-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Shb+F+f8INtxgAebnvUIOZ3I5tGBg9SC+xtCfIBtiSDpxkigz/c4cZ6pHAamyQ5Q smJNCVFNf/QzVOh0cRuy6g== 0000912057-96-004713.txt : 19960320 0000912057-96-004713.hdr.sgml : 19960320 ACCESSION NUMBER: 0000912057-96-004713 CONFORMED SUBMISSION TYPE: DEF 14A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19960424 FILED AS OF DATE: 19960319 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: AMERICAN ELECTRIC POWER COMPANY INC CENTRAL INDEX KEY: 0000004904 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 134922640 STATE OF INCORPORATION: NY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: DEF 14A SEC ACT: 1934 Act SEC FILE NUMBER: 001-03525 FILM NUMBER: 96536051 BUSINESS ADDRESS: STREET 1: 1 RIVERSIDE PLZ CITY: COLUMBUS STATE: OH ZIP: 43215 BUSINESS PHONE: 6142231000 FORMER COMPANY: FORMER CONFORMED NAME: KINGSPORT UTILITIES INC DATE OF NAME CHANGE: 19660906 DEF 14A 1 DEF 14A SCHEDULE 14A INFORMATION Proxy Statement Pursuant to Section 14(a) of the Securities Exchange Act of 1934 (Amendment No. ) Filed by the Registrant /X/ Filed by a Party other than the Registrant / / Check the appropriate box: / / Preliminary Proxy Statement / / Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e)(2)) /X/ Definitive Proxy Statement / / Definitive Additional Materials / / Soliciting Material Pursuant to Section 240.14a-11(c) or Section 240.14a-12 American Electric Power Company, Inc. - -------------------------------------------------------------------------------- (Name of Registrant as Specified In Its Charter) - -------------------------------------------------------------------------------- (Name of Person(s) Filing Proxy Statement, if other than the Registrant) Payment of Filing Fee (Check the appropriate box): /X/ $125 per Exchange Act Rules 0-11(c)(1)(ii), 14a-6(i)(1), 14a-6(i)(2) or Item 22(a)(2) of Schedule 14A. / / $500 per each party to the controversy pursuant to Exchange Act Rule 14a-6(i)(3). / / Fee computed on table below per Exchange Act Rules 14a-6(i)(4) and 0-11. 1) Title of each class of securities to which transaction applies: ------------------------------------------------------------------------ 2) Aggregate number of securities to which transaction applies: ------------------------------------------------------------------------ 3) Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (Set forth the amount on which the filing fee is calculated and state how it was determined): ------------------------------------------------------------------------ 4) Proposed maximum aggregate value of transaction: ------------------------------------------------------------------------ 5) Total fee paid: ------------------------------------------------------------------------ / / Fee paid previously with preliminary materials. / / Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing. 1) Amount Previously Paid: ------------------------------------------------------------------------ 2) Form, Schedule or Registration Statement No.: ------------------------------------------------------------------------ 3) Filing Party: ------------------------------------------------------------------------ 4) Date Filed: ------------------------------------------------------------------------ NOTICE OF 1996 ANNUAL MEETING - PROXY STATEMENT AMERICAN ELECTRIC POWER COMPANY, INC. 1 Riverside Plaza Columbus, OH 43215 [LOGO] March 9, 1996 Dear Shareholder: This year's annual meeting of shareholders will be held in the Franklin Room of the Hyatt Regency Columbus, 350 North High Street, Columbus, Ohio, on Wednesday, April 24, 1996 at 9:30 a.m. Your Board of Directors and I cordially invite you to attend. During the course of the meeting there will be the usual time for discussion of the items on the agenda and for questions regarding the Company's affairs. Directors and officers will be available to talk individually with shareholders before and after the meeting. This year, the Company's audited financial statements and certain other financial information are included in Appendix A to this proxy statement. Including this financial information with the proxy statement allows for the use of a summary annual report. The Company's summary annual report contains my letter to shareholders, a review of operations, the summary management discussion and financial information and independent auditors' report. E. LINN DRAPER, JR. Chairman of the Board, President and Chief Executive Officer If you plan to attend the meeting and are a shareholder of record, please mark the "Annual Meeting" box on your proxy card. An admission ticket is included with the proxy card for each shareholder of record. However, if your shares are not registered in your own name, please advise the shareholder of record (your bank, broker, etc.) that you wish to attend. That firm must provide you with evidence of your ownership which will enable you to gain admittance to the meeting. IN ORDER TO ENSURE MAXIMUM SHAREHOLDER REPRESENTATION AT THE MEETING, I URGE EACH OF YOU, WHETHER OR NOT YOU EXPECT TO ATTEND IN PERSON, TO FILL IN, DATE, SIGN AND RETURN YOUR PROXY PROMPTLY IN THE ENCLOSED ENVELOPE. Sincerely, [SIGNATURE] NOTICE OF 1996 ANNUAL MEETING March 9, 1996 Columbus, Ohio THE ANNUAL MEETING of shareholders of AMERICAN ELECTRIC POWER COMPANY, INC., a New York corporation, will be held in the Franklin Room of the Hyatt Regency Columbus, 350 North High Street, Columbus, Ohio, on Wednesday, April 24, 1996 at 9:30 o'clock in the morning, for the following purposes: 1. To elect 12 directors to hold office until the next annual meeting and until their successors are duly elected; 2. To approve the firm of Deloitte & Touche LLP as independent auditors for the year 1996; and 3. To consider and act on such other matters as may properly come before the meeting. Only shareholders of record at the close of business on March 6, 1996 are entitled to notice of and to vote at the meeting or any adjournment thereof. G.P. Maloney SECRETARY PROXY STATEMENT March 9, 1996 THIS PROXY STATEMENT and the accompanying proxy card are to be mailed to shareholders, commencing on or about March 19, 1996, 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, 1996 in Columbus, Ohio. Only the holders of shares of Common Stock at the close of business on March 6, 1996 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 March 6, 1996, there were 186,635,000 shares of Common Stock, $6.50 par value, outstanding. When proxy cards are returned properly signed, the shares represented thereby will be voted by the persons named on the proxy card or by their substitutes in accordance with shareholders' directions. The proxy cards 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 March 6, 1996. Shareholders are urged to grant or withhold authority to vote for the nominees for directors listed on the proxy card and to specify their choice between approval or disapproval of, or abstention with respect to, the other matter by marking the appropriate box on the proxy card. 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. A shareholder giving a proxy may revoke it at any time before it is exercised at the meeting by giving notice of its revocation to the Company, by executing another proxy dated after the proxy to be revoked, or by attending the meeting and voting in person. ANNUAL REPORT. Securities and Exchange Commission rules require that an annual report precede or accompany proxy material. More than one annual report need not be sent to the same address, if the recipient agrees. If more than one annual report is being sent to your address, at your request, mailing of the duplicate copy to the account you select will be discontinued. You may so indicate in the space provided on the proxy card. Eliminating these duplicate mailings will not affect receipt of future proxy statements and proxy cards. 1. ELECTION OF DIRECTORS TWELVE DIRECTORS are to be elected by a plurality of the votes cast at the meeting to hold office until the next annual meeting and until their successors have been elected. The Restated Certificate of Incorporation of the Company provides that the number of directors of the Company shall be such number, not less than 12 nor more than 17, as shall be determined from time to time, as prescribed in the By-Laws, by resolution of the Board of Directors. On December 13, 1995, the Board of Directors adopted a resolution increasing the number of directors constituting the entire Board from 12 to 13, and elected Mr. Robert W. Fri to fill the vacancy thus created. In addition, on January 31, 1996, the Board of Directors adopted a resolution reducing the number of directors from 13 to 12, effective on the date of the annual meeting. Mr. Toy F. Reid, a director, will be retiring from the Board and not standing for reelection. The 12 nominees named on pages 3-5 were selected by the Board of Directors on the recommendation of the Committee on Directors of the Board. The proxies named on the proxy card or their substitutes will vote for the Board's nominees, unless instructed otherwise. Shareholders may withhold authority to vote for any or all of such nominees on the proxy card. Except for Mr. Robert W. Fri, who is standing for election for the first time, all of the Board's nominees were elected by the shareholders at the 1995 annual meeting. It is not expected that any of the nominees will be unable to stand for election or be unable to serve if elected. In the event that a vacancy in the slate of nominees should occur before the meeting, the proxies may be voted for another person nominated by the Board of Directors. Shareholders have the right to vote cumulatively for the election of directors. This means that in the voting at the meeting each shareholder, or his proxy, may multiply the number of his shares by 12 -- the number of directors to be elected -- and then cast the resulting total number of votes for a single nominee, or distribute such votes on the ballot among any two or more nominees as desired. The proxies designated by the Board of Directors will not cumulate the votes of the shares they represent. 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 the Company's Common Stock and stock-based units beneficially owned by each of them appears on pages 16 and 17. 2 NOMINEES FOR DIRECTOR PETER J. DEMARIA Received his B.A. in 1955 from Queens [PHOTO] CONTROLLER OF THE COMPANY; College and M.B.A. in 1963 from New York EXECUTIVE VICE PRESIDENT -- University. Certified Public Accountant ADMINISTRATION AND CHIEF (1965). Joined AEP Service Corporation in ACCOUNTING OFFICER, AEP SERVICE 1959. In 1978 became senior vice CORPORATION president and chief accounting officer of Age 61 AEP Service Corporation and treasurer of Director since 1993 the Company and in 1984 became executive vice president -- administration of AEP Service Corporation. Resigned as treasurer and became controller in November 1995. - ------------------------------------------------------------------------------------------- E. LINN DRAPER, JR. Received his B.A. and B.S. (chemical [PHOTO] CHAIRMAN, PRESIDENT AND CHIEF engineering) degrees from Rice University EXECUTIVE OFFICER OF THE COMPANY in 1964 and 1965, respectively, and Ph.D. AND AEP SERVICE CORPORATION; (nuclear engineering) in 1970 from CHAIRMAN AND CHIEF EXECUTIVE Cornell University. Joined Gulf States OFFICER OF ALL OTHER MAJOR Utilities Company, an unaffiliated COMPANY SUBSIDIARIES electric utility, in 1979. Chairman of Age 54 the board, president and chief executive Director since 1992 officer of Gulf States (1987-1992). Elected president of the Company and president and chief operating officer of AEP Service Corporation in March 1992 and chairman of the board and chief executive officer of the Company and all of its major subsidiaries in April 1993. A director of VECTRA Technologies, Inc. - ------------------------------------------------------------------------------------------- ROBERT M. DUNCAN Received his B.S. and J.D. from The Ohio [PHOTO] DIRECTOR AND TRUSTEE, State University in 1948 and 1952, COLUMBUS, OHIO respectively. After two years in the Age 68 private practice of law, held a series of Director since 1985 governmental legal positions culminating in service as a judge for the U.S. District Court for the Southern District of Ohio, a position held from 1974 to 1985. Private practice of law (1985-1991). Vice president and general counsel, The Ohio State University (1992-1994). A trustee of Nationwide Investing Foundation, Nationwide Investing Foundation II, Nationwide Separate Account Trust and Financial Horizons Investment Trust. A director of Nationwide Financial Services Inc. - ------------------------------------------------------------------------------------------- ROBERT W. FRI Holds a B.A. from Rice University and an SENIOR FELLOW, M.B.A. from Harvard Business School. RESOURCES FOR THE FUTURE, INC., Associated with McKinsey & Company, Inc., WASHINGTON, D.C. management consulting firm, from 1963 to Age 60 1971 and again from 1973 to 1975, being Director since December 1995 elected a principal in the firm in 1968. From 1971 to 1973, served as first Deputy Administrator of the Environmental Protection Agency, becoming Acting Administrator in 1973. Was first Deputy and then Acting Administrator of the Energy Research and Development Administration from 1975 to 1977. From 1978 to 1986 was President of Energy Transition Corporation. President and director of Resources for the Future (non-profit research organization) from 1986 to 1995. - -------------------------------------------------------------------------------------------
3 NOMINEES FOR DIRECTOR -- CONTINUED ARTHUR G. HANSEN Received his B.S.E.E. in 1946 and M.S. in [PHOTO] EDUCATIONAL CONSULTANT, 1948 from Purdue University, his Ph.D. ZIONSVILLE, INDIANA (mathematics) in 1958 from Case Western Age 71 Reserve University, and honorary doctoral Director since 1979 degrees in engineering and science from Purdue and Indiana universities. Was dean of the College of Engineering (1966-1969) and president (1969-1971) of Georgia Institute of Technology, president of Purdue University (1971-1982) and chancellor of The Texas A&M University System (1982-1986). Director of Research, Hudson Institute (1987-1988). Vice chairman, Indiana Commission for Higher Education (1995). A director of International Paper Company. - ------------------------------------------------------------------------------------------- LESTER A. HUDSON, JR. Received a B.A. from Furman University in [PHOTO] CHAIRMAN, H&E ASSOCIATES, 1961 and an M.B.A. from the University of GREENVILLE, SOUTH CAROLINA South Carolina in 1965. Joined Dan River Age 56 Inc. (textile fabric manufacturer) in Director since 1987 1970 and was elected president and chief operating officer in 1981 and chief executive officer in 1987. Resigned from Dan River in 1990. Joined WundaWeve Carpets, Inc. (carpet manufacturer) as chairman, president and chief executive officer in 1990. Chairman of WundaWeve in 1991. Vice chairman of WundaWeve, June 1993 through April 1995. Chairman, H&E Associates (investment firm), June 1995. A director of American National Bankshares Inc. - ------------------------------------------------------------------------------------------- GERALD P. MALONEY Holds B.S. degrees in both electrical [PHOTO] VICE PRESIDENT AND SECRETARY OF engineering and business administration THE COMPANY; EXECUTIVE VICE from Massachusetts Institute of PRESIDENT -- Technology (1955) and an M.B.A. from CHIEF FINANCIAL OFFICER, Rutgers University (1962). Joined AEP AEP SERVICE CORPORATION Service Corporation in 1955. In 1974 Age 63 became senior vice president -- finance Director since 1994 of AEP Service Corporation and vice president of the Company; in 1991 became executive vice president -- chief financial officer of AEP Service Corporation; and in 1994 became secretary of the Company. - ------------------------------------------------------------------------------------------- ANGUS E. PEYTON Graduated from Princeton University in [PHOTO] PARTNER, BROWN & PEYTON, 1949 and received his LL.B. from the ATTORNEYS, CHARLESTON, University of Virginia in 1952. Served as WEST VIRGINIA an assistant attorney general of West Age 69 Virginia (1956-1957), as chairman of the Director since 1978 West Virginia Industrial Development Authority, and as West Virginia Commerce Commissioner (1965-1969). Formed his present law firm in 1969. A director of One Valley Bancorp of West Virginia, Inc. - ------------------------------------------------------------------------------------------- DONALD G. SMITH Joined Roanoke Electric Steel Corporation [PHOTO] CHAIRMAN OF THE BOARD, (steel manufacturer) in 1957. Held PRESIDENT, CHIEF EXECUTIVE various positions with Roanoke Electric OFFICER AND TREASURER OF ROANOKE Steel before being named president and ELECTRIC STEEL CORPORATION, treasurer in 1985, chief executive ROANOKE, VIRGINIA officer in 1986 and chairman of the board Age 60 in 1989. Director since 1994 - -------------------------------------------------------------------------------------------
4 LINDA GILLESPIE STUNTZ Holds an A.B. from Wittenberg University [PHOTO] PARTNER, STUNTZ & DAVIS, P.C., (1976) and J.D. from Harvard Law School ATTORNEYS, WASHINGTON, D.C. (1979). Private practice of law Age 41 (1979-1981). U.S. House of Repre- Director since 1993 sentatives, Committee on Energy and Commerce: Associate Minority Counsel, Subcommittee on Fossil and Synthetic Fuels (1981-1986) and Minority Counsel and Staff Director (1986-1987). Private practice of law (1987-1989). U.S. Department of Energy (1989-1993): Acting Deputy Secretary (January 1992-July 1992) and Deputy Secretary (July 1992-January 1993). Returned to the private practice of law in March 1993. A director of Schlumberger Limited. Member, Advisory Council, Electric Power Research Institute. - ------------------------------------------------------------------------------------------- MORRIS TANENBAUM Graduated from The Johns Hopkins [PHOTO] VICE PRESIDENT, NATIONAL ACADEMY University in 1949 with a B.A. in OF ENGINEERING, chemistry and received a Ph.D. in SHORT HILLS, NEW JERSEY physical chemistry in 1952 from Princeton Age 67 University. Joined Bell Telephone Director since 1989 Laboratories in 1952 and held various positions with AT&T companies. Became vice chairman of the board of AT&T in 1986 and chief financial officer in 1988. Retired in 1991. A director of Cabot Corporation. A trustee of Battelle Memorial Institute, Massachusetts Insti- tute of Technology and The Johns Hopkins University and honorary trustee of The Brookings Institution. - ------------------------------------------------------------------------------------------- ANN HAYMOND ZWINGER Received her B.A. in art history with [PHOTO] AUTHOR, ILLUSTRATOR AND honors from Wellesley College (1946) and CONSULTANT, M.A. in art history from Indiana COLORADO SPRINGS, COLORADO University (1950). Adjunct professor at Age 71 Colorado College. Books include BEYOND Director since 1977 THE ASPEN GROVE, 1970, RUN, RIVER, RUN, 1975, which received the Friends of American Writers Award for nonfiction and John Burroughs Award and DOWNCANYON: A NATURALIST EXPLORES THE COLORADO RIVER THROUGH THE GRAND CANYON, 1995, which re- ceived the Western Arts Federation Award for nonfiction. In March 1996 received Orion Society's Award recognizing achievement in nature writing, environmental education and conservation. Member of founding board, Utility Women's Conference. Secretary, Colorado Board, The Nature Conservancy. - -------------------------------------------------------------------------------------------
Dr. Draper and Messrs. DeMaria and Maloney are directors of Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company (all of which are subsidiaries of the Company with one or more classes of publicly held preferred stock or debt securities) and other subsidiaries of the Company. Dr. Draper and Messrs. DeMaria and Maloney are also directors of AEP Generating Company, a subsidiary of the Company. FUNCTIONS OF THE BOARD OF DIRECTORS AND COMMITTEES UNDER NEW YORK LAW, the Company 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 1995, the Board held eight regular meetings. The Board has six standing committees, the functions of which are described in the following paragraphs. The AUDIT COMMITTEE consists of Messrs. Duncan, Hudson and Peyton and Ms. Zwinger. The Audit Committee oversees, and 5 reports to the Board concerning, the general policies and practices of the Company and its subsidiaries with respect to accounting, financial reporting, and internal auditing and financial controls. It also maintains a direct exchange of information between the Board and the Company's independent accountants and reviews possible conflict of interest situations involving directors. During 1995 the Audit Committee held five meetings. The COMMITTEE ON DIRECTORS consists of Messrs. Duncan and Hudson, Dr. Hansen and Mses. Stuntz and Zwinger. The Committee on Directors is responsible for: (i) recommending the size of the Board within the boundaries imposed by the corporate charter; (ii) recommending selection criteria for nominees for election or appointment to the Board; (iii) conducting independent searches for qualified nominees and screening the qualifications of candidates recommended by others; and (iv) recommending to the Board for its consideration one or more nominees for appointment to fill vacancies on the Board as they occur and the slate of nominees for election at the annual meeting. During 1995 the Committee on Directors held two meetings. The Committee on Directors will consider shareholder recommendations of candidates to be nominated as directors of the Company. All such recommendations must be in writing and addressed to the Secretary of the Company. By accepting a shareholder recommendation for consideration, the Committee on Directors does not undertake to adopt or take any other action concerning the recommendation, or to give the proponent its reasons for not doing so. The CORPORATE PUBLIC POLICY COMMITTEE consists of Messrs. Duncan, Fri, Hudson, Peyton, Reid and Smith and Drs. Hansen and Tanenbaum and Mses. Stuntz and Zwinger. The Corporate Public Policy Committee is responsible for examining the Company's policies on major public issues affecting the AEP System, as well as established System policies which affect the relationship of the Company and its subsidiaries to their service areas and the general public; for reporting periodically and on request to the Board and providing recommendations to the Board on such policy matters; and for counseling the management of the AEP System on any such policy matters presented to the Committee for consideration and study. During 1995 the Corporate Public Policy Committee held three meetings. The EXECUTIVE COMMITTEE consists of Dr. Draper and Messrs. Peyton and Reid. It is empowered to exercise all the authority of the Board of Directors, subject to certain limitations prescribed in the By-Laws, during the intervals between meetings of the Board. Meetings of the Executive Committee are convened only in extraordinary circumstances. The Executive Committee did not meet during 1995. The FINANCE COMMITTEE consists of Messrs. Peyton, Reid and Smith, Ms. Stuntz and Dr. Tanenbaum. The Finance Committee monitors and reports to the Board with respect to the capital requirements and financing plans and programs of the Company and its subsidiaries including, among other things, reviewing and making such recommendations as it considers appropriate concerning the short and long-term financing plans and programs of the Company and its subsidiaries and the implementation of the same. During 1995 the Finance Committee held five meetings. The HUMAN RESOURCES COMMITTEE consists of Drs. Hansen and Tanenbaum and Messrs. Reid and Smith. The Human Resources Committee is responsible for: (i) reviewing the salaries and other compensation and benefits provided to members of the Board who are officers of the Company or employees of any of its subsidiaries, and recommending to the Board for approval the amount of salary, compensation and benefits to be paid to such persons each year; (ii) reviewing management proposals concerning salaries, compensation and benefits to be paid to senior officers of AEP Service Corporation; (iii) reviewing and making recommendations to the Board with respect to the compensation of directors; (iv) evaluating the Company's hiring, development, promotional and succession planning practices for those management positions described in (ii) above; and (v) periodic review of the Company's overall affirmative action performance. During 1995 the Human Resources Committee held four meetings. During 1995, no incumbent director attended fewer than 75% of the aggregate of the total number of meetings of the Board of Directors and the total number of meetings held by all Committees on which he or she served. 6 COMPENSATION OF DIRECTORS DIRECTORS who are officers of the Company or employees of any of its subsidiaries do not receive any compensation, other than their regular salaries and the accident insurance coverage described below, for attending meetings of the Board of Directors of the Company. The other members of the Board receive an annual retainer of $23,000 for their services, an additional annual retainer of $3,000 for each Committee that they chair, a fee of $1,000 for each meeting of the Board and of any Committee that they attend (except a meeting of the Executive Committee held on the same day as a Board meeting), and a fee of $1,000 per day for any inspection trip or conference (except a trip or conference on the same day as a Board or Committee meeting). The Company maintains a group 24-hour accident insurance policy to provide a $1,000,000 accidental death benefit for each director (three-year premium was $16,065). The current policy will expire on September 1, 1997, and the Company expects to renew the coverage. In addition, the Company pays each director (excluding officers of the Company or employees of any of its subsidiaries) an amount to provide for the federal and state income taxes incurred in connection with the maintenance of this coverage (approximately $500 annually). The Board has adopted a policy which permits directors to elect annually to defer receipt of all or a portion of their retainer and fees to be payable in a lump sum or monthly installments after they cease to be a director. The deferred compensation accrues interest compounded quarterly at the daily prime lending rate in effect from time to time at a specified major financial institution. This policy is implemented by individual deferred-compensation agreements which set forth the terms of the deferral. The Board has adopted a retirement plan for directors (excluding officers of the Company or employees of any of its subsidiaries) which provides for annual retirement payments for life to such directors commencing at the later of the director's retirement or age 72 in an amount equal to the annual Board retainer at the time of retirement with a 20% reduction for each year that service as a director is less than five. OTHER MATTERS THE DIRECTORS and officers of the Company and its subsidiaries are insured, subject to certain exclusions, against losses resulting from any claim or claims made against them while acting in their capacities as directors and officers. The American Electric Power System companies are also insured, subject to certain exclusions and deductibles, to the extent that they have indemnified their directors and officers for any such losses. Such insurance is provided by Associated Electric & Gas Insurance Services, Energy Insurance Mutual, The Chubb Insurance Company and Great American Insurance Company, effective January 1, 1996 through December 31, 1996, and pays up to an aggregate amount of $100,000,000 on any one claim and in any one policy year. The total premium for the four policies is $1,424,124. Fiduciary liability insurance provides coverage for System companies, 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. This coverage, provided by Federal Insurance Company, was renewed, effective July 1, 1995 through June 30, 1996, for a premium of $70,500. It provides $20,000,000 of aggregate coverage with a $5,000 deductible for each loss. 2. APPROVAL OF AUDITORS ON THE RECOMMENDATION of the Audit Committee, the Board of Directors has appointed the accounting firm of Deloitte & Touche LLP as independent auditors of the Company for the year 1996, subject to approval by the shareholders at the annual meeting. Deloitte & Touche LLP is considered to be the firm best qualified to perform this important function because of its ability and the familiarity of its personnel with the Company's affairs. It and predecessor firms have been the Company's auditors since 1911. Approval of this proposal requires the affirmative vote of holders of a majority of the shares present in person or by proxy at the meeting. Fees billed by Deloitte & Touche LLP for auditing and other professional services rendered to the Company and its subsidiaries during 1995 were $3,149,000. 7 Representatives of Deloitte & Touche LLP will be present at the meeting and will have an opportunity to make a statement if they desire to do so. They also will be available to answer appropriate questions. YOUR BOARD OF DIRECTORS RECOMMENDS A VOTE FOR APPROVAL OF DELOITTE & TOUCHE LLP AS INDEPENDENT AUDITORS FOR 1996. OTHER BUSINESS THE BOARD OF DIRECTORS does not intend to present to the meeting any business other than the election of directors and the approval of auditors. 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 enclosed 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. VOTING PROCEDURES UNDER NEW YORK LAW, abstentions and broker non-votes do not count in the determination of voting results and have no effect on the vote. The determination by the shareholders of approval of the auditors is based on votes "for" and "against" -- with abstentions and broker non-votes not counted as "against" votes but counted in the determination of a quorum. Unvoted shares are termed "non-votes" when a nominee holding shares for beneficial owners may not have received instructions from the beneficial owner and may not have exercised discretionary voting power on certain matters, but with respect to other matters may have voted pursuant to discretionary authority or instructions from the beneficial owner. It is the policy of the Company that shareholders be provided privacy in voting. All proxy (voting instruction) cards and ballots, which identify shareholders, are held confidential, except as may be necessary to meet any applicable legal requirements. Proxy cards are returned in envelopes addressed to an independent third-party tabulator, who receives, inspects, and tabulates the proxies. Voted proxies and ballots are not seen by nor reported to the Company 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. 8 EXECUTIVE COMPENSATION THE FOLLOWING TABLE shows for 1995, 1994 and 1993 the compensation earned by the chief executive officer and the four other most highly compensated executive officers (as defined by regulations of the Securities and Exchange Commission) of the Company at December 31, 1995. SUMMARY COMPENSATION TABLE
LONG-TERM COMPENSATION ANNUAL ------------------- COMPENSATION ---------------- PAYOUTS ALL OTHER SALARY BONUS ------------------- COMPENSATION NAME AND PRINCIPAL POSITION YEAR ($) ($)(1) LTIP PAYOUTS($)(1) ($)(2) - ---------------------------------------- ---- ------- ------- ------------------- ------------- E. LINN DRAPER, JR. -- Chairman of the 1995 685,000 236,325 334,851 30,790 board, president and chief executive 1994 620,000 209,436 137,362 29,385 officer of the Company and the Service 1993 538,333 148,742 18,180 Corporation; chairman and chief executive officer of other subsidiaries PETER J. DEMARIA -- Controller and 1995 330,000 113,850 143,829 20,050 director of the Company; executive vice 1994 305,000 103,029 59,032 18,750 president -- administration and chief 1993 280,000 77,364 17,811 accounting officer and director of the Service Corporation; vice president, controller and director of other subsidiaries G.P. MALONEY -- Vice president, 1995 330,000 113,850 141,582 20,060 secretary and director of the Company; 1994 300,000 101,340 58,094 19,745 executive vice president -- chief 1993 269,000 74,325 18,000 financial officer and director of the Service Corporation; vice president and director of other subsidiaries WILLIAM J. LHOTA -- Executive vice 1995 300,000 103,500 132,592 19,140 president and director of the Service 1994 280,000 94,584 54,409 19,185 Corporation; president, chief operating 1993 249,000 68,799 17,160 officer and director of other subsidiaries JAMES J. MARKOWSKY -- Executive vice 1995 285,000 98,325 126,599 17,515 president -- power generation and 1994 267,000 90,193 51,930 14,755 director of the Service Corporation; 1993 247,000 65,259 11,165 vice president and director of other subsidiaries
- ------------- (1) Amounts in the "Bonus" column reflect payments under the Management Incentive Compensation Plan for performance measured for each of the years ended December 31, 1993, 1994 and 1995. Payments are made in March of the subsequent year. Amounts for 1995 are estimates but should not change significantly. Amounts in the "Long-Term Compensation" column reflect performance share units earned under the Performance Share Incentive Plan (which became effective January 1, 1994) for the one-year and two-year transition performance periods ending December 31, 1994 and 1995, respectively. For 1995, their value was calculated by multiplying the $40.50 closing price of AEP's Common Stock as reported on the New York Stock Exchange on December 29, 1995, the last trading day of fiscal year 1995, by the number of units earned. See below under "Long-Term Incentive Plans -- Awards in 1995" and pages 13 and 14 for additional information. (2) For 1995, includes (i) employer matching contributions under the AEP System Employees Savings Plan: $4,500 for each of the named executive officers; (ii) employer matching contributions under the AEP System Supplemental Savings Plan (which became effective January 1, 1994), a non-qualified plan designed to supplement the AEP Savings Plan: Dr. Draper, $16,050; Mr. DeMaria, $5,400; Mr. Maloney, $5,400; Mr. Lhota, $4,500; and Dr. Markowsky, $4,050; and (iii) subsidiary companies director fees: Dr. Draper, $10,240; Mr. DeMaria, $10,150; Mr. Maloney, $10,160; Mr. Lhota, $10,140; and Dr. Markowsky, $8,965. 9 LONG-TERM INCENTIVE PLANS -- AWARDS IN 1995 Each of the awards set forth below constitutes a grant of performance share units, which represent units equivalent to shares of Common Stock, pursuant to the Company's Performance Share Incentive Plan. Since it is not possible to predict future dividends and the price of AEP Common Stock, credits of performance share units in amounts equal to the dividends that would have been paid if the performance share units were granted in the form of shares of Common Stock are not included in the table. The ability to earn performance share units is tied to achieving specified levels of total shareholder return ("TSR") relative to the S&P Electric Utility Index. Notwithstanding AEP's TSR ranking, no performance share units are earned unless AEP shareholders realize a positive TSR over the relevant three-year performance period. The Human Resources Committee may, at its discretion, reduce the number of performance share units otherwise earned. In accordance with the performance goals established for the periods set forth below, the threshold, target and maximum awards are equal to 25%, 100% and 200%, respectively, of the performance share units held. No payment will be made for performance below the threshold. Payments of earned awards are deferred in the form of restricted stock units (equivalent to shares of AEP Common Stock) until the officer has met the equivalent stock ownership target discussed in the Human Resources Committee Report. Once officers meet and maintain their respective targets, they may elect either to continue to defer or to receive further earned awards in cash and/or Common Stock.
ESTIMATED FUTURE PAYOUTS OF PERFORMANCE SHARE UNITS UNDER PERFORMANCE NON-STOCK PRICE-BASED PLAN NUMBER OF PERIOD UNTIL ------------------------------- PERFORMANCE MATURATION THRESHOLD TARGET MAXIMUM NAME SHARE UNITS OR PAYOUT (#) (#) (#) - --------------- ----------- ------------ ---------- ------- ------- E. L. Draper, Jr. 8,302 1995-1997 2,075 8,302 16,604 P. J. DeMaria 3,499 1995-1997 875 3,499 6,998 G. P. Maloney 3,499 1995-1997 875 3,499 6,998 W. J. Lhota 3,181 1995-1997 795 3,181 6,362 J. J. Markowsky 3,022 1995-1997 755 3,022 6,044
RETIREMENT BENEFITS The American Electric Power System Retirement Plan provides pensions for all employees of AEP System companies (except for employees covered by certain collective bargaining agreements), including the executive officers of the Company. The Retirement Plan is a noncontributory defined benefit plan. The following table shows the approximate annual annuities under the Retirement Plan that would be payable to employees in certain higher salary classifications, assuming retirement at age 65 after various periods of service. PENSION PLAN TABLE
YEARS OF ACCREDITED SERVICE HIGHEST AVERAGE -------------------------------------------------------------------------- ANNUAL EARNINGS 15 20 25 30 35 40 45 - ---------------- -------- -------- -------- -------- -------- -------- -------- $ 300,000 $ 69,930 $ 93,240 $116,550 $139,860 $163,170 $183,120 $203,070 400,000 93,930 125,240 156,550 187,860 219,170 245,770 272,370 500,000 117,930 157,240 196,550 235,860 275,170 308,420 341,670 700,000 165,930 221,240 276,550 331,860 387,170 433,720 480,270 900,000 213,930 285,240 356,550 427,860 499,170 559,020 618,870 1,100,000 261,930 349,240 436,550 523,860 611,170 684,320 757,470
The amounts shown in the table are the straight life annuities payable under the Retirement Plan without reduction for the joint and survivor annuity. Retirement benefits listed in the table are not subject to any deduction for Social Security or other offset amounts. The retirement annuity is reduced 3% per year in the case of retirement between ages 60 and 62 and further 10 reduced 6% per year in the case of retirement between ages 55 and 60. If an employee retires after age 62, there is no reduction in the retirement annuity. The Company maintains a supplemental retirement plan which provides for the payment of benefits that are not payable under the Retirement Plan due primarily to limitations imposed by Federal tax law on benefits paid by qualified plans. The table includes supplemental retirement benefits. Compensation upon which retirement benefits are based, for the executive officers named in the Summary Compensation Table above, consists of the average of the 36 consecutive months of the officer's highest aggregate salary and Management Incentive Compensation Plan awards, shown in the "Salary" and "Bonus" columns, respectively, of the Summary Compensation Table, out of the officer's most recent 10 years of service. As of December 31, 1995, the number of full years of service applicable for retirement benefit calculation purposes for such officers were as follows: Dr. Draper, three years; Mr. DeMaria, 36 years; Mr. Maloney, 40 years; Mr. Lhota, 31 years; and Dr. Markowsky, 24 years. Dr. Draper's employment agreement described below provides him with a supplemental retirement annuity that credits him with 24 years of service in addition to his years of service credited under the Retirement Plan less his actual pension entitlement under the Retirement Plan and any pension entitlement from the Gulf States Utilities Company Trusteed Retirement Plan, a plan sponsored by his prior employer. The Company will pay supplemental retirement benefits to 19 AEP System employees (including Messrs. DeMaria, Maloney and Lhota and Dr. Markowsky) whose pensions may be adversely affected by amendments to the Retirement Plan made as a result of the Tax Reform Act of 1986. Such payments, if any, will be equal to any reduction occurring because of such amendments. Assuming retirement in 1996 of the executive officers named in the Summary Compensation Table, only Mr. Maloney would be affected and his annual supplemental benefit would be $972. The Company made available a voluntary deferred-compensation program in 1982 and 1986, which permitted certain members of AEP System management to defer receipt of a portion of their salaries. Under this program, a participant was able to defer up to 10% or 15% annually (depending on the terms of the program offered), over a four-year period, of his or her salary, and receive supplemental retirement or survivor benefit payments over a 15-year period. The amount of supplemental retirement payments received is dependent upon the amount deferred, age at the time the deferral election was made, and number of years until the participant retires. The following table sets forth, for the executive officers named in the Summary Compensation Table, the amounts of annual deferrals and, assuming retirement at age 65, annual supplemental retirement payments under the 1982 and 1986 programs.
1982 PROGRAM 1986 PROGRAM ---------------------------------- ---------------------------------- ANNUAL AMOUNT OF ANNUAL AMOUNT OF ANNUAL SUPPLEMENTAL ANNUAL SUPPLEMENTAL AMOUNT RETIREMENT AMOUNT RETIREMENT DEFERRED PAYMENT DEFERRED PAYMENT NAME (4-YEAR PERIOD) (15-YEAR PERIOD) (4-YEAR PERIOD) (15-YEAR PERIOD) - ----------------------------------------- --------------- ---------------- --------------- ---------------- P. J. DeMaria............................ $10,000 $52,000 $13,000 $53,300 G. P. Maloney............................ 15,000 67,500 16,000 56,400
EMPLOYMENT AGREEMENT Dr. Draper has a contract with the Company and AEP Service Corporation which provides for his employment for an initial term from no later than March 15, 1992 until March 15, 1997. Dr. Draper commenced his employment with the Company and AEP Service Corporation on March 1, 1992. The Company or AEP Service Cor- poration may terminate the contract at any time and, if this is done for reasons other than cause and other than as a result of Dr. Draper's death or permanent disability, AEP Service Corporation must pay Dr. Draper's then base salary through March 15, 1997, less any amounts received by Dr. Draper from other employment. 11 BOARD HUMAN RESOURCES COMMITTEE REPORT ON EXECUTIVE COMPENSATION The Human Resources Committee of the Board of Directors regularly reviews executive compensation policies and practices and evaluates the performance of management in the context of the Company's performance. None of the members of the Committee is or has been an officer or employee of any AEP System company or receives remuneration from any AEP System company in any capacity other than as a director. See page 6. The Human Resources Committee recognizes that the executive officers are charged with managing a $16 billion, multi-state electric utility during challenging times and with addressing many difficult and complex issues. The Company's executive compensation program is designed to enhance shareholder value, to support the implementation of the Company's business strategy and to improve both corporate and personal performance. The Committee believes that compensation must be competitive in order to attract, retain, reward and motivate the highly qualified individuals needed to manage AEP to meet corporate objectives and that compensation should be closely tied to performance in order to provide incentives that will maximize shareholder value. The Company's Management Incentive Compensation Plan and Performance Share Incentive Plan, both described below, reflect the intention of the Committee to place a significant portion of the total compensation of senior officers at risk similar to the risk experienced by other AEP shareholders. The Committee also has taken into account management's ability to respond to the impact of increased competition and other significant changes in the rapidly evolving electric utility industry. It is the Committee's opinion that, in this ever-changing environment, Dr. Draper and the senior management team continue to develop effectively and implement strategies to position the Company for the future. The Company's recent and continuing restructuring and organizational realignment and its proposal for the industry's transition to retail competition, both of which are discussed in the 1995 annual report, are two major steps. Some of the benefits of these efforts to the Company cannot, of course, be quantifiably measured but the Committee believes these efforts are vital to the Company's continuing success. INTERNAL REVENUE CODE SECTION 162(M). The Committee has considered the impact of Section 162(m) of the Internal Revenue Code, which provides a limit on the deductibility of compensation for certain executive officers in excess of $1,000,000 per year. Award payments under the Performance Share Incentive Plan have been structured to be exempt from the deduction limit because they are made pursuant to a shareholder-approved performance-driven plan. No named officer in the Summary Compensation Table had taxable compensation for 1995 in excess of the deduction limit. The Committee intends to continue to evaluate the impact of this Code provision. STOCK OWNERSHIP GUIDELINES. The Board of Directors, upon the Committee's recommendation, underscored the importance of linking executive and shareholder interests by adopting in December 1994 stock ownership guidelines for senior management participants in the Performance Share Incentive Plan. Under the guidelines, the target ownership of AEP Common Stock is directly related to the officer's corporate position with the greatest ownership target for the chief executive officer. The target for the CEO is 45,000 shares, which was equivalent to approximately three times his then annual base salary. The targets for the other four officers named in the Summary Compensation Table are 15,000 shares each, equivalent to approximately 1.5 times their then annual base salary. Each officer is expected to achieve the ownership target within a period of five years commencing on January 1, 1995. Common Stock equivalents earned through the Management Incentive Compensation Plan and the Performance Share Incentive Plan are included in determining compliance with the ownership targets. Substantial progress has been made in complying with the stock ownership guidelines and, as of January 1, 1996, the executive officers named in the Summary Compensation Table had achieved their respective ownership targets to the following extent (see the table on pages 16 and 17 12 for actual ownership amounts): Dr. Draper, 40%; Mr. DeMaria, 69%; Mr. Maloney, 70%; Mr. Lhota, 120%; and Dr. Markowsky, 75%. COMPONENTS OF EXECUTIVE COMPENSATION BASE SALARY. When reviewing salaries, the Committee considers pay practices used by other electric utilities and by industry in general. In addition, the Committee considers the respective positions held by the executive officers, their levels of responsibility, performance and experience, and the relationship of their salaries to the salaries of other AEP managers and employees. For compensation comparison purposes, the Human Resources Committee uses the electric utility companies in the S&P Electric Utility Index, which is the peer group used in the Comparison of Five Year Cumulative Total Return graph in this proxy statement. In recognition of AEP's relatively large size and operational complexity, executive officer salary levels are targeted to the third quartile (between the 50th and 75th percentiles) of the range of compensation paid by the other electric utilities in this compensation peer group. Base salary levels in 1995 for the five most highly compensated executive officers of AEP named in the Summary Compensation Table were within this third quartile. In establishing salary levels against that range, the Human Resources Committee considers the competitiveness of AEP's entire compensation package. Salaries are reviewed and adjusted annually to reflect individual and corporate performance and consistency with compensation changes within the Company and the compensation peer group of other electric utilities. The Committee meets without the presence of Dr. Draper, chairman, president and chief executive officer, to evaluate his performance and compensation and reports on that evaluation to the outside directors of the Board. These directors then act on the Committee's recommendation. ANNUAL INCENTIVE. A variable, performance-based portion of the executive officers' total compensation is paid through the Management Incentive Compensation Plan ("MICP"), which is included in the "Bonus" column in the Summary Compensation Table. The MICP was established (effective January 1, 1990) to motivate and reward superior management performance in serving customer needs and creating shareholder value. Each participant is assigned an annual target award expressed as a percentage of annual salary. The target award is 30% for the executive officers named in the compensation table. Actual awards can vary from 0-150% of the target award based on performance. The MICP awards for the executive officers named in the compensation table are based entirely on preestablished AEP corporate performance criteria specified in the MICP, which include return on stockholder equity (weighted at 25%) and total investor return reflecting changes in stock price and payment of dividends (weighted at 25%), both measured relative to the performance of utilities in the S&P Electric Utility Index, and the extent to which the average price of power sold to retail customers (weighted at 50%) is lower as compared with other utilities in the states which AEP serves. For 1995, the AEP corporate performance target was achieved to the extent of 115%. This percentage is an estimate but should not change significantly. To more closely align the financial interests of the executive officers with the Company's shareholders, 20% of an MICP award is deferred for three years and treated as if invested in Common Stock of the Company, although no stock is actually purchased. Dividend equivalents are credited during the three-year period. Effective for 1996 and subsequent years, MICP participants may elect to defer further the 20%, and to defer all or any part of the remaining 80% of an award, for payment up to five years past termination of employment, with the same treatment. LONG-TERM INCENTIVE. The Performance Share Incentive Plan (the "Plan") provides longer-term, performance-driven, equity incentive award opportunities directly related to shareholder value. The Board of Directors approved the Plan in December 1993 and, at the 1994 annual meeting, the shareholders also approved it. The Plan grants performance share units annually which are paid based on AEP's subsequent three-year total shareholder returns measured relative to the S&P peer utilities. In 1995, the Committee granted Dr. Draper and the other executive officers named in the Summary Compensation Table performance share units equivalent to 40% and 35%, respectively, of their base salaries. The number of performance share units granted has been determined after an evaluation of long-term incentive opportunities provided by the S&P peer companies, again targeting the third quartile of 13 competitive practice. However, the awards which will ultimately be paid to participants under the Plan for a performance period are not determinable in advance and, in fact, could be zero. The Plan ended a two-year transition performance period at year end 1995. AEP's total shareholder return for 1993-1995 ranked sixth relative to the S&P 24 peer utilities and, as a result, 160% of the performance share units granted (and dividend credits) were earned. The associated award payments are listed in the Summary Compensation Table. Similar to that portion of the MICP awards which are deferred, payments of earned awards under the Plan, commencing with the performance period ending in 1995, are also deferred in the form of restricted stock units (equivalent to shares of AEP Common Stock). Such Plan deferrals continue until termination of employment or, if so elected by the recipient, up to five years thereafter. Once the officers meet and maintain their respective equivalent stock ownership targets discussed above, they may then elect either to continue to defer or to receive further earned Plan awards in cash and/or Common Stock. Dividend equivalents are credited as though reinvested in additional restricted stock units. The Plan is further described on page 10. HUMAN RESOURCES COMMITTEE MEMBERS Toy F. Reid, Chairman Arthur G. Hansen Donald G. Smith Morris Tanenbaum 14 EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
COMPARISON OF FIVE YEAR CUMULATIVE TOTAL RETURN* AEP, S&P 500 INDEX & S&P ELECTRIC UTILITY INDEX** American Electric Power S&P 500 Index S&P Electric Utility Index 100.00 100.00 100.00 1991 132.82 130.47 130.42 1992 138.37 140.41 138.39 1993 165.68 154.56 155.76 1994 158.06 156.60 135.48 1995 208.59 215.31 177.45 Assumes $100 Invested on January 1, 1991 in AEP Common Stock, S&P 500 Index and S&P Electric Utility Index *Total Return Assumes Reinvestment of Dividends **Fiscal Year Ending December 31
The total return performance shown on the graph above is not necessarily indicative of future performance. SHARE OWNERSHIP OF BENEFICIAL OWNER THE FOLLOWING TABLE sets forth certain information regarding each person (including any "group" as that term is used in Section 13(d)(3) of the Securities Exchange Act of 1934) who is known by the Company (based on February 1996 Schedule 13G filings made with the Securities and Exchange Commission) to beneficially own more than 5% of the Company's Common Stock.
AMOUNT AND NATURE OF PERCENT OF NAME AND ADDRESS OF BENEFICIAL OWNER BENEFICIAL OWNERSHIP CLASS - -------------------------------------------------- ---------------------- ------------- Franklin Resources, Inc. ......................... 9,676,910(a) 5.2% 777 Mariners Island Blvd. San Mateo, CA 94404
- ------------ (a) Franklin Resources, Inc., a registered investment company and investment adviser, has reported that it has sole voting power for 9,644,910 shares, shared voting power for 7,000 shares and shared dispositive power for 9,676,910 shares. 15 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 January 1, 1996 for all directors as of the date of this proxy statement (except for Mr. Fri and Ms. Stuntz whose share ownership is as of February 13, 1996 and February 27, 1996, respectively), all nominees to the Board of 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 Common Stock and stock-based units of AEP set forth across from his or her name. Fractions of shares and units have been rounded to the nearest whole number.
STOCK NAME SHARES UNITS(A) TOTAL - ------------------------------------------------------------------ -------- --------- --------- P. J. DeMaria..................................................... 7,356(b)(c)(d)(e)(f) 5,391 12,747 E. L. Draper, Jr.................................................. 6,119(c)(e) 11,984 18,103 R. M. Duncan...................................................... 1,713 -- 1,713 R. W. Fri......................................................... 500 -- 500 A. G. Hansen...................................................... 1,116 -- 1,116 L. A. Hudson, Jr.................................................. 1,853(f) -- 1,853 W. J. Lhota....................................................... 13,064(c)(d)(e) 4,944 18,008 G. P. Maloney..................................................... 5,227(c)(d)(e) 5,306 10,533 J. J. Markowsky................................................... 6,631(c)(f) 4,714 11,345 A. E. Peyton...................................................... 3,348(g) -- 3,348 T. F. Reid........................................................ 1,500(e) -- 1,500 D. G. Smith....................................................... 1,200 -- 1,200 L. G. Stuntz...................................................... 1,000(e) -- 1,000 M. Tanenbaum...................................................... 1,160 -- 1,160 A. H. Zwinger..................................................... 12,300(e)(f) -- 12,300 All directors and executive officers as a group (15 persons)...... 149,318(d)(h) 32,339 181,657
- ------------ (a) This column includes amounts deferred in stock units and held under the Management Incentive Compensation Plan and Performance Share Incentive Plan. (b) Mr. DeMaria owns 100 shares of Cumulative Preferred Shares 9.50% Series, $100 par value, of Columbus Southern Power Company. (c) Includes shares and share equivalents held in the following plans in the amounts listed below:
AEP EMPLOYEE STOCK AEP PERFORMANCE AEP EMPLOYEES OWNERSHIP PLAN SHARE INCENTIVE SAVINGS PLAN (SHARE (SHARES) PLAN (SHARES) EQUIVALENTS) ------------------- ----------------- ------------------- Mr. DeMaria....................................... 83 944 2,705 Dr. Draper........................................ -- 2,196 1,958 Mr. Lhota......................................... 60 812 10,824 Mr. Maloney....................................... 85 867 2,775 Dr. Markowsky..................................... 66 830 5,718 All Directors and Executive Officers.............. 294 5,649 23,980
With respect to the shares and share equivalents held in these plans, such persons have sole voting power, but the investment/disposition power is subject to the terms of such plans. (d) Does not include, for Messrs. DeMaria, Lhota and Maloney, 85,231 shares in the American Electric Power System Educational Trust Fund over which Messrs. DeMaria, Lhota and Maloney share voting and investment power as trustees (they disclaim beneficial ownership). The amount of shares shown for all directors and executive officers as a group includes these shares. 16 (e) Includes the following numbers of shares held in joint tenancy with a family member: Mr. DeMaria, 1,232; Dr. Draper, 1,965; Mr. Lhota, 1,368; Mr. Maloney, 1,500; Mr. Reid, 1,500; Ms. Stuntz, 300; and Ms. Zwinger, 3,100. (f) Includes the following numbers of shares held by family members over which beneficial ownership is disclaimed: Mr. DeMaria, 2,392; Mr. Hudson, 750; Dr. Markowsky, 17; and Ms. Zwinger, 3,000. (g) Includes 315 shares over which Mr. Peyton shares voting and investment power which are held by trusts of which he is a trustee, but he disclaims beneficial ownership of 169 of such shares. (h) Represents less than 1% of the total number of shares outstanding. - ------------ Section 16(a) of the Securities Exchange Act of 1934 requires the Company's executive officers and directors to file initial reports of ownership and reports of changes in ownership of Common Stock of the Company with the Securities and Exchange Commission. Executive officers and directors are required by SEC regulations to furnish the Company with copies of all reports they file. Based solely on a review of the copies of such reports furnished to the Company and written representations from the Company's executive officers and directors during the fiscal year ended December 31, 1995, the Company notes that Robert M. Duncan, a director, did not timely report the acquisition of 283 shares of Common Stock that occurred in April 1995, although he reported it shortly thereafter. TRANSACTIONS WITH MANAGEMENT MS. STUNTZ, a director, was a partner in the Washington, D.C. law firm of Van Ness Feldman, P.C. during part of 1995. Several organizations of which certain AEP System companies have been members and to which they have provided financial support, were clients of Van Ness Feldman, P.C. in 1995. No such relationships exist between AEP System companies and the current firm of Ms. Stuntz, Stuntz & Davis, P.C. SHAREHOLDER PROPOSALS TO BE INCLUDED in the Company's proxy statement and form of proxy for the 1997 annual meeting of shareholders, any proposal which a shareholder intends to present at such meeting must be received by the Company at its office at 1 Riverside Plaza, Columbus, Ohio 43215 not later than the close of business on November 12, 1996. SOLICITATION EXPENSES THE COSTS of this proxy solicitation will be paid by the Company. Proxies will be solicited principally by mail, but some telephone, telegraph or personal solicitations of holders of Common Stock of the Company may be made. Any officers or employees of the Company or of American Electric Power Service Corporation who make or assist in such solicitations will receive no compensation, other than their regular salaries, for doing so. The Company 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 the Company will reimburse them for their expenses incurred in doing so at rates prescribed by the New York Stock Exchange. 17 - -------------------------------------------------------------------------------- [LOGO] 1 Riverside Plaza Columbus, OH 43215-2373 [PRINTED WITH SOY INK] [PRINTED ON RECYCLED PAPER] American Electric Power 1995 Annual Report - ------------------------------------------------------------------------------- Appendix A [AEP LOGO] AMERICAN ELECTRIC POWER 1 Riverside Plaza Columbus, Ohio 43215-2373
CONTENTS - ------------------------------------------------------------------------------------------------ Selected Consolidated Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Management's Discussion and Analysis of Results of Operations and Financial Condition . . 3 - 13 Consolidated Statements of Income and Consolidated Statements of Retained Earnings . . . . . 14 Consolidated Statements of Cash Flows. . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Consolidated Balance Sheets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 - 17 Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . 18 - 33 Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries . . . . . . . . . . . . 34 Schedule of Consolidated Long-term Debt of Subsidiaries. . . . . . . . . . . . . . . . . . . 35 Management s Responsibility. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Independent Auditors' Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SELECTED CONSOLIDATED FINANCIAL DATA
Year Ended December 31, 1995 1994 1993 1992 1991 - --------------------------------------------------------------------------------------------------------- INCOME STATEMENTS DATA (in millions): Operating Revenues $5,670 $5,505 $5,269 $5,045 $5,047 Operating Income 965 932 929 883 918 Net Income 530 500 354 468 498 December 31, 1995 1994 1993 1992 1991 - --------------------------------------------------------------------------------------------------------- BALANCE SHEETS DATA (in millions): Electric Utility Plant $18,496 $18,175 $17,712 $17,509 $17,148 Accumulated Depreciation and Amortization 7,111 6,827 6,612 6,281 5,952 ------- ------- ------- ------- ------- Net Electric Utility Plant $11,385 $11,348 $11,100 $11,228 $11,196 ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- Total Assets $15,902 $15,739 $15,362 $14,217 $13,824 Common Shareholders' Equity 4,340 4,229 4,151 4,245 4,221 Cumulative Preferred Stocks of Subsidiaries: Not Subject to Mandatory Redemption 148 233 268 535 535 Subject to Mandatory Redemption* 523 590 501 234 141 Long-term Debt* 5,057 4,980 4,995 5,311 5,029 Obligations Under Capital Leases* 405 400 284 300 273 *Including portion due within one year Year Ended December 31, 1995 1994 1993 1992 1991 - --------------------------------------------------------------------------------------------------------- COMMON STOCK DATA: Earnings per Share $2.85 $2.71 $1.92 $2.54 $2.70 Average Number of Shares Outstanding (in thousands) 185,847 184,666 184,535 184,535 184,535 Market Price Range: High $40-5/8 $37-3/8 $40-3/8 $35-1/4 $34-1/4 Low 31-1/4 27-1/4 32 30-3/8 26-5/8 Year-end Market Price 40-1/2 32-7/8 37-1/8 33-1/8 34-1/4 Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40 Dividend Payout Ratio 84.1% 88.6% 125.2% 94.6% 88.9% Book Value per Share $23.25 $22.83 $22.50 $23.01 $22.88
2 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS BUSINESS CONDITIONS The prospect for market driven rates is powering a movement to introduce direct competition to the generation function of the electric utility industry. As a result we expect that competition will be a factor influencing AEP's future results of operations. Other important factors that could affect future results of operations are environmental laws, affiliated coal mining costs, nuclear fuel storage and disposal costs and nuclear decommissioning costs. Management will be working to prepare for a transition to greater competition and to manage the other major factors that could impact future results of operations. COMPETITION AT THE WHOLESALE LEVEL The Energy Policy Act of 1992 (Energy Act) was designed, among other things, to foster competition in the wholesale market through amendments to (a) the Public Utility Holding Company Act, facilitating the ownership and operation of generating facilities by independent power producers including non-electric utilities and (b) the Federal Power Act, authorizing the Federal Energy Regulatory Commission (FERC) under certain conditions to order utilities which own transmission facilities to provide wholesale transmission services to other utilities and entities generating electric power. While the Energy Act gave the FERC broad authority to mandate transmission access in the wholesale market, it prohibited the FERC from ordering retail transmission access. CUSTOMER CHOICE The demand for customer choice of electric supplier is mainly coming from large industrial energy users. Transmission access in the retail marketplace will allow an electric customer within a particular utility's service territory to buy power directly from another source using the power lines of the local electric utility for delivery. FINANCIAL IMPLICATIONS OF COMPETITION A significant expansion of competition in the generation of electricity would require the resolution of many complex issues, including the obligation to serve and the recovery of stranded costs which, if not properly addressed, could adversely impact future results of operations and possibly the financial condition of electric utilities. Stranded costs occur when a customer switches to a new supplier for its electric energy needs creating the issue of who pays for plant investment, purchased power or fuel contracts both non-affiliated and affiliated, inventories, construction work in progress, nuclear decommissioning costs, and other investments and commitments that are no longer needed, economic or recoverable in a competitive market. The amount of any losses the Company may experience from stranded costs depends on the extent to which direct competition is introduced to its business and the market price of energy. Cost-based regulation traditionally results in the recognition of revenues and expenses in accordance with rate 3 commission orders which can result in revenue and expense recognition in different time periods than for enterprises that are not regulated. As a result, regulatory assets have been recorded by regulated utility companies representing the deferral of costs for recovery in future periods. The Company has approximately $2 billion in regulatory assets. In order to maintain regulatory assets, the Company's rates must be cost-based regulated. Management has reviewed the evidence currently available and concluded that AEP continues to meet the requirements to apply rate-regulated accounting standards. In the event a portion of the Company's business no longer met these requirements, regulatory assets would have to be written off for that portion of the business. Whether future results of operations are adversely affected by losses or write-offs also will depend on whether and how equitable recovery is provided for by the applicable regulators. We intend to seek appropriate recovery of any stranded costs and regulatory assets. AEP'S RESPONSE TO COMPETITIVE PRESSURES AEP has the financial strength, geographic reach,location and cost structure to be an able competitor. However, no assurance can be given that AEP can maintain this position in the future. In 1995 AEP took steps to prepare for competition by realigning into functional business units, expanding our marketing and customer service efforts and proposing a plan for an orderly transition to retail competition. Previously, AEP had proposed open access transmission rates. In order to better position AEP for increasing competition among electricity suppliers, we realigned from separate operating company organizations to distinct Power Generation, Nuclear Generation, Energy Delivery and Corporate Development operating units. We are realigning into separate functional units in order (a) to facilitate the unbundling of electric services to the extent required or permitted by the evolving regulatory structure and (b) to operate more efficiently and effectively to meet customers needs. The legal, financial, rate and regulatory relationships of the subsidiary operating companies will not change. To facilitate reliable, safe and efficient access for customers, AEP supports the creation of an Independent System Operator (ISO) to operate a multi-state transmission grid. Under AEP's proposal each electric company, while retaining ownership, would place its portion of the transmission grid under the management of the ISO who would be responsive to the needs of all parties using the transmission grid. AEP also supports the evolution of a Regional Power Exchange, which would establish a competitive marketplace for generation. Generators and resellers of electricity would be permitted to sell power into a spot market operated by the Regional Power Exchange. The Regional Power Exchange would accept offers to buy and sell power and would settle transactions based on the price at which supply and demand are balanced. State regulators would continue to determine the terms, standards and prices for the delivery service. Under our proposed plan regulators would be authorized to establish distribution service charges which would provide, as appropriate, for the recovery of stranded costs and regulatory assets. These charges would be collected by electric companies 4 from all new and existing distribution services customers within a company's service territory. AEP has also offered access to its transmission grid at 142 interconnections under the same costs and terms available to AEP itself. The unbundled transmission service for wholesale customers will provide AEP with greater opportunities for transmission service revenues. Also, AEP has responded to its retail customers by introducing new rate designs (interruptible buy-through and real-time pricing) to provide lower cost-based rates, to meet specific customers' needs, and to offer customer choice. AEP's proposals to pave the way for retail competition were issued to enable the Company to participate in a meaningful way in the debate with other interested parties so that we can build consensus and form coalitions to shape the form of the future playing field. We plan to enhance shareholder value by making AEP the supplier of choice. Our success will depend on our ability to obtain a level playing field, improve and expand on our energy sales and services and maintain and improve our relatively low cost structure. NEW BUSINESS OPPORTUNITIES We continue to seek and consider new business opportunities, particularly those which permit the use of our expertise and core competencies. In the non-rate-regulated environment, AEP offers consulting services both domestically and internationally and contracts with other public utilities and government agencies for the licensing of intellectual property and the delivery of energy services. In addition, AEP is pursuing investments in power generation, transmission and distribution projects. In 1995 AEP announced a strategic alliance with Cogentrix Energy and Zurn Industries to pursue industrial power projects in the United States and Canada. Cogentrix is one of the largest independent power producers in the U.S., while Zurn is the largest turnkey engineer and constructor of both biomass power plants and mid-sized gas turbine combined cycle plants in the U.S. AEP has been pursuing several other possible power generation, transmission and distribution investment projects overseas. These investment opportunities offer the potential for earning returns which exceed those of the domestic rate-regulated operations. However, they also involve a higher degree of risk which must be carefully considered and assessed. AEP may make investments in these and other new business opportunities after management carefully assesses the risks involved versus the potential for enhanced shareholder value. Appropriate new business investments are part of AEP's strategic plan for enhancing shareholder value and will be the full time responsibility of our newly formed corporate development operating unit. AFFILIATED COAL COST Fuel is 80% of the production cost of electricity. Although our fuel costs have declined by one half in constant dollars since 1986, we must continue to manage our coal costs to effectively compete. As long-term contracts expire we are negotiating with suppliers to lower purchased coal costs. We will continue to supplement our affiliated and long-term coal supplies with spot market coal as favorable market conditions permit. Approximately 13% of the coal we burn is supplied by affiliated mines; the remainder is acquired under long-term contracts and in 5 the spot market. Efforts continue to reduce the cost of affiliated coal. In recent years Ohio Power Company (OPCo) has been limited in its recovery of the cost of coal produced by its affiliated mines in its Ohio jurisdiction. Under the terms of a 1992 stipulation agreement a predetermined price of $1.575 per million Btu's for coal burned at the Gavin Plant was established effective December 1, 1994 for a 15-year period subject to adjustment for inflation. A subsequent Settlement Agreement sets an overall predetermined electric fuel component rate for OPCo at 1.465 cents per kwh for the period June 1, 1995 through November 30, 1998. The Gavin Plant predetermined price remains effective as escalated from the original $1.575 per million Btu's. After November 2009 the price that OPCo can recover for coal from its affiliated Meigs mine, which supplies the Gavin Plant, will be limited to the lower of cost or the then-current market price. The predetermined prices provide OPCo with an opportunity to accelerate recovery of its Ohio jurisdictional investment in and liabilities and closing costs of the Company's Meigs, Muskingum and Windsor mining operations to the extent the actual cost of coal burned at the Gavin Plant is less than the predetermined prices. Based on the estimated future cost of coal at Gavin Plant, we believe that OPCo should be able to recover under the terms of the 1992 stipulation agreement and in conjunction with the Settlement Agreement, the Ohio jurisdictional portion of the cost of the affiliated mining operations including mine closure costs. Management intends to seek from ratepayers recovery of the non-Ohio jurisdictional portion of the investment in and the liabilities and closing costs of the affiliated Meigs, Muskingum and Windsor mines. The non-Ohio jurisdictional portion of shutdown costs for these mines which includes the investment in the mines, leased asset buy- outs, reclamation costs and employee benefits is estimated to be approximately $195 million after tax at December 31, 1995. The affiliated Muskingum and Windsor mines may have to close by January 2000 as part of compliance with Phase II requirements of the Clean Air Act Amendments of 1990. Should it become apparent that the costs of the affiliated mines including future mine closure costs will not be recoverable, the mines could be closed and results of operations adversely affected. NUCLEAR COST The Company's only nuclear plant, the Donald C. Cook Nuclear Plant, has recently achieved a superior rating from the Institute of Nuclear Power Operations, a nuclear industry oversight group, and received improved Nuclear Regulatory Commission (NRC) performance ratings. Refueling outage costs have been reduced by $20 million compared to 1992 outage expense levels. In an effort to continue to reduce costs and enhance organizational efficiency, we announced in November that during the summer of 1996 we will consolidate our Columbus-based nuclear management and support staff with the plant staff at or near the Cook Nuclear Plant in Bridgman, Michigan. The cost to operate and maintain the two-unit Cook Nuclear Plant is impacted by federal laws and NRC requirements. The Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of spent nuclear fuel and high-level radioactive waste. By law we participate in the Department of Energy's (DOE's) Spent Nuclear Fuel (SNF) disposal program which is described in Note 4 of the Notes to Consolidated Financial Statements. 6 Since 1983 our consumers of nuclear generated electricity have paid $237 million for the disposal of spent nuclear fuel consumed at the Cook Nuclear Plant. Under the provisions of the Nuclear Waste Policy Act, collections from customers are to provide the DOE with money to build a permanent repository for spent fuel. The federal government has not made sufficient progress towards a permanent repository and as long as there is a delay in the permanent storage repository for spent nuclear fuel, the cost of a temporary or permanent repository will continue to increase. The cost to decommission the Cook Plant is affected by NRC regulations and the DOE's SNF disposal program. Studies completed in 1994 estimate the cost to decommission the plant and dispose of low-level nuclear waste accumulation to range from $634 million to $988 million in 1993 dollars. The decommissioning estimate could escalate due to uncertainty in the DOE's SNF disposal program and the length of time that SNF may need to be stored at the plant site delaying decommissioning. Presently we are recovering the estimated cost of decommissioning the Cook Plant over its remaining life. However, AEP's future results of operations and possibly its financial condition could be adversely affected if the cost of spent nuclear fuel disposal and decommissioning continues to increase and if for some reason such costs cannot be recovered. ENVIRONMENTAL CONCERNS CLEAN AIR ACT To comply with the Clean Air Act Amendments of 1990 (CAAA) which requires substantial reductions in sulfur dioxide and nitrogen oxides emitted from electric generating plants, an AEP System wide least-cost compliance plan was developed reflecting various methods of compliance. The corner stone of the compliance strategy is the installation of flue gas desulfurization systems (scrubbers) on the two-unit Gavin Plant which has been responsible for about 25% of the System's total sulfur dioxide emissions. By selecting scrubbers, the compliance plan allows the use of Ohio high-sulfur coal at the Gavin Plant. The scrubbers for the Gavin units are completed and operational. The PUCO approved the compliance plan as the least cost compliance strategy and approved recovery of the compliance costs under the terms of the Settlement Agreement. Through the CAAA emission allowance program in which utilities are authorized to emit a designated quantity of sulfur dioxide, measured in tons per year, AEP, on a system wide or aggregate basis, will bank a substantial number of Phase I allowances due to over compliance. To meet the stricter standards of Phase II of the CAAA, AEP has the option to use banked Phase I allowances, buy low sulfur compliance coal, purchase additional allowances and/or build additional scrubbers. We also have the option to sell Phase I allowances saved due to the installation of the scrubbers and the acquisition of low sulfur coal. HAZARDOUS MATERIAL By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and spent nuclear fuel. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically disposed of or treated in captive disposal facilities or are beneficially utilized. In 7 addition, the AEP generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and non-hazardous materials. The AEP System is currently incurring costs to safely dispose of such substances, and additional costs could be incurred to comply with new laws and regulations if enacted. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund legislation) addresses clean-up of hazardous substances at disposal sites and authorizes the United States Environmental Protection Agency (Federal EPA) to administer the clean-up programs. As of year-end 1995, AEP companies are currently involved in litigation with respect to five sites being overseen by the Federal EPA and have been named by the Federal EPA as "Potentially Responsible Parties" (PRPs) for five other sites. There are 11 additional sites for which AEP companies have received information requests which could lead to PRP designation. Also, AEP companies have received information requests with respect to four sites administered by state authorities. AEP companies' liability has been resolved for a number of sites with no significant effect on results of operations. In those instances where an AEP company has been named a PRP or defendant, the disposal or recycling activity of the AEP company was in accordance with applicable laws and regulations. CERCLA does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. While the potential liability for each Superfund site must be evaluated separately, several general statements can be made regarding such potential liability. The disposal at a particular site by the AEP companies is often unsubstantiated; the quantity of material the AEP companies disposed of at a site was generally small; and the nature of the material AEP generally disposed of was non-hazardous. Typically, an AEP subsidiary is one of many parties named as PRPs for a site and, although liability is joint and several, generally some of the other parties are financially sound enterprises. Therefore, AEP's present estimates do not anticipate material cleanup costs for identified sites for which AEP subsidiaries have been declared PRPs. However, if for reasons not currently identified significant costs are incurred for cleanup, future results of operations and possibly financial condition would be adversely affected unless the costs can be recovered. RESULTS OF OPERATIONS EARNINGS INCREASE The 6% increase in net income to $530 million or $2.85 per share for 1995 from $500 million or $2.71 per share in 1994 was primarily due to increased energy sales. Total sales of energy were 120.7 billion kilowatthours in 1995 compared with 116.7 billion kilowatthours in 1994 reflecting increased usage and additional customers. Unseasonably warm weather in the summer of 1995 and colder weather in the fourth quarter of 1995, compared with milder weather in the prior year's fourth quarter, were the primary factors causing the increased usage. The positive earnings impact of the increased sales was partly offset by the unfavorable effect of $27 million in after-tax expenses related to severance pay charges. 8 In 1994 earnings increased 41% to $500 million or $2.71 per share from $354 million or $1.92 per share in 1993. The increase was due to the effect of a $145 million after-tax loss recorded in 1993 as a result of a disallowance of a portion of the Company's Zimmer Plant investment. Without the disallowance, 1993 earnings and earnings per share would have been $498 million and $2.70, respectively. Excluding the disallowance, 1994 earnings increased slightly as compared to 1993 earnings predominately due to the favorable effect of rate increases in several jurisdictions which were heavily offset by the related amortization of Zimmer Plant deferrals and increased operating expenses largely as a result of significant storm damage. REVENUES AND SALES INCREASE Operating revenues increased 3% in 1995 and more than 4% in 1994 reflecting increased energy usage by retail customers, growth in the number of retail customers and the effects of rate increases. The change in revenues is analyzed as follows:
Increase (Decrease) From Previous Year ----------------------------- (Revenues in Millions) 1995 1994 - ------------------------------------------------------------- Amount % Amount % ------ --- ------ --- Retail: Price Variance $ 46.5 $ 90.7 Volume Variance 173.0 53.8 Fuel Cost Recoveries (22.9) 40.5 ------ ------ 196.6 4.2 185.0 4.1 ------ ------ Wholesale: Price Variance (39.3) 68.6 Volume Variance 10.8 (49.7) Fuel Cost Recoveries (4.6) 8.1 ------ ------ (33.1) (4.6) 27.0 3.9 ------ ------ Other Operating Revenues 2.2 23.8 ------ ------ Total $165.7 3.0 $235.8 4.5 ------ ------ ------ ------
The increase in 1995 operating revenues resulted from a 4% increase in energy sales to retail customers primarily due to increased usage and continued growth in the number of customers in all retail customer classes. Energy sales to residential customers, which is the most weather-sensitive customer class, rose over 6% in 1995 mainly as a result of increased weather related usage in the last half of the year. Sales to commercial and industrial customers rose 5% and 2%, respectively, reflecting additional customers, the effects of weather and the expanding economy. Although revenues from wholesale customers declined in 1995, wholesale energy sales increased by more than 1% largely due to increased sales made on an hourly basis to unaffiliated utilities. This type of short-term sale is typically made when the unaffiliated utility can purchase energy at a lower cost than the cost at which that utility can generate the energy. Such sales usually take place as a result of increased weather-related demand. The increase in 1995 wholesale energy sales occurred during the last six months of the year when the summer weather was unseasonably warm and fall temperatures were colder compared with the prior year. While wholesale energy sales increased, wholesale revenues declined in 1995 reflecting increasing competition. Although demand and generation increased, fuel cost revenues declined in 1995 due to operation of the fuel clause mechanisms. Operating revenues increased in 1994 primarily due to increased revenues from retail customers reflecting retail rate increases in several jurisdictions and an increase in retail energy sales and fuel cost recoveries. A 2% increase in retail energy 9 sales in 1994 was offset by a 7% decline in wholesale sales resulting in a slight decline in net energy sales. The 2% increase in retail energy sales in 1994 resulted from growth in the number of residential, commercial and industrial customers served and increased usage by industrial and commercial customers. Energy sales to residential customers remained constant in 1994 due to mild weather during most of the year. Wholesale revenues increased 4% in 1994, on a 7% decrease in sales, reflecting an increase in take-or-pay capacity charges to unaffiliated utilities. Capacity charges are to reserve a specified quantity of AEP System generating capacity and must be paid even when the energy is not taken. The increase in capacity charges resulted from increased capacity reserved under a long-term contract and short-term contracts with unaffiliated utilities in the summer of 1994 because of a forced generating unit outage. The increase in capacity reservation did not lead to a corresponding increase in energy sold in 1994 due to mild weather throughout most of 1994. The mild weather in 1994, combined with increased competition in the wholesale market, reduced short-term wholesale sales for 1994. Fuel cost recoveries increased in 1994 in both the retail and wholesale jurisdictions resulting from increased fuel costs. Future levels of short-term wholesale sales will be affected by the competitive nature of the short-term energy market and other factors, such as unaffiliated generating plant availability, the weather and the economy, all of which are not generally within management's control. The Company's future results of operations will be affected by its ability to make cost-effective wholesale sales or, if such sales are reduced, the ability to raise retail rates to reflect the loss of wholesale sales credits. Future results of operations also will depend in part on the weather since sales to residential and commercial customers are weather-sensitive. OPERATING EXPENSES INCREASE Changes in the components of operating expenses are shown in the table.
Increase (Decrease) From Previous Year ------------------------------- (Dollars in Millions) 1995 1994 - ---------------------------------------------------------------------------- Amount % Amount % ------ --- ------ --- Fuel and Purchased Power $(119.7) (6.9) $ 97.7 5.9 Other Operation 181.3 18.1 31.9 3.3 Maintenance (2.4) (0.5) 21.2 4.1 Depreciation and Amortization 20.8 3.6 41.5 7.8 Taxes Other Than Federal Income Taxes (5.0) (1.0) 25.9 5.5 Federal Income Taxes 58.6 27.5 13.8 6.8 ------- ------ Total $ 133.6 2.9 $232.0 5.3 ------- ------ ------- ------
Although generation increased 3% in 1995, fuel and purchased power expense declined as a result of a decrease in the average cost of fossil fuel resulting from reduced coal prices reflecting the renegotiation of certain long-term coal contracts and other lower priced purchases under existing and new contracts. Other factors which reduced fuel and purchased power expense were increased utilization of low-cost nuclear generation in 1995; operation of fuel clause mechanisms; and decreased energy purchases due to the mild weather during the first half of 1995. Changes in fuel expense are generally 10 deferred pending recovery in various fuel recovery mechanisms, and as such they generally do not affect earnings. The increase in fuel and purchased power expense in 1994 was mainly the result of increased utilization of coal-fired generation while the Cook Plant nuclear units were unavailable during refueling and maintenance outages in 1994, and increased purchases of energy from unaffiliated utilities for pass- through sales to other unaffiliated utilities. The significant increase in other operation expense during 1995 was primarily due to rent and other operating costs of the Gavin Plant scrubbers which went into service in December 1994 and the first quarter of 1995; a $41 million ($27 million after-tax) provision for severance pay recorded in 1995 related mainly to a functional realignment of operations; and costs related to the development of a new activity based budgeting system. Other operation expense increased in 1994 as a result of regulatory-approved increases in accruals and amortization, concurrent with rate recovery, of nuclear plant decommissioning expense and certain low-income residential customers' payment programs. Maintenance expense increased in 1994 due to significant storm damage caused by snow and ice storms during the first three months of 1994. The increase in depreciation and amortization expense in 1994 was primarily due to the court-ordered discontinuance of the Zimmer Plant phase- in plan deferrals effective in February 1994 and the subsequent monthly amortization of such costs as they were recovered in rates. Taxes other than federal income tax expense rose in 1994 mainly due to an increase in revenue-based gross receipts taxes of several states reflecting the increase in 1994 revenues and an increase in generation-based West Virginia taxes reflecting an increase in generation at West Virginia power plants in 1994. Effective June 1995, the West Virginia tax is based on generating capacity in West Virginia rather than on generation in West Virginia which will result in a less volatile level of West Virginia taxes. The increase in 1995 federal income tax expense attributable to operations was primarily due to an increase in pre-tax operating income; changes in certain book/tax differences accounted for on a flow-through basis and the effects of accrual adjustments for prior year tax returns. The 1994 increase was mainly due to an increase in pre-tax operating income. DEFERRED CARRYING CHARGES AND NONOPERATING INCOME The decrease in deferred Zimmer Plant carrying charges in 1995 and 1994 resulted from the cessation of deferrals commensurate with inclusion of the full plant investment in rate base effective February 1, 1994 and the monthly reduction in the deferred balance on which a return is earned. The deferred balance declined due to its amortization to depreciation and amortization expense commensurate with recovery through a rate surcharge. The increase in other nonoperating income in 1995 and the decrease in 1994 was mainly due to the 1994 recordation of a provision for loss of $8.2 million after-tax on an investment. Also contributing to the 1994 decrease was the effect of interest income 11 recorded in March 1993 on tax refunds from the Internal Revenue Service (IRS) in connection with the settlement of audits of prior years' tax returns. INTEREST CHARGES INCREASE Interest charges increased in 1995 mainly due to an increase in interest on short-term debt resulting from a higher average interest rate in 1995 on larger levels of outstanding short-term debt during the year. Refinancing programs of several subsidiaries during the early part of 1994 and 1993 reduced the average interest rate on outstanding long-term debt in 1994 as well as the levels of long-term debt causing the decline in interest expense in 1994. COMMON DIVIDEND REMAINS CONSTANT, PAYOUT RATIO DECREASES The Company paid a quarterly dividend in 1995 of 60 cents a share maintaining the annual dividend rate at $2.40 per share. The payout ratio improved to 84% in 1995 from 89% in 1994. In 1993 the payout ratio was also 89% before the Zimmer disallowance. CONSTRUCTION SPENDING DECLINING Construction expenditures have been declining in recent years. Management estimates cumulative construction expenditures for utility operation to be $2 billion over the next three years with no major new plant construction planned. Approximately 80% of the construction expenditures for the next three years will be financed internally. LIQUIDITY AND CAPITAL RESOURCES The operating subsidiaries generally issue short-term debt to provide for interim financing of capital expenditures that exceed internally generated funds. They periodically reduce their outstanding short-term debt through issuances of long-term debt and preferred stock and with additional capital contributions by the parent company. In 1995 short-term borrowing increased by $48 million. At December 31, 1995, American Electric Power and its subsidiaries had unused short-term lines of credit of $372 million. The sources of funds available to the parent company are dividends from its subsidiaries, short-term and long-term borrowings and, when necessary, proceeds from the issuance of common stock. American Electric Power issued 1,400,000 shares of common stock in 1995 and 700,000 in 1994 through a Dividend Reinvestment Program raising $49 million and $22 million, respectively. As a result of the common stock issuance in 1995 and 1994 and a reduction in long-term debt over the past several years, the common equity to capitalization ratio has steadily improved. At December 31,1995 the ratio increased to 43.1% from 42.1% at year end 1994 and has improved from 41.1% in 1992. At December 31, 1995 the subsidiaries had outstanding $5.06 billion of long-term debt and $671 million of preferred stock. The subsidiaries have regulatory approval to issue up to $1.2 billion of long-term debt. Management expects to use the proceeds of future long-term financing to retire short-term debt, refinance maturing and other long-term debt, refund cumulative preferred stock and fund construction expenditures. 12 PRINCIPAL OPERATING SUBSIDIARIES DEBT & PREFERRED STOCK COVERAGE
Mortgage Preferred December 31, 1995 Debt Stock Appalachian Power Co. 3.47 1.78 Columbus Southern Power Co. 3.90 N/A Indiana Michigan Power Co. 6.25 2.63 Kentucky Power Co. 2.86 N/A Ohio Power Co. 6.17 3.04 N/A - Not Applicable
Unless the subsidiaries meet certain earnings or coverage tests, they cannot issue additional mortgage bonds or preferred stock. In order to issue mortgage bonds (without refunding existing debt), each subsidiary must have pre-tax earnings equal to at least two times the annual interest charges on mortgage bonds after giving effect to the issuance of the new debt. Generally, issuance of additional preferred stock requires an after-tax gross income at least equal to one and one-half times annual interest and preferred stock dividend requirements after giving effect to the issuance of the new preferred stock. The subsidiaries presently exceed these minimum coverage requirements. LITIGATION AEP is involved in a number of legal proceedings and claims. While we are unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters will have a material adverse effect on the results of operations and/or financial condition. EFFECTS OF INFLATION Inflation affects AEP's cost of replacing utility plant and the cost of operating and maintaining its plant. The rate-making process limits our recovery to the historical cost of assets resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis. However, economic gains that results from the repayment of long-term debt with inflated dollars partly offset such losses. NEW ACCOUNTING RULES The Financial Accounting Standards Board (FASB) issued a new accounting standard, SFAS 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," in 1995 effective for 1996 accounting periods. The initial implementation of this new standard is not expected to have a significant impact on the Company. In 1996 the FASB issued an exposure draft Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets. This document proposes that the present value of any decommissioning or other closure or removal obligation be recorded as a liability when the obligation is incurred. A corresponding asset would be recorded in the plant investment account and recovered through depreciation charges over the asset s life. A proposed transition rule would require that an entity report in income the cumulative effect of initially applying the new standard. The Company is currently studying the impact of the proposed rules and evaluating its potential impact. 13 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME (in thousands - except per share amounts)
Year Ended December 31, -------------------------------------- 1995 1994 1993 ---- ---- ---- OPERATING REVENUES $5,670,330 $5,504,670 $5,268,842 ---------- ---------- ---------- OPERATING EXPENSES: Fuel and Purchased Power 1,625,531 1,745,245 1,647,573 Other Operation 1,184,158 1,002,822 970,916 Maintenance 541,825 544,312 523,062 Depreciation and Amortization 593,019 572,189 530,731 Taxes Other Than Federal Income Taxes 489,223 494,210 468,296 Federal Income Taxes 272,027 213,399 199,621 ---------- ---------- ---------- TOTAL OPERATING EXPENSES 4,705,783 4,572,177 4,340,199 ---------- ---------- ---------- OPERATING INCOME 964,547 932,493 928,643 ---------- ---------- ---------- NONOPERATING INCOME: Deferred Zimmer Plant Carrying Charges (net of tax) 3,089 5,604 25,343 Other Nonoperating Income 17,115 5,881 21,229 ---------- ---------- ---------- TOTAL NONOPERATING INCOME 20,204 11,485 46,572 ---------- ---------- ---------- LOSS FROM ZIMMER PLANT DISALLOWANCE: Disallowed Cost - - 159,067 Related Income Taxes - - (14,534) ---------- ---------- ---------- NET ZIMMER LOSS - - 144,533 ---------- ---------- ---------- INCOME BEFORE INTEREST CHARGES AND PREFERRED DIVIDENDS 984,751 943,978 830,682 INTEREST CHARGES (net) 400,077 389,240 418,064 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 54,771 54,726 58,849 ---------- ---------- ---------- NET INCOME $ 529,903 $ 500,012 $ 353,769 ---------- ---------- ---------- ---------- ---------- ---------- AVERAGE NUMBER OF SHARES OUTSTANDING 185,847 184,666 184,535 ---------- ---------- ---------- ---------- ---------- ---------- EARNINGS PER SHARE $2.85 $2.71 $1.92 ---------- ---------- ---------- ---------- ---------- ---------- CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40 ---------- ---------- ---------- ---------- ---------- ----------
__________________ CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (in thousands)
Year Ended December 31, -------------------------------------- 1995 1994 1993 ---- ---- ---- RETAINED EARNINGS JANUARY 1 $1,325,581 $1,269,283 $1,358,800 NET INCOME 529,903 500,012 353,769 DEDUCTIONS: Cash Dividends Declared 445,831 443,101 442,891 Other 8 613 395 ---------- ---------- ---------- RETAINED EARNINGS DECEMBER 31 $1,409,645 $1,325,581 $1,269,283 ---------- ---------- ---------- ---------- ---------- ----------
See Notes to Consolidated Financial Statements. 14 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
Year Ended December 31, -------------------------------------- 1995 1994 1993 ---- ---- ---- OPERATING ACTIVITIES: Net Income $ 529,903 $ 500,012 $ 353,769 Adjustments for Noncash Items: Depreciation and Amortization 578,003 561,188 555,436 Deferred Federal Income Taxes 11,916 (16,033) (62,186) Deferred Investment Tax Credits (25,819) (31,275) (28,222) Amortization of Operating Expenses and Carrying Charges (net) 53,479 16,022 2,997 Loss from Zimmer Plant Disallowance - - 159,067 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (71,804) 34,302 (15,641) Fuel, Materials and Supplies 457 (1,627) 156,464 Accrued Utility Revenues (40,433) 2,419 18,994 Accounts Payable (31,044) (7,959) 47,018 Taxes Accrued 37,515 (26,521) 56,502 Other (net) 14,437 (52,803) 22,469 ---------- ---------- ---------- Net Cash Flows From Operating Activities 1,056,610 977,725 1,266,667 ---------- ---------- ---------- INVESTING ACTIVITIES: Construction Expenditures (605,974) (643,457) (592,199) Proceeds from Sale of Property and Other 20,567 49,802 26,669 ---------- ---------- ---------- Net Cash Flows Used For Investing Activities (585,407) (593,655) (565,530) ---------- ---------- ---------- FINANCING ACTIVITIES: Issuance of Common Stock 48,707 22,256 - Issuance of Cumulative Preferred Stock - 88,787 321,168 Issuance of Long-term Debt 523,476 411,869 1,339,227 Retirement of Cumulative Preferred Stock (158,839) (35,949) (333,992) Retirement of Long-term Debt (469,767) (445,636) (1,696,806) Change in Short-term Debt (net) 48,140 38,009 25,822 Dividends Paid on Common Stock (445,831) (443,101) (442,891) ---------- ---------- ---------- Net Cash Flows Used For Financing Activities (454,114) (363,765) (787,472) ---------- ---------- ---------- Net Increase (Decrease) in Cash and Cash Equivalents 17,089 20,305 (86,335) Cash and Cash Equivalents January 1 62,866 42,561 128,896 ---------- ---------- ---------- Cash and Cash Equivalents December 31 $ 79,955 $ 62,866 $ 42,561 ---------- ---------- ---------- ---------- ---------- ----------
See Notes to Consolidated Financial Statements. 15 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (In Thousands - Except Share Data)
December 31, -------------------------- 1995 1994 ---- ---- ASSETS - ------ ELECTRIC UTILITY PLANT: Production $ 9,238,843 $ 9,172,766 Transmission 3,316,664 3,247,280 Distribution 4,184,251 3,966,442 General (including mining assets and nuclear fuel) 1,442,086 1,529,436 Construction Work in Progress 314,118 258,700 ----------- ----------- Total Electric Utility Plant 18,495,962 18,174,624 Accumulated Depreciation and Amortization 7,111,123 6,826,514 ----------- ----------- NET ELECTRIC UTILITY PLANT 11,384,839 11,348,110 ----------- ----------- OTHER PROPERTY AND INVESTMENTS 825,781 747,422 ----------- ----------- CURRENT ASSETS: Cash and Cash Equivalents 79,955 62,866 Accounts Receivable: Customers (less allowance for uncollectible accounts of $5,430 in 1995 and $4,056 in 1994) 417,854 346,462 Miscellaneous 74,429 74,017 Fuel - at average cost 271,933 306,700 Materials and Supplies - at average cost 251,051 216,741 Accrued Utility Revenues 207,919 167,486 Prepayments and Other 98,717 94,786 ----------- ----------- TOTAL CURRENT ASSETS 1,401,858 1,269,058 ----------- ----------- REGULATORY ASSETS 1,979,446 2,040,997 ----------- ----------- DEFERRED CHARGES 310,377 333,169 ----------- ----------- TOTAL $15,902,301 $15,738,756 ----------- ----------- ----------- -----------
See Notes to Consolidated Financial Statements. 16 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS
December 31, -------------------------- 1995 1994 ---- ---- CAPITALIZATION AND LIABILITIES - ------------------------------ CAPITALIZATION: Common Stock-Par Value $6.50: 1995 1994 ---- ---- Shares Authorized. .300,000,000 300,000,000 Shares Issued. . . .195,634,992 194,234,992 (8,999,992 shares were held in treasury) $ 1,271,627 $ 1,262,527 Paid-in Capital 1,658,524 1,640,661 Retained Earnings 1,409,645 1,325,581 ----------- ----------- Total Common Shareholders' Equity 4,339,796 4,228,769 Cumulative Preferred Stocks of Subsidiaries:* Not Subject to Mandatory Redemption 148,240 233,240 Subject to Mandatory Redemption 515,085 590,300 Long-term Debt* 4,920,329 4,686,648 ----------- ----------- TOTAL CAPITALIZATION 9,923,450 9,738,957 ----------- ----------- OTHER NONCURRENT LIABILITIES 884,707 794,478 ----------- ----------- CURRENT LIABILITIES: Preferred Stock and Long-term Debt Due Within One Year* 144,597 293,756 Short-term Debt 365,125 316,985 Accounts Payable 220,142 251,186 Taxes Accrued 420,192 382,677 Interest Accrued 80,848 88,916 Obligations Under Capital Leases 89,692 93,252 Other 304,466 281,124 ----------- ----------- TOTAL CURRENT LIABILITIES 1,625,062 1,707,896 ----------- ----------- DEFERRED INCOME TAXES 2,656,651 2,657,062 ----------- ----------- DEFERRED INVESTMENT TAX CREDITS 430,041 456,043 ----------- ----------- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 249,875 259,152 ----------- ----------- DEFERRED CREDITS 132,515 125,168 ----------- ----------- CONTINGENCIES (Note 4) TOTAL $15,902,301 $15,738,756 ----------- ----------- ----------- -----------
*See Accompanying Schedules on pages 34 - 35. 17 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SIGNIFICANT ACCOUNTING POLICIES: The American Electric Power System (AEP, AEP System or the Company) is a public utility engaged in the generation, purchase, transmission and distribution of electric power to over 2.9 million retail customers in its seven state service territory which covers portions of Ohio, Michigan, Indiana, Kentucky, West Virginia, Virginia and Tennessee. Electric power is also supplied at wholesale to neighboring utility systems. The organization of the AEP System consists of American Electric Power Company, Inc., the parent holding company; seven electric utility operating companies (utility subsidiaries); a generating subsidiary, AEP Generating Company (AEPGEN); a service company, American Electric Power Service Corporation (AEPSC); and three active coal-mining companies. The five largest utility subsidiaries, which pool their generating and transmission facilities and operate them as an integrated system, are: - - Appalachian Power Company (APCo) - - Columbus Southern Power Company (CSPCo) - - Indiana Michigan Power Company (I&M) - - Kentucky Power Company (KEPCo) - - Ohio Power Company (OPCo) The remaining two utility subsidiaries, Kingsport Power Company and Wheeling Power Company, are distribution companies that purchase power from APCo and OPCo, respectively. AEPSC provides management and professional services to the AEP System. The active coal-mining companies are wholly-owned by OPCo and sell substantially all of their production to OPCo. AEPGEN has a 50% interest in the Rockport Plant which is comprised of two of the AEP System's six 1,300 megawatt (mw) generating units. Effective January 1, 1996, AEPSC and the seven utility subsidiaries began operating as American Electric Power. There has been no change to the legal names of these companies. The AEP System s operations are divided into four major business units which are managed centrally by AEPSC. The four business units are Power Generation, Nuclear Generation, Energy Delivery and Corporate Development. RATE REGULATION - The AEP System is subject to regulation by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (1935 Act). The rates charged by the utility subsidiaries are approved by the Federal Energy Regulatory Commission (FERC) or one of the state utility commissions as applicable. The FERC regulates wholesale rates and the state commissions regulate retail rates. PRINCIPLES OF CONSOLIDATION - The consolidated financial statements include American Electric Power Company, Inc.(AEPCo., Inc.) and its wholly-owned subsidiaries consolidated with their wholly-owned subsidiaries. Significant intercompany items are eliminated in consolidation. BASIS OF ACCOUNTING - As the owner of cost-based rate-regulated electric public utility companies, AEPCo., Inc.'s consolidated financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation, regulatory assets and liabilities are recorded to reflect the economic effects of regulation. -18- USE OF ESTIMATES - The preparation of these financial statements in conformity with generally accepted accounting principles requires in certain instances the use of management's estimates. Actual results could differ from those estimates. UTILITY PLANT - Electric utility plant is stated at original cost and is generally subject to first mortgage liens. Additions, major replacements and betterments are added to the plant accounts. Retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreciation. The costs of labor, materials and overheads incurred to operate and maintain utility plant are included in operating expenses. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) - AFUDC is a noncash nonoperating income item that is recovered over the service life of utility plant through depreciation and represents the estimated cost of borrowed and equity funds used to finance construction projects. The average rates used to accrue AFUDC were 6.91%, 6.59%, and 5.84% in 1995, 1994 and 1993, respectively. DEPRECIATION, DEPLETION AND AMORTIZATION - Depreciation is provided on a straight-line basis over the estimated useful lives of property other than coal-mining property and is calculated largely through the use of composite rates by functional class as follows: FUNCTIONAL CLASS COMPOSITE OF PROPERTY ANNUAL RATES - ---------------- ------------ Production: Steam-Nuclear 3.4% Steam-Fossil-Fired 3.2% to 4.4% Hydroelectric-Conventional and Pumped Storage 2.5% to 3.2% Transmission 1.7% to 2.7% Distribution 3.4% to 4.2% General 2.0% to 3.8% The utility subsidiaries presently recover amounts to be used for demolition of non-nuclear plant through depreciation charges included in rates. Depreciation, depletion and amortization of coal-mining assets is provided over each asset's estimated useful life, ranging up to 30 years, and is calculated using the straight-line method for mining structures and equipment. The units-of-production method is used for coal rights and mine development costs based on estimated recoverable tonnages at a current average rate of $1.07 per ton. These costs are included in the cost of coal charged to fuel expense. CASH AND CASH EQUIVALENTS - Cash and cash equivalents include temporary cash investments with original maturities of three months or less. SALE OF RECEIVABLES - Under an agreement that expires in 2000, CSPCo can sell up to $50 million of undivided interests in designated pools of accounts receivable and accrued utility revenues with limited recourse. As collections reduce previously sold pools, interests in new pools are sold. At December 31, 1995, 1994 and 1993, $50 million remained to be collected and remitted to the buyer. -19- OPERATING REVENUES - Revenues include the accrual of electricity consumed but unbilled at month-end as well as billed revenues. FUEL COSTS - Fuel costs are matched with revenues in accordance with rate commission orders. Generally in the retail jurisdictions, changes in fuel costs are deferred or revenues accrued until approved by the regulatory commission for billing to customers in later months. Wholesale jurisdictional fuel cost changes are expensed and billed as incurred. LEVELIZATION OF NUCLEAR REFUELING OUTAGE COSTS - Incremental operation and maintenance costs associated with refueling outages at the Company's Donald C. Cook Nuclear Plant (Cook Plant) are deferred for amortization over the period (generally eighteen months) beginning with the commencement of an outage until the beginning of the next outage. INCOME TAXES - The Company follows the liability method of accounting for income taxes as prescribed by SFAS 109, Accounting for Income Taxes. Under the liability method, deferred income taxes are provided for all temporary differences between book cost and tax basis of assets and liabilities which will result in a future tax consequence. Where the flow-through method of accounting for temporary differences is reflected in rates, regulatory assets and liabilities are recorded in accordance with SFAS 71. INVESTMENT TAX CREDITS - Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Deferred investment tax credits are being amortized over the life of the related plant investment. DEBT AND PREFERRED STOCK - Gains and losses on reacquired debt are deferred and amortized over the remaining term of the reacquired debt in accordance with rate-making treatment. If the debt is refinanced the reacquisition costs are deferred and amortized over the term of the replacement debt commensurate with their recovery in rates. Debt discount or premium and debt issuance expenses are amortized over the term of the related debt, with the amortization included in interest charges. Redemption premiums paid to reacquire preferred stock are deferred, debited to paid-in capital and amortized to retained earnings in accordance with rate-making treatment. The excess of par value over costs of preferred stock reacquired to meet sinking fund requirements is credited to paid-in capital. OTHER PROPERTY AND INVESTMENTS - Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are recorded at market value in accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. Due to the rate-making process, adjustments for unrealized gains and losses are not reported in equity but result in adjustments to regulatory assets and liabilities. Excluding the decommissioning and spent nuclear fuel disposal trust funds, other property and investments are stated at cost. RECLASSIFICATIONS - Certain prior-period amounts were reclassified to conform with current-period presentation. -20- 2. RATE MATTERS: BASE RATE ACTIVITY - In March 1995 a Settlement Agreement was approved by the Public Utilities Commission of Ohio (PUCO) that resolved a July 1994 base rate case and a pending electric fuel component (EFC) proceeding. Under the terms of the Settlement Agreement, base rates increased by $66 million annually in March 1995 which includes recovery of the cost of the flue gas desulfurization systems (scrubbers) installed at the Gavin Plant; the EFC rate is fixed at 1.465 cents per kwh from June 1995 through November 1998; OPCo is provided with the opportunity to recover its Ohio jurisdictional share of its investment in and the liabilities and the future shut-down costs of its affiliated mines as well as any fuel costs incurred above the fixed rate; and OPCo may proceed with its Clean Air Act Amendments of 1990 (CAAA) compliance plan as filed with the PUCO. The Settlement Agreement allows the Company to continue to operate the affiliated Muskingum and Windsor mines. RECOVERY OF FUEL COSTS - Under the terms of a 1992 stipulation agreement the cost of coal burned at the Gavin Plant is subject to a 15-year predetermined price of $1.575 per million Btu's with quarterly escalation adjustments through November 2009. (As discussed above the Settlement Agreement fixes the EFC factor at 1.465 cents per kwh for the period June 1, 1995 through November 30, 1998.) After November 2009 the price that OPCo can recover for coal from its affiliated Meigs mine which supplies the Gavin Plant will be limited to the lower of cost or the then-current market price. The stipulation agreement, in conjunction with the above-referenced Settlement Agreement, provides OPCo with an opportunity to accelerate recovery of its investment in and the liabilities and closing costs and any operating losses incurred under the fixed EFC period of its affiliated mining operations attributable to its Ohio jurisdiction to the extent the actual cost of coal burned at the Gavin Plant is below the predetermined price. Based on the estimated future cost of coal burned at Gavin Plant, management believes that the Ohio jurisdictional portion of the investment in and liabilities and closing costs of the affiliated mining operations will be recovered under the terms of the predetermined price agreement. Management intends to seek from ratepayers recovery of the non-Ohio jurisdictional portion of the investment in and the liabilities and closing costs of the affiliated Meigs, Muskingum and Windsor mines. The non-Ohio jurisdictional portion of shutdown costs for these mines which includes the investment in the mines, leased asset buy-outs, reclamation costs and employee benefits is estimated to be approximately $195 million after tax at December 31, 1995. The affiliated Muskingum and Windsor mines may have to close by January 2000 as part of compliance with Phase II requirements of the CAAA. The Muskingum and/or Windsor mines could close prior to January 2000 depending on the economics of continued operation under the terms of the above Settlement Agreement. Unless future shutdown costs and/or the cost of affiliated coal production of the Meigs, Muskingum and Windsor mines can be recovered, results of operations would be adversely affected. 3. EFFECTS OF REGULATION AND PHASE-IN PLANS: The consolidated financial statements include assets and liabilities recorded in accordance with regulatory actions to match expenses and revenues in cost-based rates. The assets are expected to be recovered in future periods through the rate-making process and the liabilities are expected to reduce future cost recoveries. The Company has reviewed -21- all the evidence currently available and concluded that it continues to meet the requirements to apply SFAS 71. In the event a portion of the Company's business no longer met these requirements regulatory assets would have to be written off for that portion of the business. Regulatory assets and liabilities are comprised of the following:
December 31, ------------------------------ 1995 1994 ---- ---- (In Thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $1,446,485 $1,458,807 Rate Phase-in Plan Deferrals 74,402 118,553 Unamortized Loss on Reacquired Debt 109,551 108,777 Other 349,008 354,860 ---------- ---------- Total Regulatory Assets $1,979,446 $2,040,997 ---------- ---------- ---------- ---------- Regulatory Liabilities: Deferred Investment ax Credits $430,041 $456,043 Other Regulatory Liabilities* 86,347 76,468 --------- --------- Total Regulatory Liabilities $516,388 $532,511 -------- -------- -------- -------- * Included in Deferred Credits on Consolidated Balance Sheets
The rate phase-in plan deferrals are applicable to the Zimmer Plant Unit and the Rockport Plant Unit 1. The Zimmer Plant is a 1,300 mw coal- fired plant which commenced commercial operation in 1991. CSPCo owns 25.4% of the plant with the remainder owned by two unaffiliated companies. In May 1992 the PUCO issued an order providing for a phased in rate increase of $123 million to be implemented in three steps over a two-year period and disallowed $165 million of Zimmer Plant investment. CSPCo appealed the PUCO ordered Zimmer disallowance and phase-in plan to the Ohio Supreme Court. In November 1993 the Supreme Court issued a decision on CSPCo's appeal affirming the disallowance and finding that the PUCO did not have statutory authority to order phased-in rates. The Court instructed the PUCO to fix rates to provide gross annual revenues in accordance with the law and to provide a mechanism to recover the amounts deferred under the phase-in order. As a result of the ruling, 1993 net income was reduced by $144.5 million after tax to reflect the disallowance and in January 1994, the PUCO approved a 7.11% rate increase effective February 1, 1994. The increase is comprised of a 3.72% base rate increase to complete the rate increase phase- in and a temporary 3.39% surcharge, which will be in effect until the deferrals are recovered, estimated to be 1998. In 1995 and 1994 $28.5 million and $18.5 million, respectively, of net phase-in deferrals were collected through the surcharge which reduced the deferrals from $93.9 million at December 31, 1993 to $75.4 million at December 31, 1994 and $46.9 million at December 31, 1995. In 1993 and 1992, $47.9 million and $46 million, respectively, were deferred under the phase-in plan. The recovery of amounts deferred under the phase-in plan and the increase in rates to the full rate level did not affect net income. From the in-service date of March 1991 until rates went into effect in May 1992 deferred carrying charges of $43 million were recorded on the Zimmer Plant investment. Recovery of the deferred carrying charges will be sought in the next PUCO base rate proceeding in accordance with the PUCO accounting order that authorized the deferral. The Rockport Plant consists of two 1,300 mw coal-fired units. I&M and AEPGEN each own 50% of one unit (Rockport 1) and lease a 50% interest in the other unit (Rockport 2) from unaffiliated lessors under an operating lease. The gain on the sale and 22 leaseback of Rockport 2 was deferred and is being amortized, with related taxes, over the initial lease term which expires in 2022. Rate phase-in plans in I&M's Indiana and FERC jurisdictions for its share of Rockport 1 provide for the recovery and straight-line amortization through 1997 of prior-year deferrals. Unamortized deferred amounts under the phase-in plans were $27.5 million and $43.2 million at December 31, 1995 and 1994, respectively. Amortization was $16 million in 1995, 1994 and 1993. 4. COMMITMENTS AND CONTINGENCIES: CONSTRUCTION AND OTHER COMMITMENTS - The AEP System has made substantial construction commitments for utility operations. Such commitments do not presently include any expenditures for new generating capacity. The aggregate construction program expenditures for 1996-1998 are estimated to be $2 billion. Long-term fuel supply contracts contain clauses for periodic adjustments, and most jurisdictions have fuel clause mechanisms that provide for recovery of changes in the cost of fuel with the regulators' review and approval. The contracts are for various terms, the longest of which extend to the year 2014, and contain various clauses that would release the Company from its obligation under certain force majeure conditions. The AEP System has contracted to sell up to 1,300 mw of capacity to unaffiliated utilities. The Company has an obligation to deliver energy under certain unit power agreements regardless of whether the unit capacity is available. The power sales contracts expire from 1997 to 2010. NUCLEAR PLANT - I&M owns and operates the two-unit 2,110 mw Cook Plant under licenses granted by a regulatory authority. The operation of a nuclear facility involves special risks, potential liabilities, and specific regulatory and safety requirements. Should a nuclear incident occur at any nuclear power plant facility in the United States, the resultant liability could be substantial. 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. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery is not possible, results of operations and financial condition could be negatively affected. NUCLEAR INCIDENT LIABILITY - Public liability is limited by law to $8.9 billion should an incident occur at any licensed reactor in the United States. Commercially available insurance provides $200 million of coverage. In the event of a nuclear incident at any nuclear plant in the United States the remainder of the liability would be provided by a deferred premium assessment of $79.3 million on each licensed reactor payable in annual installments of $10 million. As a result, I&M could be assessed $158.6 million per nuclear incident payable in annual installments of $20 million. The number of incidents for which payments could be required is not limited. Nuclear insurance pools and other insurance policies provide $3.6 billion of property damage, decommissioning and decontamination coverage for the Cook Plant. Additional insurance provides coverage for extra costs resulting from a prolonged accidental Cook Plant outage. Some of the policies have deferred premium provisions which could be triggered by losses in excess of the insurer's resources. The losses could result from claims at the Cook Plant or certain other non-affiliated nuclear units. I&M could be assessed up to $40.9 million under these policies. 23 SPENT NUCLEAR FUEL DISPOSAL - Federal law provides for government responsibility for permanent spent nuclear fuel disposal and assesses nuclear plant owners fees for spent fuel disposal. A fee of one mill per kilowatthour for fuel consumed after April 6, 1983 is being collected from customers and remitted to the U.S. Treasury. Fees and related interest of $163 million for fuel consumed prior to April 7, 1983 have been recorded as long-term debt. I&M has not paid the government the pre-April 1983 fees due to various factors including continued delays and uncertainties related to the federal disposal program. At December 31, 1995, funds collected from customers to eventually pay the pre-April 1983 fee and related earnings including accrued interest approximated the liability. DECOMMISSIONING AND LOW LEVEL WASTE ACCUMULATION DISPOSAL - Decommissioning costs are accrued over the service life of the Cook Plant. The licenses to operate the two nuclear units expire in 2014 and 2017. After expiration of the licenses the plant is expected to be decommissioned through dismantlement. The Company's latest estimate for decommissioning and low level radioactive waste accumulation disposal costs range from $634 million to $988 million in 1993 nondiscounted dollars. The wide range is caused by variables in assumptions including the estimated length of time spent nuclear fuel must be stored at the plant subsequent to ceasing operations. This in turn depends on future developments in the federal government's spent nuclear fuel disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is recovering estimated decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding. I&M records decommissioning costs in other operation expense and records a noncurrent liability equal to the decommissioning cost recovered in rates; such amount was $30 million in 1995, $26 million in 1994 and $13 million in 1993. Decommissioning amounts recovered from customers are deposited in external trusts. Trust fund earnings increase the fund assets and the recorded liability and decrease the amount to be recovered from ratepayers. At December 31, 1995 I&M has recognized a decommissioning liability of $269 million. LITIGATION - The Company is involved in a number of legal proceedings and claims. While management is unable to predict the ultimate outcome of litigation, it is not expected that the resolution of these matters will have a material adverse effect on the results of operations or financial condition. 5. DIVIDEND RESTRICTIONS: Mortgage indentures, debentures, charter provisions and orders of regulatory authorities place various restrictions on the use of the subsidiaries' retained earnings for the payment of cash dividends on their common stocks. At December 31, 1995, $230 million of retained earnings were restricted. To pay dividends out of paid-in capital the subsidiaries need regulatory approval. 6. LINES OF CREDIT AND COMMITMENT FEES: At December 31, 1995 and 1994 unused short-term bank lines of credit were available in the amounts of $372 million and $558 million, respectively. Commitment fees of approximately 1/8 of 1% of the unused short-term lines of credit are paid each year to the banks to maintain the lines of credit. 24 Outstanding short-term debt consisted of:
December 31, ----------------------- (Dollars In Thousands) 1995 1994 ---- ---- Balance Outstanding: Notes Payable $128,425 $ 42,535 Commercial Paper 236,700 274,450 -------- -------- Total $365,125 $316,985 -------- -------- -------- -------- Year-End Weighted Average Interest Rate: Notes Payable 6.1% 6.2% Commercial Paper 6.1% 6.3% Total 6.1% 6.3%
7. BENEFIT PLANS: AEP SYSTEM PENSION PLAN - The AEP pension plan is a trusteed, noncontributory defined benefit plan covering all employees meeting eligibility requirements, except participants in the United Mine Workers of America (UMWA) pension plans. Benefits are based on service years and compensation levels. The funding policy is to make annual trust fund contributions equal to the net periodic pension cost up to the maximum amount deductible for federal income taxes, but not less than the minimum required contribution in accordance with the Employee Retirement Income Security Act of 1974. Net AEP pension plan costs were computed as follows:
Year Ended December 31, -------------------------------- 1995 1994 1993 ---- ---- ---- (In Thousands) Service Cost-Benefits Earned During the Year $ 30,400 $ 40,000 $ 37,100 Interest Cost on Projected Benefit Obligation 116,700 114,500 112,600 Actual Return on Assets (416,800) (6,700) (150,000) Net Amortization and Deferral 281,800 (123,300) 24,700 -------- -------- -------- Net AEP Pension Plan Costs $ 12,100 $ 24,500 $ 24,400 -------- -------- -------- -------- -------- --------
AEP pension plan assets and actuarially computed benefit obligations are:
December 31, ------------------------- 1995 1994 ---- ---- (In Thousands) AEP Pension Plan Assets at Fair Value (a) $1,805,300 $1,480,600 ---------- ---------- Actuarial Present Value of Benefit Obligation: Vested 1,321,600 1,130,000 Nonvested 147,400 120,700 ---------- ---------- Accumulated Benefit Obligation 1,469,000 1,250,700 Effects of Salary Progression 181,000 132,600 ---------- ---------- Projected Benefit Obligation 1,650,000 1,383,300 ---------- ---------- Funded Status - AEP Pension Plan Assets in Excess of Projected Benefit Obligation 155,300 97,300 Unrecognized Prior Service Cost 147,000 160,800 Unrecognized Net Gain (295,200) (229,000) Unrecognized Net Transition Assets (Being Amortized Over 17 Years) (78,700) (88,600) ---------- ---------- Accrued Net AEP Pension Plan Liability $ (71,600) $ (59,500) ---------- ---------- ---------- ----------
(a) AEP pension plan assets primarily consist of common stocks, bonds and cash equivalents and are included in a separate entity Trust Fund. Assumptions used to determine AEP pension plan's funded status were:
December 31, ------------------------ 1995 1994 1993 ---- ---- ---- Discount Rate 7.25% 8.5% 7.0% Average Rate of Increase in Compensation Levels 3.2% 3.2% 3.2% Expected Long-Term Rate of Return on Plan Assets 9.0% 8.5% 9.0%
25 AEP SYSTEM SAVINGS PLAN - An employee savings plan is offered to non-UMWA employees which allows participants to contribute up to 17% of their salaries into various investment alternatives, including AEP common stock. An employer matching contribution, equaling one-half of the employees' contribution to the plan up to a maximum of 3% of the employees' base salary, is invested in AEP common stock. The employer's annual contributions totaled $18.8 million in 1995, $18.6 million in 1994 and $17.6 million in 1993. UMWA PENSION PLANS - The coal-mining subsidiaries of OPCo provide UMWA pension benefits for UMWA employees meeting eligibility requirements. Benefits are based on age at retirement and years of service. As of June 30, 1995, the UMWA actuary estimates the OPCo coal-mining subsidiaries' share of the UMWA pension plans unfunded vested liabilities was approximately $35 million. In the event the OPCo coal-mining subsidiaries cease or significantly reduce mining operations or contributions to the UMWA pension plans, a withdrawal obligation may be triggered for all or a portion of their share of the unfunded vested liability. Contributions are based on the number of hours worked, are expensed when paid and totaled $1.4 million in 1995 and $1.6 million in both 1994 and 1993. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (OPEB) - The AEP System provides certain other benefits for retired employees. Substantially all non-UMWA employees are eligible for postretirement health care and life insurance if they have at least 10 service years and are age 55 at retirement. Postretirement medical benefits for OPCo's UMWA employees who have or will retire after January 1, 1976 are the liability of the OPCo coal-mining subsidiaries. They are eligible for postretirement medical and life insurance benefits if they have at least 10 service years and are age 55 at retirement. Non-active UMWA employees become eligible at age 55 if they have had 20 service years. Management has taken several measures to reduce its OPEB costs. First, a Voluntary Employees Beneficiary Association (VEBA) trust fund for OPEB benefits for all non-UMWA employees was established. In addition, to help fund and reduce the future costs of OPEB benefits, a corporate owned life insurance (COLI) program was implemented, except where restricted by state law. The insurance policies have a substantial cash surrender value which is recorded, net of equally substantial policy loans, in other property and investments. Legislation was passed by Congress which would have significantly reduced the tax benefits of a COLI program for the future. The legislation containing this provision was vetoed by the President. At this time it is uncertain if legislation repealing certain tax benefits from COLI programs will be enacted. If enacted this legislation would negatively impact the effectiveness of the COLI program as a funding and cost reduction mechanism. For jurisdictions where OPEB costs are reflected in cost of service, the funding policy is to make VEBA trust fund contributions equal to the increase in OPEB costs resulting from the January 1993 implementation of SFAS 106, "Employers Accounting for Postretirement Benefits Other Than Pensions." These contributions include amounts collected from ratepayers and the net earnings from the COLI program. For jurisdictions where recovery has not been approved and rates are insufficient to absorb these additional costs, the funding policy is to contribute cash generated by the COLI program. Contribution to the VEBA trust fund, including amounts funded by the COLI program, were $53 million in 1995, $29.5 million in 1994 and $21.5 million in 1993. 26 The utility subsidiaries received approval in several jurisdictions to recover their increased OPEB costs resulting from the implementation of SFAS 106. For those jurisdictions where recovery has not been approved and rates are insufficient to absorb these additional costs, the utility subsidiaries received regulatory authority to defer the increased OPEB costs which are not being currently recovered in rates. Future recovery of the deferrals and the annual ongoing OPEB costs will be sought by the utility subsidiaries in their next base rate filings. At December 31, 1995 and 1994, $24.6 million and $28.5 million, respectively, of incremental OPEB costs were deferred. Aggregate OPEB costs were computed as follows:
Year Ended December 31, ------------------------------ 1995 1994 1993 ---- ---- ---- (In Thousands) Service Cost $ 13,500 $16,500 $15,700 Interest Cost on Projected Benefit Obligation 54,900 47,300 45,300 Net Amortization of Transition Obligation 32,000 31,100 28,200 Return on Plan Assets (25,400) 900 (1,000) Net Amortization and Deferral 16,800 (6,800) - -------- -------- -------- Net OPEB Costs $ 91,800 $89,000 $88,200 -------- -------- -------- -------- -------- --------
OPEB assets and actuarially computed benefit obligations are:
December 31, -------------------- 1995 1994 ---- ---- (In Thousands) Fair Market Value of Plan Assets (a) $ 165,600 $ 87,200 --------- --------- Accumulated Postretirement Benefit Obligation: Active Employees Fully Eligible for Benefits 59,200 41,200 Current Retirees 398,400 361,500 Other Active Employees 282,400 245,800 --------- --------- Total Benefit Obligation 740,000 648,500 --------- --------- Unfunded Benefit Obligation (574,400) (561,300) Unrecognized Net Loss 48,500 8,900 Unrecognized Net Transition Obligation Being Amortized Over 20 Years 485,600 517,700 --------- --------- Accrued Net OPEB Liability $ (40,300) $ (34,700) --------- --------- --------- ---------
(a) Plan assets consist of cash surrender value of life insurance contracts on certain employees owned by the trust and short-term tax exempt municipal bonds. Assumptions used to determine OPEB's funded status were:
December 31, -------------------- 1995 1994 1993 ---- ---- ---- Discount Rate 7.25% 8.5 % 7.0 % Expected Long-Term Rate of Return on Plan Assets 8.75% 8.25% 8.75% Initial Medical Cost Trend Rate 8.0 % 8.0 % 8.0 % Ultimate Medical Cost Trend Rate 4.5 % 5.25% 4.25% Medical Cost Trend Rate Decreases to Ultimate Rate in Year 2005 2005 2005
Assuming a one percent increase in the medical cost trend rate, the 1995 OPEB cost for all employees, both non-UMWA and UMWA, would increase by $9 million and the accumulated benefit obligations would increase by $78 million. 27 Several UMWA health plans pay the postretirement medical benefits for the Company's UMWA retirees who retired before January 2, 1976 and their survivors plus retirees and others whose last employer is no longer a signatory to the UMWA contract or is no longer in business. The UMWA health plans are funded by payments from current and former UMWA wage agreement signatories, the 1950 UMWA Pension Plan surplus and the Abandoned Mine Land Reclamation Fund Surplus. Required annual payments to the UMWA health funds made by AEP's active and inactive coal-mining subsidiaries were recognized as expense when paid and totaled $2.8 million in 1995, $3.1 million in 1994 and $3.8 million in 1993. By law excess Black Lung Trust funds may be used to pay certain postretirement medical benefits under one of the UMWA health plans. Excess AEP Black Lung Trust funds used to reimburse the coal companies totaled $7.9 million in 1995, $6.9 million in 1994 and $10 million in 1993. The Black Lung Trust had excess funds at December 31, 1995, 1994 and 1993 of $13 million, $16 million and $18 million, respectively. 8. FAIR VALUE OF FINANCIAL INSTRUMENTS: NUCLEAR TRUST FUNDS RECORDED AT MARKET VALUE - The trust investments, reported in other property and investments, are recorded at market value in accordance with SFAS 115 and consist primarily of long-term tax-exempt municipal bonds. At December 31, 1995 and 1994 the fair values of the trust investments were $434 million and $353 million, respectively. Accumulated gross unrealized holding gains and losses were $19.1 million and $1.0 million, respectively, at December 31, 1995. The change in market value was a $24.9 million net holding gain in 1995 and a $27.1 million net holding loss in 1994. The trust investments' cost basis by security type were:
December 31, ----------------------- 1995 1994 ---- ---- (In Thousands) Treasury Bonds $ 14,963 $ 997 Tax-Exempt Bonds 336,073 332,098 Equity Securities 24,101 1,665 Cash, Cash Equivalents and Interest Accrued 40,356 25,304 -------- -------- Total $415,493 $360,064 -------- --------
Proceeds from sales and maturities of securities of $78.2 million during 1995 resulted in $1.4 million of realized gains and $0.3 million of realized losses. Proceeds from sales and maturities of securities of $20.1 million during 1994 resulted in $52,000 of realized gains and $155,000 of realized losses. The cost of securities for determining realized gains and losses is original acquisition cost including amortized premiums and discounts. At December 31, 1995, the year of maturity of trust fund investments other than equity securities, was:
(In Thousands) 1996 $ 55,748 1997 - 2000 96,882 2001 - 2005 162,563 After 2005 76,199 -------- Total $391,392 --------
OTHER FINANCIAL INSTRUMENTS RECORDED AT HISTORICAL COST - The carrying amounts 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. Fair values for preferred stock subject to mandatory redemption were $544 million and $537 million and for long-term debt were $5.3 billion and $4.7 billion at December 31, 1995 and 1994, respectively. The carrying amounts for preferred stock subject to mandatory redemption were $523 million and $590 million and for long-term debt were $5.1 billion and $5.0 billion at December 31, 1995 and 1994, respectively. Fair values are 28 based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments of the same remaining maturities. The carrying amount of the pre-April 1983 spent nuclear fuel disposal liability approximates the Company's best estimate of its fair value. 9. FEDERAL INCOME TAXES: The details of federal income taxes as reported are as follows:
Year Ended December 31, -------------------------------- 1995 1994 1993 ---- ---- ---- (In Thousands) Charged (CREDITED) to Operating Expenses (net): Current $265,313 $240,655 $270,318 Deferred 22,990 (10,177) (53,462) Deferred Investment Tax Credits (16,276) (17,079) (17,235) -------- -------- -------- Total 272,027 213,399 199,621 -------- -------- -------- Charged (CREDITED) to Nonoperating Income (net): Current 11,325 (2,907) 8,727 Deferred (11,074) (5,856) 4,603 Deferred Investment Tax Credits (9,543) (14,196) (9,780) -------- -------- -------- Total (9,292) (22,959) 3,550 -------- -------- -------- Credited to Loss from Zimmer Plant Disallowance (net): Deferred - - (13,327) Deferred Investment Tax Credits - - (1,207) -------- -------- -------- Total - - (14,534) -------- -------- -------- Total Federal Income Tax as Reported $262,735 $190,440 $188,637 -------- -------- --------
The following is a reconciliation of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory tax rate, and the amount of federal income taxes reported.
Year Ended December 31, -------------------------------- 1995 1994 1993 (In Thousands) Income Before Preferred Stock Dividend Requirements of Subsidiaries $584,674 $554,738 $412,618 Federal Income Taxes 262,735 190,440 188,637 -------- -------- -------- Pre-Tax Book Income $847,409 $745,178 $601,255 -------- -------- -------- -------- -------- -------- Federal Income Tax on Pre-Tax Book Income at Statutory Rate (35%) $296,593 $260,812 $210,439 Increase (Decrease) in Federal Income Tax Resulting from the Following Items: Depreciation 46,453 31,212 27,554 Removal Costs (14,640) (13,818) (17,730) Corporate Owned Life Insurance (25,506) (22,970) (27,310) Investment Tax Credits (net) (26,179) (31,273) (28,218) Zimmer Plant Disallowance - - 42,346 Federal Income Tax Accrual Adjustments - (16,100) (6,500) Other (13,986) (17,423) (11,944) -------- -------- -------- Total Federal Income Taxes as Reported $262,735 $190,440 $188,637 -------- -------- -------- -------- -------- -------- Effective Federal Income Tax Rate 31.0% 25.6% 31.4% ----- ----- ----- ----- ----- -----
29 The following tables show the elements of the net deferred tax liability and the significant temporary differences:
December 31, --------------------- 1995 1994 ---- ---- (In Thousands) Deferred Tax Assets $ 723,196 $ 657,298 Deferred Tax Liabilities (3,379,847) (3,314,360) ----------- ----------- Net Deferred Tax Liabilities $(2,656,651) $(2,657,062) ----------- ----------- ----------- ----------- Property Related Temporary Differences $(2,139,387) $(2,098,304) Amounts Due From Customers For Future Federal Income Taxes (442,311) (444,305) Deferred State Income Taxes (183,981) (183,987) All Other (net) 109,028 69,534 ----------- ----------- Total Net Deferred Tax Liabilities $(2,656,651) $(2,657,062) ----------- ----------- ----------- -----------
The Company has settled with the Internal Revenue Service (IRS) all issues from the audits of the consolidated federal income tax returns for the years prior to 1991. Returns for the years 1991 through 1993 are presently being audited by the IRS. In the opinion of management, the final settlement of open years will not have a material effect on results of operations. 10. LEASES: Leases of property, plant and equipment are for periods up to 35 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals are primarily charged to operating expenses in accordance with rate-making treatment. The components of rentals are as follows:
Year Ended December 31, ------------------------------ 1995 1994 1993 ---- ---- ---- (In Thousands) Operating Leases $259,877 $233,805 $243,190 Amortization of Capital Leases 101,068 79,116 84,226 Interest on Capital Leases 27,542 23,280 23,839 -------- -------- -------- Total Rental Payments $388,487 $336,201 $351,255 -------- -------- -------- -------- -------- --------
30 Properties under capital leases and related obligations on the Consolidated Balance Sheets are as follows:
December 31, ----------------------------- 1995 1994 ---- ---- (In Thousands) ELECTRIC UTILITY PLANT: Production $ 44,849 $ 44,683 Transmission 7 38 Distribution 14,753 14,717 General: Nuclear Fuel (net of amortization) 69,442 89,478 Mining Plant and Other 424,952 403,038 -------- -------- Total Electric Utility Plant 554,003 551,954 Accumulated Amortization 179,952 173,641 -------- -------- Net Electric Utility Plant 374,051 378,313 -------- -------- OTHER PROPERTY 34,536 24,724 Accumulated Amortization 3,994 2,838 -------- -------- Net Other Property 30,542 21,886 -------- -------- Net Property under Capital Leases $404,593 $400,199 -------- -------- -------- -------- Obligations under Capital Leases $404,593 $400,199 Less Portion Due Within One Year 89,692 93,252 -------- -------- Noncurrent Capital Lease Liability $314,901 $306,947 -------- -------- -------- --------
Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets. Future minimum lease rentals, consisted of the following at December 31, 1995:
Noncancelable Capital Operating Leases Leases ------- ------------- (In Thousands) 1996 $ 86,495 $ 244,228 1997 72,576 239,800 1998 56,165 231,449 1999 47,531 229,296 2000 39,547 227,506 Later Years 156,895 4,092,193 --------- ---------- Total Future Minimum Lease Rentals 459,209(a) $5,264,472 ---------- ---------- Less Estimated Interest Element 124,058 -------- Estimated Present Value of Future Minimum Lease Rentals 335,151 Unamortized Nuclear Fuel 69,442 -------- Total $404,593 -------- --------
(a) Minimum lease rentals do not include nuclear fuel rentals. The rentals are paid in proportion to heat produced and carrying charges on the unamortized nuclear fuel balance. There are no minimum lease payment requirements for leased nuclear fuel. 31 11. SUPPLEMENTARY INFORMATION:
Year Ended December 31, ------------------------------ 1995 1994 1993 ---- ---- ---- (In Thousands) Purchased Power - Ohio Valley Electric Corp. (44.2% owned by AEP) $10,546 $5,755 $19,253 Cash was paid for: Interest (net of capitalized amounts) $395,169 $379,361 $421,060 Income Taxes $273,671 $312,233 $245,350 Noncash Acquisitions under Capital Leases were $106,256 $227,055 $80,220
12. CAPITAL STOCKS AND PAID-IN CAPITAL: Changes in capital stocks and paid-in capital during the period January 1, 1993 through December 31, 1995 were:
Cumulative Preferred Stocks Shares of Subsidiaries ------------------------------------ ---------------------------- Cumulative Not Subject Subject to Common Stock- Preferred Stocks Paid-in To Mandatory Mandatory Par Value $6.50(a) of Subsidiaries Common Stock Capital Redemption Redemption(b) ------------------ ---------------- ------------ ------- ------------ ------------- (Dollars in Thousands) January 1, 1993 193,534,992 10,761,675 $1,257,977 $1,628,394 $ 534,978 $233,509 Issues - 3,250,000 - - - 325,000 Retirements and Other - (6,323,907) - (4,218) (266,738) (57,972) ----------- ---------- ---------- ---------- --------- -------- December 31, 1993 193,534,992 7,687,768 1,257,977 1,624,176 268,240 500,537 Issues 700,000 900,000 4,550 17,706 - 90,000 Retirements and Other - (351,517) - (1,221) (35,000) (152) ----------- ---------- ---------- ---------- --------- -------- December 31, 1994 194,234,992 8,236,251 1,262,527 1,640,661 233,240 590,385 Issues 1,400,000 - 9,100 39,607 - - Retirements and Other - (1,526,500) - (21,744) (85,000) (67,650) ----------- ---------- ---------- ---------- --------- -------- December 31, 1995 195,634,992 6,709,751 $1,271,627 $1,658,524 $ 148,240 $522,735 ----------- ---------- ---------- ---------- --------- -------- ----------- ---------- ---------- ---------- --------- --------
(a) Includes 8,999,992 shares of treasury stock. (b) Including portion due within one year. 32 13. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Ended -------------------------------------------------- 1995 -------------------------------------------------- March 31 June 30 Sept. 30 Dec. 31 ---------- --------- ---------- --------- In Thousands - Except Per Share Amounts) - --------------------- Operating Revenues $1,416,169 $1,305,342 $1,523,390 $1,425,429 Operating Income 257,556 211,284 262,548 233,159 Net Income 147,850 96,478 154,156 131,419 Earnings per Share 0.80 0.52 0.83 0.70
Quarterly Periods Ended -------------------------------------------------- 1994 -------------------------------------------------- March 31 June 30 Sept. 30 Dec. 31 ---------- --------- ---------- --------- (In Thousands - Except Per Share Amounts) - ---------------------- Operating Revenues $1,488,185 $1,348,563 $1,385,278 $1,282,644 Operating Income 257,517 219,496 247,015 208,465 Net Income 152,954 103,793 139,826 103,439 Earnings per Share 0.83 0.56 0.76 0.56
Fourth quarter 1994 net income includes favorable federal income tax accrual adjustments of $16.1 million related to the resolution of various issues with the IRS. 33 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
December 31, 1995 --------------------------------------------------------------- Call Price per Shares Shares Amount(in Share (a) Authorized(b) Outstanding thousands) - -------------------------------------------------------------------------------------------------------------- Not Subject to Mandatory Redemption: 4.08% - 4.56% $102-$110 932,403 932,403 $ 93,240 7.08% - 7.40% $101.85-$102.11 550,000 550,000 55,000 --------- Total Not Subject to Mandatory Redemption $148,240 -------- -------- Subject to Mandatory Redemption (c): 4.50% $102 19,625 2,348 $ 235 5.90% - 5.92% (d) 1,950,000 1,950,000 195,000 6.02% - 6-7/8% (e) 1,950,000 1,950,000 195,000 7% - 7-7/8% $107.80-$107.88(f) 1,250,000 1,250,000 125,000 9.50% (g) 750,000 75,000 7,500 -------- Total Subject to Mandatory Redemption (h) 522,735 Less Portion Due Within One Year 7,650 -------- Long-term Portion $515,085 -------- -------- - --------------------------------------------------------------------------------------------------------------
December 31, 1994 -------------------------------------------------------------- Call Price per Shares Shares Amount(in Share (a) Authorized Outstanding thousands) - -------------------------------------------------------------------------------------------------------------- Not Subject to Mandatory Redemption: 4.08% - 4.56% $102-$110 932,403 932,403 $ 93,240 7.08% - 7.76% $101.85-$102.26 1,250,000 1,250,000 125,000 8.04% $102.58 150,000 150,000 15,000 -------- Total Not Subject to Mandatory Redemption $233,240 -------- -------- Subject to Mandatory Redemption (c): 4.50% $102 19,625 3,848 $385 5.90% - 5.92% (d) 1,950,000 1,950,000 195,000 6.02% - 6-7/8% (e) 1,950,000 1,950,000 195,000 7% - 7-7/8% $107.80-$107.88(f) 1,250,000 1,250,000 125,000 9.50% (g) 750,000 750,000 75,000 -------- Total Subject to Mandatory Redemption (h) 590,385 Less Portion Due Within One Year 85 -------- Long-term Portion $590,300 -------- --------
NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES (a) At the option of the subsidiary the shares may be redeemed at the call price (December 31, 1995 price is shown) plus accrued dividends. The involuntary liquidation preference is $100 per share for all outstanding shares. (b) As of December 31, 1995 the subsidiaries had 4,255,000, 22,200,000 and 5,547,652 shares of $100, $25 and no par value preferred stock, respectively, that were authorized but unissued. (c) With sinking fund. Shares outstanding and related amounts are stated net of applicable retirements through sinking funds (generally at par) and reacquisitions of shares in anticipation of future requirements. (d) Redemption is prohibited prior to 2003; after that the call price is $100 per share. (e) Redemption is prohibited prior to 2000; after that the call price is $100 per share. (f) Redemption is restricted prior to 1997. (g) On February 1, 1996 the outstanding balance of 75,000 shares was redeemed at $100 per share. (h) The sinking fund provisions of the series subject to mandatory redemption aggregate $7,650,000, $84,800, $5,000,000, $5,000,000 and $16,000,000 in 1996, 1997, 1998, 1999 and 2000, respectively. 34 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
Weighted Average Maturity Interest Rate Interest Rates at December 31, December 31, - -------- ----------------- ------------------------------ --------------------- December 31, 1995 1995 1994 1995 1994 ----------------- ---- ---- ---- ---- (in thousands) -------------- FIRST MORTGAGE BONDS 1995-1999 7.05% 5%-9.15% 5%-9.15% $ 496,866 $ 526,866 2001-2005 7.28% 6%-9.31% 6%-9.31% 1,530,020 1,450,020 2019-2025 8.26% 7.10%-9-7/8% 7.10%-9-7/8% 1,473,127 1,540,661 INSTALLMENT PURCHASE CONTRACTS(a) 1995-2002 5.65% 5%-7-1/4% 6%-7-1/4% 209,500 174,500 2007-2025 6.45% 5.45%-7-7/8% 5.45%-9-3/8% 756,745 811,745 NOTES PAYABLE(b) 1995-2008 7.87% 5.29%-10.78% 5.29%-10.78% 221,000 313,000 DEBENTURES 1996 - 1999(c) 6.40% 5-1/8%-7-7/8% 5-1/8%-7-7/8% 30,759 30,759 2025 8.35% 8.16%-8.72% - 200,000 - OTHER LONG-TERM DEBT(d) 172,403 163,896 Unamortized Discount (net) (33,144) (31,128) ---------- ---------- Total Long-term Debt Outstanding (e) 5,057,276 4,980,319 Less Portion Due Within One Year 136,947 293,671 ---------- ---------- Long-term Portion $4,920,329 $4,686,648 ---------- ---------- ---------- ----------
NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES (a) For certain series of installment purchase contracts interest rates are subject to periodic adjustment. Certain series will be purchased on the demand of the owners at periodic interest-adjustment dates. Letters of credit from banks and standby bond purchase agreements support certain series. (b) Notes payable represent outstanding promissory notes issued under term loan 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. (c) All sinking fund debentures will be reacquired by March 1, 1996. (d) Other long-term debt consist primarily of a liability along with accrued interest for disposal of spent nuclear fuel (see Note 4 of the Notes to Consolidated Financial Statements). (e) Long-term debt outstanding at December 31, 1995 is payable as follows: Principal Amount (in thousands) 1996 $ 136,947 1997 86,933 1998 269,266 1999 185,673 2000 168,648 Later Years 4,242,953 ---------- Total $5,090,420 ---------- ----------
35 Management's Responsibility The management of American Electric Power Company, Inc. is responsible for the integrity and objectivity of the information and representations in this annual report, including the consolidated financial statements. These statements have been prepared in conformity with generally accepted accounting principles, using informed estimates where appropriate, to reflect the Company's financial condition and results of operations. The information in other sections of the annual report is consistent with these statements. The Company's Board of Directors has oversight responsibilities for determining that management has fulfilled its obligation in the preparation of the financial statements and in the ongoing examination of the Company's established internal control structure over financial reporting. The Audit Committee, which consists solely of outside directors and which reports directly to the Board of Directors, meets regularly with management, Deloitte & Touche LLP - Certified Public Accountants and the Company's internal audit staff to discuss accounting, auditing and reporting matters. To ensure auditor independence, both Deloitte & Touche LLP and the internal audit staff have free access to the Audit Committee. The financial statements have been audited by Deloitte & Touche LLP, whose report appears on the next page. The auditors provide an objective, independent review as to management s discharge of its responsibilities insofar as they relate to the fairness of the Company's reported financial condition and results of operations. Their audit includes procedures believed by them to provide reasonable assurance that the financial statements are free of material misstatement and includes a review of the Company's internal control structure over financial reporting. INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of American Electric Power Company, Inc.: We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and its subsidiaries as of December 31, 1995 and 1994, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1995. 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 generally accepted auditing standards. 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 its subsidiaries as of December 31, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 27, 1996 AMERICAN ELECTRIC POWER COMPANY, INC. PROXY SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS FOR THE ANNUAL MEETING TO BE HELD APRIL 24, 1996 P R O X Y _______________________________________________________________________________ _______________________________________________________________________________ The undersigned appoints E. Linn Draper, Jr., Peter J. DeMaria and Gerald P. Maloney, and each of them, acting by a majority if more than one be present, attorneys and proxies of 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, 1996, and at any adjournments 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. TRUSTEE'S AUTHORIZATION. The undersigned authorizes Fidelity Management Trust Company and Key Trust Company of Ohio, N.A. to vote all shares of Common Stock of the Company credited to the undersigned's account under the American Electric Power System Employees Savings and Employee Stock Ownership plans, respectively, at the annual meeting in accordance with the instructions on the reverse side. Election of Directors. Nominees: P.J. DeMaria, E.L. Draper, Jr., R.M. Duncan, R.W. Fri, A.G. Hansen, L.A. Hudson, Jr., G.P. Maloney, A.E. Peyton, D.G. Smith, L.G. Stuntz, M. Tanenbaum, A.H. Zwinger. 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. THE PROXIES CANNOT VOTE YOUR SHARES UNLESS YOU SIGN AND RETURN THIS CARD. ________________________________________________________________________________ ________________________________________________________________________________ Comments: ________________________________________________________________________________ ________________________________________________________________________________ ________________________________________________________________________________ (If you have written in the above space, please mark the "Special Attention" box on the other side of this card.) /\ FOLD AND DETACH HERE /\ THE 89TH ANNUAL MEETING OF SHAREHOLDERS WILL BE HELD AT 9:30 A.M. WEDNESDAY, APRIL 24, 1996, IN THE FRANKLIN ROOM OF THE HYATT REGENCY COLUMBUS, 350 N. HIGH ST., COLUMBUS, OHIO. [MAP] [MAP] [AEP LOGO] PARKING AVAILABLE AT SHAREHOLDER'S EXPENSE AT OHIO CENTER AND COLUMBUS CONVENTION CENTER (SEE SHADED AREAS). /X/ Please mark your 0116 votes as in this example. The proxies are directed to vote as specified below and in their discretion on all other matters coming before the meeting. If no direction is made, the proxies will vote FOR all nominees listed on the reverse side and FOR Proposal 2. - -------------------------------------------------------------------------------- The Board of Directors recommends a vote FOR all nominees for election as directors and FOR Proposal 2. - -------------------------------------------------------------------------------- FOR WITHHELD FOR AGAINST ABSTAIN 1. Election of / / / / 2. Approval / / / / / / Directors of (See Reverse). Auditors. For, except vote withheld from the following nominee(s): ________________________________________________________ - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SPECIAL ATTENTION Mark here if you have written a comment on reverse. / / ANNUAL REPORT Mark here to discontinue annual report mailing for this / / account (for multiple-account holders only). ANNUAL MEETING Mark here if you plan to attend the annual meeting. / / - -------------------------------------------------------------------------------- Please sign exactly as name appears hereon. Joint owners should each sign. When signing as attorney, executor, administrator, trustee or guardian, please give full title as such. ____________________________________________________,1996 ____________________________________________________,1996 SIGNATURE(S) DATE /\ FOLD AND DETACH HERE /\ ANNUAL MEETING [AEP LOGO] OF SHAREHOLDERS Wednesday, April 24, 1996 - 9:30 a.m. ADMISSION TICKET Franklin Room - ------------------------------------- Hyatt Regency Columbus 350 North High Street Columbus, Ohio ---------------------------------------- AGENDA - Introduction and Welcome - Election of Directors - Ratification of Auditors - Chairman's Report - Comments and Questions from Shareholders - -------------------------------------------------------------------------------- IF YOU PLAN TO ATTEND THE 1996 ANNUAL MEETING OF SHAREHOLDERS, PLEASE MARK THE "ANNUAL MEETING" BOX ON THE PROXY CARD ABOVE. PRESENT THIS TICKET FOR ADMITTANCE OF SHAREHOLDER(S) NAMED ABOVE AND A GUEST. SEE REVERSE FOR MAP OF AREA. -----END PRIVACY-ENHANCED MESSAGE-----