
Current		37			(20	)		(76	)
Deferred		(25	)		38			55
Total State and Local		12			18			(21	)
International:
Current		-			(1	)		-
Deferred		-			-			-
Total International		-			(1	)		-
Income Tax Expense	$	818		$	643		$	575

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,
			2011			2010			2009
			(in millions)
Net Income			$	1,949		$	1,218		$	1,365
Extraordinary Items, Net of Tax of $(112) million and $3 million in 2011
	and 2009, respectively			(373)			-			5
Income Before Extraordinary Items				1,576			1,218			1,370
Income Tax Expense				818			643			575
Pretax Income			$	2,394		$	1,861		$	1,945
Income Taxes on Pretax Income at Statutory Rate (35%)			$	838		$	651		$	681
Increase (Decrease) in Income Taxes resulting from the following items:
		Depreciation		41			47			31
		Investment Tax Credits, Net		(15)			(16)			(19)
		Energy Production Credits		(18)			(20)			(15)
		State and Local Income Taxes, Net		(22)			11			(14)
		Removal Costs		(20)			(19)			(19)
		AFUDC		(42)			(33)			(36)
		Medicare Subsidy		1			12			(11)
		Valuation Allowance		86			-			-
		Tax Reserve Adjustments		2			(16)			(6)
		Other		(33)			26			(17)
Income Tax Expense			$	818		$	643		$	575
Effective Income Tax Rate				34.2	%		34.6	%		29.6	%

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The following table shows elements of the net deferred tax liability and significant temporary differences:

	December 31,
	2011			2010
	(in millions)
Deferred Tax Assets	$	2,855		$	2,519
Deferred Tax Liabilities		(11,185	)		(10,009	)
Net Deferred Tax Liabilities	$	(8,330	)	$	(7,490	)
Property Related Temporary Differences	$	(5,963	)	$	(5,301	)
Amounts Due from Customers for Future Federal Income Taxes		(259	)		(250	)
Deferred State Income Taxes		(668	)		(622	)
Securitized Transition Assets		(621	)		(651	)
Regulatory Assets		(1,208	)		(867	)
Postretirement Benefits		424			356
Accrued Pensions		149			218
Deferred Income Taxes on Other Comprehensive Loss		254			207
Accrued Nuclear Decommissioning		(436	)		(395	)
Net Operating Loss Carryforward		125			-
Tax Credit Carryforward		182			-
Valuation Allowance		(86	)		-
All Other, Net		(223	)		(185	)
Net Deferred Tax Liabilities	$	(8,330	)	$	(7,490	)

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 2009.  We completed the examination of the years 2007 and 2008 in April 2011 and settled all outstanding issues on appeal for the years 2001 through 2006 in October 2011.  The settlements did not have a material impact on net income, cash flows or financial condition.  The IRS examination of years 2009 and 2010 started in October 2011.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, 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 have a material effect on 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.  We believe that we have filed tax returns with positions that may be challenged by these tax authorities.  Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and the ultimate resolution of these audits will not materially impact net income.  With few exceptions, we are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2000.

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Net Income Tax Operating Loss Carryforward

In 2011, we sustained a federal net income tax operating loss of $226 million driven primarily by bonus depreciation, pension plan contributions and other book versus tax temporary differences.  We also had state net income tax operating loss carryforwards as indicated in the table below.  As a result, we accrued deferred federal, state and local income tax benefits in 2011.  We expect to realize the federal, state and local cash flow benefit in future periods as there was insufficient capacity in prior periods to carry the net operating loss back. We anticipate future taxable income will be sufficient to realize the net income tax operating loss tax benefits before the federal carryforward expires after 2031.

	State Net Income
	Tax Operating
	Loss		Year of
State	Carryforward		Expiration
	(in millions)
Oklahoma	$	135		2031
Tennessee		13		2026
Virginia		358		2031
West Virginia		511		2031

We sustained federal, state and local net income tax operating losses in 2009 driven primarily by bonus depreciation, a change in tax accounting method related to units of property and other book versus tax temporary differences.  As a result, we accrued current federal, state and local income tax benefits in 2009.  We realized the federal cash flow benefit in 2010 as there was sufficient capacity in prior periods to carry the net operating loss back.  Most of our state and local jurisdictions do not provide for a net operating loss carry back, therefore the state and local losses were carried forward to future periods.

Tax Credit Carryforward

Federal and state net income tax operating losses sustained in 2009 and 2011 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits.  At December 31, 2011, we have total federal tax credit carryforwards of $182 million and total state tax credit carryforwards of $74 million, not all of which are subject to an expiration date.  If these credits are not utilized, the federal general business tax credits of $81 million will expire in the years 2028 through 2031 and the state coal tax credits of $ 29 million will expire in the years 2013 through 2021.

We anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused.  We do not anticipate state taxable income will be sufficient in future periods to realize the tax benefits of all state income tax credits before they expire unused and we have provided a valuation allowance accordingly.

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.  A significant piece of objective negative information evaluated were the net income tax operating losses sustained in 2009 and 2011.  On the basis of this evaluation of available positive and negative evidence, as of December 31, 2011, a valuation allowance of $30 million for state tax credits, net of federal tax, and $56 million for an unrealized capital loss has been recorded in order to measure only the portion of the deferred tax assets that, more likely than not, will be realized.  The amount of the deferred tax assets considered realizable, however, could be adjusted if estimates of future taxable income during the carryforward period are reduced or if objective negative evidence in the form of cumulative losses is no longer present and additional weight may be given to subjective evidence, such as our projections for growth.

For a discussion of the tax implications of the unrealized capital loss resulting from our settlement with BOA and Enron, see “Enron Bankruptcy” section of Note 5.

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Uncertain Tax Positions

We recognize interest accruals related to uncertain tax positions in interest income or expense, as applicable, and penalties in Other Operation 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,
	2011			2010			2009
	(in millions)
Interest Expense		$	8		$	8		$	1
Interest Income			22			11			5
Reversal of Prior Period Interest Expense			13			5			5

The following table shows balances for amounts accrued for the receipt of interest and the payment of interest and penalties:

	December 31,
	2011			2010
	(in millions)
Accrual for Receipt of Interest		$	13		$	42
Accrual for Payment of Interest and Penalties			6			21

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

	2011			2010			2009
	(in millions)
Balance at January 1,	$	219		$	237		$	237
Increase - Tax Positions Taken During a Prior Period		51			40			56
Decrease - Tax Positions Taken During a Prior Period		(43	)		(43	)		(65	)
Increase - Tax Positions Taken During the Current Year		10			-			16
Decrease - Tax Positions Taken During the Current Year		-			(6	)		-
Increase - Settlements with Taxing Authorities		-			-			1
Decrease - Settlements with Taxing Authorities		(31	)		(2	)		-
Decrease - Lapse of the Applicable Statute of Limitations		(38	)		(7	)		(8	)
Balance at December 31,	$	168		$	219		$	237

The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $ 111 million, $112 million and $137 million for 2011, 2010 and 2009, 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

Under the Energy Tax Incentives Act of 2005, we filed applications with the United States Department of Energy and the IRS in 2008 for the West Virginia IGCC project and in July 2008 the IRS allocated the project $134 million in credits.  In September 2008, we entered into a memorandum of understanding with the IRS concerning the requirements of claiming the credits.  We had until July 2010 to meet certain minimum requirements under the agreement with the IRS or the credits would be forfeited.  In July 2010, we forfeited the allocated tax credits.

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TheAmerican Recovery and Reinvestment Tax Act of 2009 provided for several new grant programs and expanded tax credits and an extension of the 50% bonus depreciation provision enacted in the Economic Stimulus Act of 2008.  The enacted provisions did not have a material impact on net income or financial condition.  However, the bonus depreciation contributed to the 2009 federal net operating tax loss that resulted in a 2010 cash flow benefit of $419 million.

The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts) were enacted in March 2010.  The Health Care Acts amend tax rules so that the portion of employer health care costs that are reimbursed by the Medicare Part D prescription drug subsidy will no longer be deductible by the employer for federal income tax purposes effective for years beginning after December 31, 2012.  Because of the loss of the future tax deduction, a reduction in the deferred tax asset related to the nondeductible OPEB liabilities accrued to date was recorded in March 2010.  This reduction did not materially affect our cash flows or financial condition.  For the year ended December 31, 2010, deferred tax assets decreased $56 million, partially offset by recording net tax regulatory assets of $35 million in our jurisdictions with regulated operations, resulting in a decrease in net income of $21 million.

The Small Business Jobs Act (the Act) was enacted in September 2010.  Included in the Act was a one-year extension of the 50% bonus depreciation provision.  The Tax Relief, Unemployment Insurance Reauthorization and the Job Creation Act of 2010 extended the life of research and development, employment and several energy tax credits originally scheduled to expire at the end of 2010.  In addition, the Act extended the time for claiming bonus depreciation and increased the deduction to 100% for part of 2010 and 2011.  The enacted provisions will not have a material impact on net income or financial condition but had a favorable impact on cash flows of $ 318 million in 2010.

In December of 2011 the U.S. Treasury Department issued guidance regarding the deduction and capitalization of expenditures related to tangible property.  The guidance was in the form of proposed and temporary regulations and generally is effective for tax years beginning in 2012.  These regulations did not have an impact on either net income or cash flow in 2011.  We are still evaluating the impact these regulations will have on future periods.

State Tax Legislation

Ohio House Bill 66 of 2005 imposed a commercial activity tax at a fully phased-in rate of 0.26% on all Ohio gross receipts.  The tax was phased-in over a five-year period that began July 1, 2005 at 23% of the full 0.26% rate.  As a result of this tax, expenses of approximately $14 million, $13 million and $11 million were recorded in 2011, 2010 and 2009, respectively, in Taxes Other Than Income Taxes.

Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rates from 8.5% to 6.5%.  The current 8.5% Indiana corporate income tax rate is scheduled for a 0.5% reduction 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 with a rate of 6%, effective January 1, 2012.

During the third quarter of 2011, the state of West Virginia determined that the state had achieved certain minimum levels of shortfall reserve funds and thus, the West Virginia corporate income tax rate will be reduced to 7.75% in 2012.  The enacted provisions will not have a material impact on net income, cash flows or financial condition.

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12.  LEASES

Leases of property, plant and equipment are for periods up to 60 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	2011			2010			2009
	(in millions)
Net Lease Expense on Operating Leases		$	343		$	343		$	354
Amortization of Capital Leases			72			97			83
Interest on Capital Leases			32			26			13
Total Lease Rental Costs		$	447		$	466		$	450

The following table shows the property, plant and equipment under capital leases and related obligations recorded on our balance sheets.  Capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on our balance sheets.

	December 31,
Property, Plant and Equipment Under Capital Leases	2011		2010
	(in millions)
Generation	$	104	$	97
Other Property, Plant and Equipment		485		482
Total Property, Plant and Equipment Under Capital Leases		589		579
Accumulated Amortization		137		108
Net Property, Plant and Equipment Under Capital Leases	$	452	$	471

Obligations Under Capital Leases
Noncurrent Liability	$	384	$	398
Liability Due Within One Year		74		76
Total Obligations Under Capital Leases	$	458	$	474

Future minimum lease payments consisted of the following at December 31, 2011:

			Noncancelable
Future Minimum Lease Payments	Capital Leases		Operating Leases
	(in millions)
2012	$	96	$	316
2013		81		288
2014		67		264
2015		55		245
2016		47		226
Later Years		285		1,235
Total Future Minimum Lease Payments		631	$	2,574
Less Estimated Interest Element		173
Estimated Present Value of Future Minimum
Lease Payments	$	458

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Master Lease Agreements

We lease certain equipment under master lease agreements.  In December 2010, we signed a new master lease agreement with GE Capital Commercial Inc. (GE) for approximately $ 137 million to replace existing operating and capital leases with GE.  We refinanced $60 million of capital leases and $77 million of operating leases.  These assets were included in existing master lease agreements that were to be terminated in 2011 since GE exercised the termination provision related to these leases in 2008.  In January 2011, we purchased $5 million of previously leased assets that were not included in the 2010 refinancing.  In June 2011, we placed an additional $ 11 million of previously leased assets under a new capital lease.  These obligations are included in the future minimum lease payments schedule earlier in this note.

For equipment under the GE master lease agreements, the lessor is guaranteed receipt of up to 78% of the unamortized balance of the equipment at the end of the lease term.  If the fair value of the leased equipment is below the unamortized balance at the end of the lease term, we are committed to pay the difference between the fair value and the unamortized balance, with the total guarantee not to exceed 78% of the unamortized balance.  For equipment under other master 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.  At December 31, 2011, the maximum potential loss for these lease agreements was approximately $14 million assuming the fair value of the equipment is zero at the end of the lease term.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.

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, 2011 are as follows:

Future Minimum Lease Payments	AEGCo		I&M
	(in millions)
2012	$	74	$	74
2013		74		74
2014		74		74
2015		74		74
2016		74		74
Later Years		443		443
Total Future Minimum Lease Payments	$	813	$	813

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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 $16 million for I&M and $18 million for SWEPCo for the remaining railcars as of December 31, 2011.  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 84% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  I&M’s maximum potential loss related to the guarantee is approximately $12 million and SWEPCo’s is approximately $13 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.

Sabine Dragline Lease

During 2009, Sabine, an entity consolidated in accordance with the accounting guidance for “Variable Interest Entities,” 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.  In addition to the 2009 transactions, Sabine has one additional $53 million dragline completed in 2008 that was financed under a capital lease.  These capital lease assets are included in Other Property, Plant and Equipment on our December 31, 2011 and 2010 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, 2011 and 2010 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 December 2007, I&M entered into a sale-and-leaseback transaction with Citicorp Leasing, Inc. (CLI), an unrelated, unconsolidated, wholly-owned subsidiary of Citibank, N.A. to lease nuclear fuel for I&M’s Cook Plant.  In December 2007, I&M sold a portion of its unamortized nuclear fuel inventory to CLI at cost for $85 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 60 months.  The future payment obligations of $383 thousand 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, 2011 and 2010 balance sheets.  The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2011 are $383 thousand for 2012, based on estimated fuel burn.

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13.  FINANCING ACTIVITIES

AEP Common Stock

In April 2009, we issued 69 million shares of common stock at $24.50 per share for net proceeds of $ 1.64 billion, which were primarily used to repay cash drawn under our credit facilities in the second quarter of 2009.

Set forth below is a reconciliation of common stock share activity for the years ended December 31, 2011, 2010 and 2009:

			Held in
Shares of AEP Common Stock	Issued		Treasury
Balance, December 31, 2008		426,321,248		20,249,992
Issued		72,012,017		-
Treasury Stock Acquired		-		28,866
Balance, December 31, 2009		498,333,265		20,278,858
Issued		2,781,616		-
Treasury Stock Acquired		-		28,867
Balance, December 31, 2010		501,114,881		20,307,725
Issued		2,644,579		-
Treasury Stock Acquired		-		28,867
Balance, December 31, 2011		503,759,460		20,336,592

Preferred Stock

In December 2011, AEP subsidiaries redeemed all of their outstanding preferred stock with a par value of $60 million at a premium, resulting in a $2.8 million loss, which is included in Preferred Stock Dividend Requirements of Subsidiaries Including Capital Stock Expense on our statement of income.  The redeemed shares are no longer outstanding and represent only the right to receive the applicable redemption price, to the extent the shares have not yet been presented for payment.

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Long-term Debt
		Weighted
		Average
		Interest
		Rate at			Outstanding at
		December 31,	Interest Rate Ranges at December 31,		December 31,
Type of Debt and Maturity		2011	2011	2010	2011		2010
					(in millions)
Senior Unsecured Notes
	2011-2040	5.85%	0.955%-8.13%	0.702%-8.13%	$	11,737	$	11,669
Pollution Control Bonds (a)
	2011-2038 (b)	3.57%	0.06%-6.30%	0.29%-6.30%		2,112		2,263
Notes Payable (c)
	2011-2026	4.77%	2.029%-8.03%	2.07%-8.03%		402		396
Securitization Bonds
	2013-2020	5.36%	4.98%-6.25%	4.98%-6.25%		1,688		1,847
Junior Subordinated Debentures (d)
	2063	8.75%	8.75%	8.75%		315		315
Spent Nuclear Fuel Obligation (e)						265		265
Other Long-term Debt
	2011-2059	6.07%	3.00%-13.718%	1.3125%-13.718%		29		91
Fair Value of Interest Rate Hedges						7		6
Unamortized Discount, Net						(39)		(41)
Total Long-term Debt Outstanding						16,516		16,811
Long-term Debt Due Within One Year						1,433		1,309
Long-term Debt					$	15,083	$	15,502

(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, standby bond purchase agreements 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 our 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) Debentures will mature on March 1, 2063, subject to extensions to no later than March 1, 2068, and are callable at par any time on or after March 1, 2013.

(e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see "SNF Disposal" section of Note 5).

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Long-term debt outstanding at December 31, 2011 is payable as follows:

											After
	2012		2013		2014		2015		2016		2016		Total
	(in millions)
Principal Amount	$	1,433	$	1,383	$	1,074	$	1,496	$	712	$	10,457	$	16,555
Unamortized Discount, Net														(39)
Total Long-term Debt Outstanding													$	16,516

In January 2012, TCC retired $98 million of its outstanding Securitization Bonds.

In January and February 2012, I&M retired $2 million and $12 million, respectively, of Notes Payable related to DCC Fuel.

In February 2012, SWEPCo issued $275 million of 3.55% Senior Unsecured Notes due in 2022 and $65 million of 4.58% Notes Payable due in 2032.

In February 2012, APCo retired $30 million of 6.05% Pollution Control Bonds due in 2024 and $19.5 million of 5% Pollution Control Bonds due in 2021.  As of December 31, 2011, these bonds were classified for maturity purposes as Long-term Debt Due Within One Year on our balance sheet.

As of December 31, 2011, trustees held, on our behalf, $478 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.

We have issued $315 million of Junior Subordinated Debentures.  The debentures will mature on March 1, 2063, subject to extensions to no later than March 1, 2068, and are callable at par any time on or after March 1, 2013.  We have the option to defer interest payments on the debentures for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire our common stock.  We do not anticipate any deferral of those interest payments in the foreseeable future.

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%.  At December 31, 2011, 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 $6 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 value of the common stock.  This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings.

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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, 2011, we had credit facilities totaling $3.25 billion to support our commercial paper program.  The maximum amount of commercial paper outstanding during 2011 was $1.2 billion and the weighted average interest rate of commercial paper outstanding during the year was 0.4%.  Our outstanding short-term debt was as follows:

	December 31,
	2011				2010
	Outstanding		Interest		Outstanding		Interest
Type of Debt	Amount		Rate (a)		Amount		Rate (a)
	(in millions)				(in millions)
Securitized Debt for Receivables (b)	$	666	0.27	%	$	690	0.31	%
Commercial Paper		967	0.51	%		650	0.52	%
Line of Credit – Sabine (c)		17	1.79	%		6	2.15	%
Total Short-term Debt	$	1,650			$	1,346

(a) Weighted average rate.

(b) Amount of securitized debt for receivables as accounted for under the "Transfers and Servicing" accounting guidance.

(c) This line of credit does not reduce available liquidity under AEP's credit facilities.

Credit Facilities

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

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.

In July 2011, AEP Credit renewed its receivables securitization agreement.  The agreement provides commitments of $750 million from bank conduits to finance receivables from AEP Credit with an increase to $800 million for the months of July, August and September to accommodate seasonal demand.  A commitment of $375 million, with the seasonal increase to $425 million for the months of July, August and September, expires in June 2012 and the remaining commitment of $375 million expires in June 2014.

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Accounts receivable information for AEP Credit is as follows:

		Years Ended December 31,
		2011			2010			2009
		(dollars in millions)
Proceeds from Sale of Accounts Receivable		$	NA		$	NA		$	7,043
Loss on Sale of Accounts Receivable			NA			NA			3
Average Variable Discount Rate on Sale of
	Accounts Receivable		NA			NA			0.57	%
Effective Interest Rates on Securitization of
	Accounts Receivable		0.27	%		0.31	%		NA
Net Uncollectible Accounts Receivable Written Off			37			22			28
NA   Not Applicable

		December 31,
		2011			2010
		(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
	Less Uncollectible Accounts	$	902	$	923
Total Principal Outstanding			666		690
Delinquent Securitized Accounts Receivable			38		50
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable			18		26
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable			370		354

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.

14.  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 20,000,000 shares of AEP common stock for various types of stock-based compensation awards, including stock options, to employees.  A maximum of 10,000,000 shares may be used under this plan for full value share awards, which includes performance units, restricted shares and restricted stock units.  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 the Board of Directors (HR Committee).

Stock Options

We did not grant stock options in 2011, 2010 or 2009 but we do have outstanding stock options from grants in earlier periods that vested or were exercised in these years.  The exercise price of all outstanding stock options equaled or exceeded the market price of AEP’s common stock on the date of grant.  All outstanding stock options were granted with a ten-year term and generally vested, subject to the participant’s continued employment, in approximately equal 1/3 increments on January 1st of the year following the first, second and third anniversary of the grant date.  We record 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 fair value of stock options vested and the total intrinsic value of options exercised are as follows:

	Years Ended December 31,
Stock Options	2011			2010			2009
	(in thousands)
Fair Value of Stock Options Vested		$	-		$	-		$	25
Intrinsic Value of Options Exercised (a)			1,202			2,058			106

(a) Intrinsic value is calculated as market price at exercise dates less the option exercise price.

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A summary of AEP stock option transactions during the years ended December 31, 2011, 2010 and 2009 is as follows:

		2011			2010			2009
			Weighted			Weighted			Weighted
			Average			Average			Average
			Exercise			Exercise			Exercise
		Options	Price		Options	Price		Options	Price
		(in thousands)			(in thousands)			(in thousands)
Outstanding at January 1,		551	$	32.88	1,089	$	32.78	1,128	$	32.73
	Granted	-		NA	-		NA	-		NA
	Exercised/Converted	(104)		27.39	(448)		31.53	(21)		27.20
	Forfeited/Expired	(126)		46.40	(90)		38.44	(18)		36.28
Outstanding at December 31,		321		29.35	551		32.88	1,089		32.78
Options Exercisable at December 31,		321	$	29.35	551	$	32.88	1,089	$	32.78
NA   Not Applicable

The following table summarizes information about AEP stock options outstanding and exercisable at December 31, 2011:

	Number	Weighted
	of Options	Average	Weighted
2011 Range of	Outstanding	Remaining	Average		Aggregate
Exercise Prices	and Exercisable	Life	Exercise Price		Intrinsic Value
	(in thousands)	(in years)			(in thousands)
$27.06-27.95	162	1.27	$	27.47	$	2,240
$30.76-38.65	159	2.12		31.26		1,599
Total	321	1.69		29.35	$	3,839

We include the proceeds received from exercised stock options in common stock and paid-in capital.

Performance Units

Our performance units have a value upon vesting equal to the market value of shares of AEP common stock.  The number of performance units held is multiplied by the performance score to determine the actual number of performance units realized.  The performance score 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 and can range from 0% to 200%.  For the three-year performance and vesting period ending on December 31, 2009, performance units were paid in cash or stock at the employee’s election unless they were needed to satisfy a participant’s stock ownership requirement.  For the three-year performance and vesting periods ending on December 31, 2010 and 2011, performance units were paid in cash, unless they were 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 was mandatorily deferred as AEP Career Shares until after the end of the participant’s AEP career.  AEP Career Shares are a form of non-qualified deferred compensation that have 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 recorded compensation cost for performance units over the three-year vesting period.  The liability for both the performance units and AEP Career Shares, recorded in Employee Benefits and Pension Obligations on our 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.

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The HR Committee awarded performance units and reinvested dividends on outstanding performance units and AEP Career Shares for the years ended December 31, 2011, 2010 and 2009 as follows:

	Years Ended December 31,
Performance Units	2011		2010		2009
Awarded Units (in thousands)		7		736		1,179
Weighted Average Unit Fair Value at Grant Date	$	38.39	$	35.43	$	34.32
Vesting Period (in years)		3		3		3
Performance Units and AEP Career Shares	Years Ended December 31,
(Reinvested Dividends Portion)	2011		2010		2009
Awarded Units (in thousands)		198		211		224
Weighted Average Grant Date Fair Value	$	37.31	$	34.70	$	28.82
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.

In January 2012, the HR Committee awarded 545,685 units of performance units at a grant price of $41.38 for the three-year performance and vesting period ending on December 31, 2014.

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 value of final awards, but may not increase them.  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 utility and multi utility sub-industry segments of the 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 value of each performance unit earned is equal to the average closing price of AEP common stock for the last 20 trading days of the performance period.

The certified performance scores and units earned for the three-year period ended December 31, 2011, 2010 and 2009 were as follows:

		Years Ended December 31,
		2011		2010		2009
Certified Performance Score		89.8	%	55.8	%	73.5	%
Performance Units Earned		1,216,926		489,013		593,175
Performance Units Mandatorily Deferred as AEP Career Shares		52,639		33,501		26,635
Performance Units Voluntarily Deferred into the Incentive
	Compensation Deferral Program	42,502		6,583		27,855
Performance Units to be Paid in Cash		1,121,785		448,929		538,685

The cash payouts for the years ended December 31, 2011, 2010 and 2009 were as follows:

	Years Ended December 31,
	2011		2010		2009
	(in thousands)
Cash Payouts for Performance Units	$	15,985	$	18,683	$	30,034
Cash Payouts for AEP Career Share Distributions		2,777		3,594		2,184

137

Restricted Shares and Restricted Stock Units

The independent members of the AEP Board of Directors granted 300,000 restricted shares to the then Chairman, President and CEO on January 2, 2004 upon the commencement of his AEP employment.  Of these restricted shares, 50,000 vested on January 1, 2005, 50,000 vested on January 1, 2006, 66,666 vested on November 30, 2009, 66,667 vested on November 30, 2010 and 66,667 vested on November 30, 2011.   Compensation cost for restricted shares is measured at fair value on the grant date and recorded over the vesting period.  Fair value is determined by multiplying the number of shares granted by the grant date market closing price, which was $30.76.  The maximum term for these restricted shares was eight years and dividends on these restricted shares were paid in cash.  AEP has not granted other restricted shares.

The HR Committee also 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.  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.  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 of RSUs to four CEO succession candidates to better ensure the retention of 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.

The HR Committee awarded RSUs, including units awarded for dividends, for the years ended December 31, 2011, 2010 and 2009 as follows:

	Years Ended December 31,
Restricted Stock Units	2011		2010		2009
Awarded Units (in thousands)		121		873		130
Weighted Average Grant Date Fair Value	$	37.07	$	35.24	$	29.29

In January 2012, the HR Committee awarded 363,790 units of restricted stock units at a grant price of $41.38, which vest in three approximately equal annual increments on May 1, 2013, 2014 and 2015.

The total fair value and total intrinsic value of restricted shares and restricted stock units vested during the years ended December 31, 2011, 2010 and 2009 were as follows:

	Years Ended December 31,
Restricted Shares and Restricted Stock Units	2011		2010		2009
	(in thousands)
Fair Value of Restricted Shares and Restricted Stock Units Vested	$	7,164	$	6,044	$	6,573
Intrinsic Value of Restricted Shares and Restricted Stock Units Vested (a)		8,017		5,993		5,445

(a) Intrinsic value is calculated as market price at exercise date.

138

A summary of the status of our nonvested restricted shares and RSUs as of December 31, 2011 and changes during the year ended December 31, 2011 are as follows:

		Weighted
		Average
Nonvested Restricted Shares and		Grant Date
Restricted Stock Units	Shares/Units	Fair Value
	(in thousands)
Nonvested at January 1, 2011	1,026	$	34.88
Granted	121		37.07
Vested	(213)		33.61
Forfeited	(31)		35.35
Nonvested at December 31, 2011	903		35.46

The total aggregate intrinsic value of nonvested restricted shares and RSUs as of December 31, 2011 was $37 million and the weighted average remaining contractual life was 2.32 years.

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 non-employee directors vest immediately upon award of the stock units.  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 recorded the compensation cost for stock units when the units are awarded and adjusted the liability for changes in value based on the current 20-day average closing price of AEP common stock at the date of valuation.

We had no material cash payouts for stock unit distributions for the years ended December 31, 2011, 2010 and 2009.

The Board of Directors awarded stock units, including units awarded for dividends, for the years ended December 31, 2011, 2010 and 2009 as follows:

	Years Ended December 31,
Stock Unit Accumulation Plan for Non-Employee Directors	2011		2010		2009
Awarded Units (in thousands)		52		54		56
Weighted Average Grant Date Fair Value	$	37.72	$	34.67	$	29.56

139

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, 2011, 2010 and 2009 were as follows:

	Years Ended December 31,
Share-based Compensation Plans	2011		2010		2009
	(in thousands)
Compensation Cost for Share-based Payment Arrangements (a)	$	61,807	$	28,116	$	31,165
Actual Tax Benefit Realized		21,632		9,841		10,908
Total Compensation Cost Capitalized		11,608		4,689		5,956

(a) Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on our statements of income.

During the years ended December 31, 2011, 2010 and 2009, there were no significant modifications affecting any of our share-based payment arrangements.

As of December 31, 2011, there was $47 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 1.49 years.

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, 2011, 2010 and 2009 were as follows:

	Years Ended December 31,
Share-based Compensation Plans	2011		2010		2009
	(in thousands)
Cash Received from Stock Options Exercised	$	2,855	$	14,134	$	567
Actual Tax Benefit Realized for the Tax Deductions from Stock Options Exercised		411		706		35

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.

140

15.  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 as follows:

2011	Regulated												Nonregulated
						Annual											Annual
Functional	Property,					Composite							Property,				Composite
Class of	Plant and			Accumulated		Depreciation				Depreciable			Plant and		Accumulated		Depreciation				Depreciable
Property	Equipment			Depreciation		Rate Ranges				Life Ranges			Equipment		Depreciation		Rate Ranges				Life Ranges
	(in millions)									(in years)			(in millions)								(in years)
Generation	$	14,804		$	6,692	1.6	-	3.8	%	9	-	132	$	10,134	$	3,904	2.6	-	3.5	%	20	-	66
Transmission		9,048			2,600	1.3	-	2.7	%	25	-	87		-		-	-	-	-	%	-	-	-
Distribution		14,783			3,828	2.4	-	4.0	%	11	-	75		-		-	-	-	-	%	-	-	-
CWIP		2,913	(a)		36	NM				NM				208		1	NM				NM
Other		2,587			1,246	1.7	-	9.3	%	5	-	55		1,193		392	NM				NM
Total	$	44,135		$	14,402								$	11,535	$	4,297

2010	Regulated												Nonregulated
						Annual											Annual
Functional	Property,					Composite							Property,				Composite
Class of	Plant and			Accumulated		Depreciation				Depreciable			Plant and		Accumulated		Depreciation				Depreciable
Property	Equipment			Depreciation		Rate Ranges				Life Ranges			Equipment		Depreciation		Rate Ranges				Life Ranges
	(in millions)									(in years)			(in millions)								(in years)
Generation	$	14,147		$	6,537	1.6	-	3.8	%	9	-	132	$	10,205	$	3,788	2.2	-	5.1	%	20	-	70
Transmission		8,576			2,481	1.4	-	3.0	%	25	-	87		-		-	-	-	-	%	-	-	-
Distribution		14,208			3,607	2.4	-	3.9	%	11	-	75		-		-	-	-	-	%	-	-	-
CWIP		2,615	(a)		47	NM				NM				143		9	NM				NM
Other		2,685			1,268	3.0	-	12.5	%	5	-	55		1,161		329	NM				NM
Total	$	42,231		$	13,940								$	11,509	$	4,126

2009		Regulated							Nonregulated
		Annual							Annual
		Composite							Composite
		Depreciation				Depreciable			Depreciation				Depreciable
Functional Class of Property		Rate Ranges				Life Ranges			Rate Ranges				Life Ranges
						(in years)							(in years)
Generation		1.6	-	3.8	%	9	-	132	1.9	-	3.3	%	20	-	70
Transmission		1.4	-	2.7	%	25	-	87	-	-	-	%	-	-	-
Distribution		2.4	-	3.9	%	11	-	75	-	-	-	%	-	-	-
CWIP		NM				NM			NM				NM
Other		4.2	-	12.8	%	5	-	55	NM				NM
(a)	Includes CWIP related to SWEPCo's Arkansas jurisdictional share of the Turk Plant.
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.

141

For rate-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.

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 2011 and 2010 aggregate carrying amounts of ARO:

	Carrying
	Amount
	of ARO
	(in millions)
ARO at December 31, 2009	$	1,259
DHLC Deconsolidation (a)		(12)
Accretion Expense		75
Liabilities Incurred		32
Liabilities Settled		(20)
Revisions in Cash Flow Estimates		64
ARO at December 31, 2010 (b)		1,398
Accretion Expense		82
Liabilities Incurred		7
Liabilities Settled		(26)
Revisions in Cash Flow Estimates		13
ARO at December 31, 2011 (c)	$	1,474

(a) We deconsolidated DHLC effective January 1, 2010 in accordance with the accounting guidance for "Consolidations."  As a result, we record only 50% of the final reclamation based on our share of the obligation instead of the previous 100%.

(b) The current portion of our ARO, totaling $4 million, is included in Other Current Liabilities on our 2010 balance sheet.

(c) The current portion of our ARO, totaling $2 million, is included in Other Current Liabilities on our 2011 balance sheet.

As of December 31, 2011 and 2010, our ARO liability was $1.5 billion and $1.4 billion, respectively, and included $979 million and $930 million, respectively, for nuclear decommissioning of the Cook Plant.  As of December 31, 2011 and 2010, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $1.3 billion and $1.2 billion, respectively, and are recorded in Spent Nuclear Fuel and Decommissioning Trusts on our balance sheets.

142

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,
	2011			2010			2009
	(in millions)
Allowance for Equity Funds Used During Construction		$	98		$	77		$	82
Allowance for Borrowed Funds Used During Construction			63			53			67

143

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 in our statements of income and the investments and accumulated depreciation are reflected in our balance sheets under Property, Plant and Equipment as follows:

					Company’s Share at December 31, 2011
							Construction
	Fuel	Percent of			Utility Plant		Work in		Accumulated
	Type	Ownership			in Service		Progress		Depreciation
					(in millions)
W.C. Beckjord Generating Station (Unit No. 6) (a)	Coal		12.5	%	$	19	$	-	$	8
Conesville Generating Station (Unit No. 4) (b)	Coal		43.5	%		310		12		54
J.M. Stuart Generating Station (c)	Coal		26.0	%		529		13		172
Wm. H. Zimmer Generating Station (a)	Coal		25.4	%		771		20		377
Dolet Hills Generating Station (Unit No. 1) (f)	Lignite		40.2	%		264		-		193
Flint Creek Generating Station (Unit No. 1) (g)	Coal		50.0	%		118		6		63
Pirkey Generating Station (Unit No. 1) (g)	Lignite		85.9	%		513		1		362
Oklaunion Generating Station (Unit No. 1) (e)	Coal		70.3	%		401		2		208
Turk Generating Plant (h)	Coal		73.33	%		-		1,326		-
Transmission	NA	(d)				63		6		50

					Company’s Share at December 31, 2010
							Construction
	Fuel	Percent of			Utility Plant		Work in		Accumulated
	Type	Ownership			in Service		Progress		Depreciation
					(in millions)
W.C. Beckjord Generating Station (Unit No. 6) (a)	Coal		12.5	%	$	19	$	-	$	8
Conesville Generating Station (Unit No. 4) (b)	Coal		43.5	%		301		8		49
J.M. Stuart Generating Station (c)	Coal		26.0	%		507		23		163
Wm. H. Zimmer Generating Station (a)	Coal		25.4	%		771		10		366
Dolet Hills Generating Station (Unit No. 1) (f)	Lignite		40.2	%		258		5		192
Flint Creek Generating Station (Unit No. 1) (g)	Coal		50.0	%		116		7		62
Pirkey Generating Station (Unit No. 1) (g)	Lignite		85.9	%		503		10		358
Oklaunion Generating Station (Unit No. 1) (e)	Coal		70.3	%		395		4		201
Turk Generating Plant (h)	Coal		73.33	%		-		971		-
Transmission	NA	(d)				63		3		48

(a)	Operated by Duke Energy Corporation, a nonaffiliated company.
(b)	Operated by OPCo.
(c)	Operated by The Dayton Power & Light Company, a nonaffiliated company.
(d)	Varying percentages of ownership.
(e)	Operated by PSO and also jointly-owned (54.7%) by TNC.
(f)	Operated by CLECO, a nonaffiliated company.
(g)	Operated by SWEPCo.
(h)	Turk Generating Plant is currently under construction with a projected commercial operation date in the fourth quarter of 2012.  SWEPCo jointly owns the plant with Arkansas Electric Cooperative Corporation (11.67%), East Texas Electric Cooperative (8.33%) and Oklahoma Municipal Power Authority (6.67%).  Through December 2011, construction costs totaling $374 million have been billed to the other owners.
NA	Not Applicable

144

16.  COST REDUCTION INITIATIVES

In April 2010, we began initiatives to decrease both labor and non-labor expenses with a goal of achieving significant reductions in operation and maintenance expenses.  A total of 2,461 positions was eliminated across the AEP System as a result of process improvements, streamlined organizational designs and other efficiencies.  Most of the affected employees terminated employment May 31, 2010.  The severance program provided two weeks of base pay for every year of service along with other severance benefits.

We recorded a charge of $293 million to Other Operation expense during 2010 primarily related to severance benefits as the result of headcount reduction initiatives.

The following table shows the cost reduction activity for the year ended December 31, 2011:

	Total
	(in millions)
Balance as of December 31, 2010	$	17
Incurred		-
Settled		(15	)
Adjustments		(2	)
Balance as of December 31, 2011	$	-

145

17.  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 net income 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:

			2011 Quarterly Periods Ended
			March 31		June 30		September 30			December 31
			(in millions - except per share amounts)
Total Revenues			$	3,730	$	3,609	$	4,333		$	3,444
Operating Income				832		717		890	(a)		343	(b)
Income Before Extraordinary Items				355		353		657	(a) (c)		211	(b) (c)
Extraordinary Items, Net of Tax				-		-		273	(c)		100	(c)
Net Income				355		353		930	(a) (c)		311	(b) (c)
Amounts Attributable to AEP Common Shareholders:
		Income Before Extraordinary Items		353		352		655	(a) (c)		208	(b) (c)
		Extraordinary Items, Net of Tax		-		-		273	(c)		100	(c)
		Net Income		353		352		928	(a) (c)		308	(b) (c)
Basic Earnings per Share Attributable to AEP
	Common Shareholders:
		Earnings per Share Before Extraordinary Items		0.73		0.73		1.35			0.43
		Extraordinary Items per Share		-		-		0.57			0.20
		Earnings per Share (f)		0.73		0.73		1.92			0.63
Diluted Earnings per Share Attributable to AEP
	Common Shareholders:
		Earnings per Share Before Extraordinary Items		0.73		0.73		1.35			0.43
		Extraordinary Items per Share		-		-		0.57			0.20
		Earnings per Share (f)		0.73		0.73		1.92			0.63

			2010 Quarterly Periods Ended
			March 31		June 30			September 30		December 31
			(in millions - except per share amounts)
Total Revenues			$	3,569	$	3,360		$	4,064	$	3,434
Operating Income				758		394	(d)		1,025		486	(e)
Net Income				346		137	(d)		557		178	(e)
Amounts Attributable to AEP Common Shareholders:
		Net Income		344		136	(d)		555		176	(e)
Basic Earnings per Share Attributable to AEP
	Common Shareholders:
		Earnings per Share (f)		0.72		0.28			1.16		0.37
Diluted Earnings per Share Attributable to AEP
	Common Shareholders:
		Earnings per Share (f)		0.72		0.28			1.16		0.37

(a) Includes pretax write-offs for plant impairments (see Note 6) and a provision for refund of POLR charges in Ohio (see Note 3).

(b) Includes a refund of POLR charges in Ohio (see Note 3) and OPCo adjustments for fuel disallowances, the 2010 SEET and the obligation to contribute to Partnership with Ohio and Ohio Growth Fund.  Also includes a write-off for SWEPCo's Turk Plant (see Note 6).

(c) See "TCC Texas Restructuring" section of Note 2 and "Texas Restructuring" section of Note 3 for discussion of gains recorded in the third and fourth quarters of 2011.

(d) See Note 16 for discussion of expenses related to cost reduction initiatives in 2010.

(e) Includes a $43 million refund provision for the 2009 SEET in addition to various other provisions for certain regulatory and legal matters.

(f) Quarterly Earnings per Share amounts are meant to be stand-alone calculations and are not always additive to full-year amount due to rounding.

146

18.  GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

The changes in our carrying amount of goodwill for the years ended December 31, 2011 and 2010 by operating segment are as follows:

	Utility		AEP River		AEP
	Operations		Operations		Consolidated
	(in millions)
Balance at December 31, 2009	$	37	$	39	$	76
Impairment Losses		-		-		-
Balance at December 31, 2010		37		39		76
Impairment Losses		-		-		-
Balance at December 31, 2011	$	37	$	39	$	76

In the fourth quarters of 2011 and 2010, 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 $1.2 million at December 31, 2010, net of accumulated amortization and are included in Deferred Charges and Other Noncurrent Assets on our balance sheets.  As of December 31, 2011, all acquired intangible assets were fully amortized.  The amortization life, gross carrying amount and accumulated amortization by major asset class are as follows:

		December 31,
		2011				2010
		Gross				Gross
	Amortization	Carrying		Accumulated		Carrying		Accumulated
	Life	Amount		Amortization		Amount		Amortization
	(in years)	(in millions)
Easements	10	$	2.2	$	2.2	$	2.2	$	2.2
Purchased Technology	10		10.9		10.9		10.9		9.7
Total		$	13.1	$	13.1	$	13.1	$	11.9

Amortization of intangible assets was $ 1 million, $1 million and $3 million for 2011, 2010 and 2009, respectively.

Other than goodwill, we have no intangible assets that are not subject to amortization.

147

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; Julie Sherwood, 614-716-2663, jasherwood@AEP.com; or Sara Macioch, 614-716-2835, semacioch@AEP.com. Individual shareholders should contact Kathleen Kozero, 614-716-2819, klkozero@AEP.com.

Number of Shareholders – As of December 31, 2011, there were approximately 87,000 registered shareholders and approximately 407,000 shareholders holding stock in street name through a bank or broker. There were 483,422,868 shares outstanding at December 31, 2011.

Form 10-K – Upon request, we will provide without charge a copy of our Form 10-K for the fiscal year ended December 31, 2011. 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.

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Executive Leadership Team

Name	Age	Office
Nicholas K. Akins	51	President and Chief Executive Officer
Lisa M. Barton	46	Executive Vice President – Transmission
David M. Feinberg	42	Senior Vice President, General Counsel and Secretary
Mark C. McCullough	52	Executive Vice President – Generation
Robert P. Powers	57	Executive Vice President and Chief Operating Officer
Brian X. Tierney	44	Executive Vice President and Chief Financial Officer
Dennis E. Welch	60	Executive Vice President and Chief Administrative Officer

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