<PAGE>
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/ No fee required.
/ / Fee computed on table below per Exchange Act Rules 14a-6(i)(1)
and 0-11.
(1) Title of each class of securities to which transaction applies:
-----------------------------------------------------------------------
(2) Aggregate number of securities to which transaction applies:
-----------------------------------------------------------------------
(3) Per unit price or other underlying value of transaction computed
pursuant to Exchange Act Rule 0-11 (set forth the amount on which the
filing fee is calculated and state how it was determined):
-----------------------------------------------------------------------
(4) Proposed maximum aggregate value of transaction:
-----------------------------------------------------------------------
(5) Total fee paid:
-----------------------------------------------------------------------
/ / Fee paid previously with preliminary materials.
/ / Check box if any part of the fee is offset as provided by Exchange Act Rule
0-11(a)(2) and identify the filing for which the offsetting fee was paid
previously. Identify the previous filing by registration statement number,
or the Form or Schedule and the date of its filing.
(1) Amount Previously Paid:
-----------------------------------------------------------------------
(2) Form, Schedule or Registration Statement No.:
-----------------------------------------------------------------------
(3) Filing Party:
-----------------------------------------------------------------------
(4) Date Filed:
-----------------------------------------------------------------------
<PAGE>
NOTICE OF 1999 ANNUAL MEETING - PROXY STATEMENT
AMERICAN ELECTRIC POWER
COMPANY, INC.
1 Riverside Plaza
Columbus, OH 43215
[LOGO]
March 11, 1999
Dear Shareholder:
This year's annual meeting of shareholders will be held in the
Grand Ballroom of the Embassy Suites Hotel and Conference
Center, 300 Court Street, Charleston, West Virginia, on
Wednesday, April 28, 1999 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 AEP's affairs. Directors and officers will be
available to talk individually with shareholders before and
after the meeting.
AEP's audited financial statements and management's discussion
and analysis of results of operations and financial condition
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. AEP's summary annual
report contains my letter to shareholders, a review of
operations, the summary management discussion and analysis of
financial condition and results of operations, and independent
auditors' report.
E. LINN DRAPER, JR.
Chairman of the Board,
President and
Chief Executive Officer
YOUR VOTE IS VERY IMPORTANT. SHAREHOLDERS OF RECORD CAN VOTE
IN ANY ONE OF THE FOLLOWING THREE WAYS:
- BY MAIL -- FILL IN, SIGN AND DATE YOUR ENCLOSED PROXY
CARD AND RETURN IT PROMPTLY IN THE ENCLOSED POSTAGE-PAID
ENVELOPE.
- BY TELEPHONE -- CALL THE TOLL-FREE TELEPHONE NUMBER ON
YOUR PROXY CARD TO VOTE BY PHONE.
- VIA INTERNET -- VISIT THE WEB SITE ON YOUR PROXY CARD TO
VOTE VIA THE INTERNET.
IF YOUR SHARES ARE HELD IN THE NAME OF A BANK, BROKER OR OTHER
HOLDER OF RECORD, YOU WILL RECEIVE INSTRUCTIONS FROM THE
HOLDER OF RECORD THAT YOU MUST FOLLOW IN ORDER FOR YOU TO VOTE
YOUR SHARES.
If you plan to attend the meeting and are a shareholder of
record, please mark the "Annual Meeting" box on your proxy
card or follow the prompts when you vote if you are voting by
telephone or Internet. 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 on March 9 which will enable you to gain
admittance to the meeting.
Sincerely,
[SIGNATURE]
<PAGE>
NOTICE OF 1999 ANNUAL MEETING
March 11, 1999
Columbus, Ohio
THE ANNUAL MEETING of shareholders of AMERICAN ELECTRIC POWER COMPANY, INC.,
a New York corporation, will be held in the Grand Ballroom of the Embassy Suites
Hotel and Conference Center, 300 Court Street, Charleston, West Virginia, on
Wednesday, April 28, 1999 at 9:30 o'clock in the morning, for the following
purposes:
1. To elect 10 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 1999; 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 9, 1999 are
entitled to notice of and to vote at the meeting or any adjournment thereof.
Susan Tomasky
SECRETARY
<PAGE>
PROXY STATEMENT
March 11, 1999
PROXY AND VOTING INFORMATION
THIS PROXY STATEMENT and the accompanying proxy card are to be mailed to
shareholders, commencing on or about March 15, 1999, 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 28, 1999 in Charleston, West Virginia.
WHO CAN VOTE. Only the holders of shares of Common Stock at the close of
business on March 9, 1999 are entitled to vote at the meeting. Each such holder
has one vote for each share held on all matters to come before the meeting. On
that date, there were 192,082,994 shares of AEP Common Stock, $6.50 par value,
outstanding.
HOW YOU CAN VOTE. Shareholders of record can give proxies by (i) mailing
their signed proxy cards, (ii) calling a toll-free telephone number or (iii)
using the Internet. The telephone and Internet voting procedures are designed to
authenticate shareholders' identities, to allow shareholders to give their
voting instructions and to confirm that shareholders' instructions have been
properly recorded. Instructions for shareholders of record who wish to use the
telephone or Internet voting procedures are set forth on the enclosed proxy
card.
When proxies are returned, the shares represented thereby will be voted by
the persons named on the proxy card or by their substitutes in accordance with
shareholders' directions. The proxies of shareholders who are participants in
the Dividend Reinvestment and Stock Purchase Plan include both the shares
registered in their names and the whole shares held in their Plan accounts on
March 9, 1999. 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.
REVOCATION OF PROXIES. 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.
HOW VOTES ARE COUNTED. 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
beneficial owner instructions.
YOUR VOTE IS CONFIDENTIAL. It is AEP's policy that shareholders be provided
privacy in voting. All proxies, voting instructions and ballots, which identify
shareholders, are held confidential, except as may be necessary to meet any
applicable legal requirements. We direct proxies to an independent third-party
tabulator, who receives, inspects, and tabulates them. Voted proxies and ballots
are not seen by nor reported to AEP except (i) in aggregate number or to
determine if (rather than how) a shareholder has voted, (ii) in cases where
shareholders write comments on their proxy cards, or (iii) in a contested proxy
solicitation.
MULTIPLE COPIES OF ANNUAL REPORT TO SHAREHOLDERS. 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 or follow the prompts when you vote if you are a shareholder of
record voting by telephone or Internet. Eliminating these duplicate mailings
will not affect receipt of future proxy statements and proxy cards.
<PAGE>
PENDING CSW MERGER
ON DECEMBER 21, 1997, AEP and Central and South West Corporation ("CSW") entered
into an Agreement and Plan of Merger pursuant to which CSW will be merged with
and into a wholly-owned merger subsidiary of AEP. The Boards of Directors of AEP
and CSW have approved the merger. At AEP's May 1998 annual meeting, the
shareholders approved the issuance of AEP Common Stock to effect the merger and
an increase in the number of AEP's authorized shares. CSW stockholders approved
the merger at their May 1998 annual meeting.
Assuming the receipt of all required regulatory approvals, we anticipate
completion of the merger by the end of 1999.
Pursuant to the merger agreement, at the effective time of the merger, AEP
has agreed to increase the size of its Board of Directors to 15 members as
follows:
- The ten then current board members of AEP.
- Mr. E. R. Brooks, chairman and chief executive officer of CSW.
- Four additional outside directors of CSW to be nominated by AEP. The four
additional outside directors have not been selected to date.
1. ELECTION OF DIRECTORS
TEN 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. AEP's By-Laws provide that the number of directors of AEP shall be
such number, not less than 9 nor more than 17, as shall be determined from time
to time by resolution of AEP's Board of Directors.
On January 27, 1999, the Board of Directors adopted a resolution reducing
the number of directors from 11 to 10, effective on the date of the annual
meeting. Mr. Angus E. Peyton, a director, will be retiring from the Board and
not standing for reelection.
The 10 nominees named on pages 3-6 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. All of the Board's nominees were
elected by the shareholders at the 1998 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 or the number of directors may be reduced accordingly.
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 10 -- 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 AEP's Common Stock and stock-based units
beneficially owned by each of them appears on page 18.
2
<PAGE>
NOMINEES FOR DIRECTOR
<TABLE>
<C> <S> <C>
JOHN P. DESBARRES Received an associate degree in
[PHOTO] INVESTOR/CONSULTANT, electrical engineering from Worcester
RANCHO PALOS VERDES, CALIFORNIA Junior College in 1960 and completed the
Age 59 Harvard Business School Program for
Director since 1997 Management Development in 1975 and the
Massachusetts Institute of Technology
Sloan School Senior Executive Program in
1984. Joined Sun Company (petroleum and
natural gas) in 1963, holding various
positions until 1979, when he was elected
president of Sun Pipe Line Company
(1979-1988) (crude oil products).
Chairman, president and chief executive
officer of Sante Fe Pacific Pipelines,
Inc. (1988- 1991) (petroleum products
pipeline). President and chief executive
officer (1991-1995) and chairman
(1992-1995) of Transco Energy Company
(natural gas). A director of Texas
Eastern Products Pipeline Company, which
is the general partner of TEPPCO
Partners, L.P.
- ------------------------------------------------------------------------------------------
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 AEP AND in 1964 and 1965, respectively, and Ph.D.
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 57 the board, president and chief executive
Director since 1992 officer of Gulf States (1987-1992).
Elected president of AEP and president
and chief operating officer of AEP
Service Corporation in March 1992 and
chairman of the board and chief executive
officer of AEP and all of its major
subsidiaries in April 1993. A director of
BCP Management, Inc., which is the
general partner of Borden Chemicals and
Plastics L.P., and CellNet Data Systems,
Inc.
- ------------------------------------------------------------------------------------------
</TABLE>
3
<PAGE>
NOMINEES FOR DIRECTOR -- CONTINUED
<TABLE>
<C> <S> <C>
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 71 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 In-
vesting Foundation III, Nationwide
Separate Account Trust and Nationwide
Asset Allocation Trust.
- ------------------------------------------------------------------------------------------
ROBERT W. FRI Holds a B.A. from Rice University and an
[PHOTO] DIRECTOR, NATIONAL M.B.A. from Harvard Business School. As-
MUSEUM OF NATURAL HISTORY sociated with McKinsey & Company, Inc.,
(SMITHSONIAN INSTITUTION), management consulting firm, from 1963 to
WASHINGTON, D.C. 1971 and again from 1973 to 1975, being
Age 63 elected a principal in the firm in 1968.
Director since 1995 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 and became senior fellow
emeritus in 1996. Assumed his present
position with the National Museum of
Natural History in 1996. A director of
Hagler Bailly, Inc.
- ------------------------------------------------------------------------------------------
</TABLE>
4
<PAGE>
<TABLE>
<C> <S> <C>
LESTER A. HUDSON, JR. Received a B.A. from Furman University in
[PHOTO] CHAIRMAN, H&E ASSOCIATES, 1961, an M.B.A. from the University of
GREENVILLE, SOUTH CAROLINA South Carolina in 1965 and Ph.D.
Age 59 (industrial management) from Clemson
Director since 1987 University in 1997. Joined Dan River Inc.
(textile fabric manufacturer) in 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 (1993-1995).
Chairman, H&E Associates (investment
firm) in 1995. A director of American
National Bankshares Inc. and Greenville
Hospital System Foundation. Professor,
Department of Management, Clemson
University.
- ------------------------------------------------------------------------------------------
LEONARD J. KUJAWA Received his B.B.A. in 1954 and M.B.A. in
[PHOTO] INTERNATIONAL 1955 from the University of Michigan.
ENERGY CONSULTANT, Joined Arthur Andersen LLP (accounting
ATLANTA, GEORGIA and consulting firm) in 1957 and became a
Age 66 partner in 1968, specializing in the
Director since 1997 electric and telecommunications
industries. Worldwide Director Energy and
Telecommunications (1985- 1995). Retired
in 1995. International energy consultant
to his former firm and other global
companies. A director of
Schweitzer-Mauduit International, 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 Steel before being named president and
ROANOKE ELECTRIC STEEL treasurer in 1985, chief executive
CORPORATION, officer in 1986 and chairman of the board
ROANOKE, VIRGINIA in 1989.
Age 63
Director since 1994
- ------------------------------------------------------------------------------------------
</TABLE>
5
<PAGE>
NOMINEES FOR DIRECTOR -- CONTINUED
<TABLE>
<C> <S> <C>
LINDA GILLESPIE STUNTZ Holds an A.B. from Wittenberg University
[PHOTO] PARTNER, STUNTZ, DAVIS & (1976) and J.D. from Harvard Law School
STAFFIER, P.C., ATTORNEYS, (1979). Private practice of law
WASHINGTON, D.C. (1979-1981). U.S. House of
Age 44 Representatives, Committee on Energy and
Director since 1993 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. De-
partment 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.
- ------------------------------------------------------------------------------------------
KATHRYN D. SULLIVAN Received her B.S. from the University of
[LOGO] PRESIDENT AND CHIEF California and Ph.D. from Dalhousie Uni-
EXECUTIVE OFFICER, versity. NASA space shuttle astronaut
COSI COLUMBUS, (1978-1993). Chief Scientist at the
COLUMBUS, OHIO National Oceanic and Atmospheric
Age 47 Administration (1993-1996). Became
Director since 1997 president and chief executive officer of
COSI Columbus (science museum) in 1996.
U.S. Naval Reserve Officer.
- ------------------------------------------------------------------------------------------
MORRIS TANENBAUM Graduated from The Johns Hopkins Univer-
[PHOTO] DIRECTOR AND TRUSTEE, sity in 1949 with a B.A. in chemistry and
SHORT HILLS, NEW JERSEY received a Ph.D. in physical chemistry in
Age 70 1952 from Princeton University. Joined
Director since 1989 Bell Telephone 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 Massachusetts Institute of Technology,
associate trustee of Battelle Memorial
Institute, trustee emeritus of The Johns
Hopkins University, honorary trustee of
The Brookings Institution and a member of
the National Academy of Engineering.
- ------------------------------------------------------------------------------------------
</TABLE>
Dr. Draper is a director 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 AEP with one or more classes of
publicly held preferred stock or debt securities) and other subsidiaries of AEP.
Dr. Draper is also a director of AEP Generating Company, a subsidiary of the
Company.
6
<PAGE>
FUNCTIONS OF THE BOARD OF DIRECTORS AND COMMITTEES
UNDER NEW YORK LAW, AEP is managed under the direction of the Board of
Directors. The Board establishes broad corporate policies and authorizes various
types of transactions, but it is not involved in day-to-day operational details.
During 1998, the Board held eight regular and two special meetings. The Board
has six standing committees, the functions of which are described in the
following paragraphs.
The AUDIT COMMITTEE oversees, and reports to the Board concerning, the
general policies and practices of AEP 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 AEP's
independent accountants and reviews possible conflict of interest situations
involving directors.
Audit Committee members: Messrs. DesBarres, Duncan, Fri and Peyton and Drs.
Hudson and Sullivan.
Audit Committee meetings in 1998: four.
The COMMITTEE ON DIRECTORS is responsible for:
1. Recommending the size of the Board within the boundaries imposed by the By-
Laws.
2. Recommending selection criteria for nominees for election or appointment to
the Board.
3. Conducting independent searches for qualified nominees and screening the
qualifications of candidates recommended by others.
4. Recommending to the Board 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.
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.
Committee on Directors members: Messrs. Duncan, Fri and Kujawa, Dr. Hudson
and Ms. Stuntz.
Committee on Directors meetings in 1998: one.
The CORPORATE PUBLIC POLICY COMMITTEE is responsible for examining AEP's
policies on major public issues affecting the AEP System, including
environmental, work force diversity, industry change and other matters, as well
as established System policies which affect the relationship of AEP 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 AEP management on any such
policy matters presented to the Committee for consideration and study.
Corporate Public Policy Committee members: Messrs. DesBarres, Duncan, Fri,
Kujawa, Peyton and Smith, Drs. Hudson, Sullivan and Tanenbaum and Ms. Stuntz.
Corporate Public Policy Committee meetings in 1998: three.
The EXECUTIVE COMMITTEE 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.
Executive Committee members: Drs. Draper and Tanenbaum and Mr. Peyton.
Executive Committee meetings in 1998: none.
The FINANCE COMMITTEE monitors and reports to the Board with respect to the
capital requirements and financing plans and programs of AEP and its
subsidiaries including, among other things, reviewing and making such
recommendations as it considers appropriate concerning the short and long-term
financing plans and programs of AEP and its subsidiaries and the implementation
of the same.
7
<PAGE>
Finance Committee members: Messrs. Kujawa, Peyton and Smith, Ms. Stuntz and
Dr. Tanenbaum.
Finance Committee meetings in 1998: six.
The HUMAN RESOURCES COMMITTEE is responsible for:
1. Reviewing executive compensation policies and plans and, as appropriate,
recommending changes to the Board.
2. Reviewing salaries and other compensation and benefits paid by AEP and its
subsidiaries to Board members who are AEP officers or employees of any of
its subsidiaries, and for recommending to the Board for approval the amount
of salary and other compensation and benefits to be paid or accrued by AEP
and/or any of its subsidiaries during the ensuing year to each such person.
3. Reviewing and approving compensation and benefits for the AEP Service
Corporation officers who hold the position of Senior Vice President or
higher office.
4. Evaluating AEP's hiring, development, promotional and succession planning
practices for those management positions described in (2) and (3) above and
recommending changes as appropriate.
Human Resources Committee members: Messrs. DesBarres and Smith and Drs.
Hudson and Tanenbaum.
Human Resources Committee meetings in 1998: four.
During 1998, 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.
DIRECTORS COMPENSATION AND STOCK OWNERSHIP GUIDELINES
ANNUAL RETAINERS AND MEETING FEES. Directors who are officers of AEP 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 AEP's Board of Directors. 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).
DEFERRED COMPENSATION AND STOCK PLAN. The Deferred Compensation and Stock
Plan for Non-Employee Directors permits non-employee directors to choose to
receive up to 100 percent of their annual Board retainer in shares of AEP Common
Stock and/or units that are equivalent in value to shares of Common Stock
("Stock Units"), deferring receipt by the non-employee director until
termination of service or for a period that results in payment commencing not
later than five years thereafter. AEP Common Stock is distributed and/or Stock
Units are credited to directors, as the case may be, when the retainer is
payable, and are based on the closing price of the Common Stock on the payment
date. Amounts equivalent to cash dividends on the Stock Units accrue as
additional Stock Units. Payment of Stock Units to a director from deferrals of
the retainer and dividend credits is made in cash or AEP Common Stock, or a
combination of both, as elected by the director.
STOCK UNIT ACCUMULATION PLAN. The Stock Unit Accumulation Plan for
Non-Employee Directors awards 300 Stock Units to each non-employee director as
of the first day of the month in which the non-employee director becomes a
member of the Board, and annually thereafter, up to a maximum of 3,000 Stock
Units for each non-employee director. Amounts equivalent to cash dividends on
the Stock Units accrue as additional Stock Units. Stock Units credited to a
non-employee director's account as a result of the annual awards and dividend
credits are forfeitable on a pro rata basis for each full month that service as
a director is less than 60 months. Stock Units are paid to the director in cash
upon termination of service unless the director has elected to defer payment for
a period that results in payment commencing not later than five years
thereafter.
INSURANCE. AEP maintains a group 24-hour accident insurance policy to
provide a $1,000,000 accidental death benefit for each
8
<PAGE>
director (three-year premium was $15,750). The current policy will expire on
September 1, 2000, and AEP expects to renew the coverage. In addition, AEP pays
each director (excluding officers of AEP 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 $350
annually).
STOCK OWNERSHIP GUIDELINES. AEP's Board of Directors considers stock
ownership in AEP by management to be of great importance. Such ownership
enhances management's commitment to the future of AEP and further aligns
management's interests with those of AEP's shareholders. In keeping with this
philosophy, the Board has adopted minimum stock ownership guidelines for
non-employee directors. The target for each non-employee director is 2,000
shares of AEP Common Stock and/or Stock Units, with such ownership to be
acquired by December 31, 2000 for directors in office on January 1, 1997, and by
the end of the fifth year of service for directors joining the Board after this
time. For further information as to the guidelines for AEP's executive officers,
see the BOARD HUMAN RESOURCES COMMITTEE REPORT ON EXECUTIVE COMPENSATION below
under the caption STOCK OWNERSHIP GUIDELINES.
INSURANCE
THE DIRECTORS and officers of AEP 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, CNA, Energy Insurance Mutual, The
Federal Insurance Company and Great American Insurance Company, effective
January 1, 1999 through December 31, 1999, and pays up to an aggregate amount of
$195,000,000 on any one claim and in any one policy year. The total annual
premium for the five policies is $1,318,684.
Fiduciary liability insurance provides coverage for AEP 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 The Federal Insurance Company, Zurich Insurance Company
and Executive Risk Indemnity, Inc., was renewed, effective July 1, 1997 through
June 30, 2000, for a premium of $402,658. It provides $100,000,000 of aggregate
coverage with a $500,000 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 AEP for the year 1999, 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 AEP's affairs. It and predecessor firms have been AEP's
auditors since 1911.
Fees billed by Deloitte & Touche LLP for auditing and other professional
services rendered to AEP and its subsidiaries during 1998 were $6,306,000.
Representatives of Deloitte & Touche LLP will be present at the meeting and
will have an opportunity to make a statement if they desire to do so. They also
will be available to answer appropriate questions.
VOTE REQUIRED. Approval of this proposal requires the affirmative vote of
holders of a majority of the shares present in person or by proxy at the
meeting.
YOUR BOARD OF DIRECTORS RECOMMENDS A VOTE FOR APPROVAL OF DELOITTE & TOUCHE
LLP AS INDEPENDENT AUDITORS FOR 1999.
OTHER BUSINESS
THE BOARD OF DIRECTORS does not intend to present to the meeting any business
other than the election of directors and the approval of auditors.
If any other business not described herein should properly come before the
meeting for action by the shareholders, the persons named as proxies on the
enclosed card or their substitutes will vote the shares represented by them in
accordance with their best judgment. At the time this proxy statement was
printed, the Board of Directors was not aware of any other matters that might be
presented.
9
<PAGE>
EXECUTIVE COMPENSATION
THE FOLLOWING TABLE shows for 1998, 1997 and 1996 the compensation earned by the
chief executive officer and the four other most highly compensated executive
officers (as defined by regulations of the Securities and Exchange Commission)
of AEP at December 31, 1998.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM
COMPENSATION
ANNUAL ------------------------
COMPENSATION
---------------- PAYOUTS ALL OTHER
SALARY BONUS ------------------------ COMPENSATION
NAME AND PRINCIPAL POSITION YEAR ($) ($)(1) LTIP PAYOUTS($)(1) ($)(2)
- ---------------------------------------- ---- ------- ------- ------------------------ -------------
<S> <C> <C> <C> <C> <C>
E. LINN DRAPER, JR. -- Chairman of the 1998 780,000 194,376 345,906 104,941
board, president and chief executive 1997 720,000 327,744 951,132 31,620
officer of the Company and the Service 1996 720,000 281,664 675,903 31,990
Corporation; chairman and chief
executive officer of other subsidiaries
WILLIAM J. LHOTA -- Executive vice 1998 380,000 82,859 134,266 56,493
president and director of the Service 1997 355,000 141,396 364,436 20,570
Corporation; president, chief operating 1996 320,000 125,184 263,114 19,690
officer and director of other
subsidiaries
DONALD M. CLEMENTS, JR. -- Executive 1998 350,000 76,317 60,047 39,040
vice president -- corporate development
and director of the Service
Corporation; president and director of
AEP Resources, Inc.(3)
JAMES J. MARKOWSKY -- Executive vice 1998 350,000 76,317 127,115 51,859
president -- power generation and 1997 325,000 129,447 338,382 18,020
director of the Service Corporation; 1996 303,000 118,534 254,535 19,480
vice president and director of other
subsidiaries
JOSEPH H. VIPPERMAN -- Executive vice 1998 310,000 67,595 82,859 58,435
president -- corporate services and
director of the Service Corporation;
vice president and director of other
subsidiaries (3)
</TABLE>
- -------------
(1) Amounts in the BONUS column reflect awards under the Senior Officer Annual
Incentive Compensation Plan (and predecessor Management Incentive
Compensation Plan). Payments are made in March of the succeeding fiscal year
for performance in the year indicated. Amounts for 1998 are estimates but
should not change significantly.
Amounts in the LONG-TERM COMPENSATION column reflect performance share unit
targets earned under the Performance Share Incentive Plan for three-year
performance periods.
See below under LONG-TERM INCENTIVE PLANS -- AWARDS IN 1998 and pages 15 and
16 for additional information.
10
<PAGE>
(2) Amounts in the ALL OTHER COMPENSATION column include (i) AEP's matching
contributions under the AEP Employees Savings Plan and the AEP Supplemental
Savings Plan, a non-qualified plan designed to supplement the AEP Savings
Plan, and (ii) subsidiary companies director fees. For 1998, the amounts
also include split-dollar insurance. Split-dollar insurance represents the
present value of the interest projected to accrue for the employee's benefit
on the current year's insurance premium paid by AEP. Cumulative net life
insurance premiums paid are recovered by AEP at the later of retirement or
15 years. Detail of the 1998 amounts in the ALL OTHER COMPENSATION column is
shown below.
<TABLE>
<CAPTION>
ITEM DR. DRAPER MR. LHOTA MR. CLEMENTS DR. MARKOWSKY MR. VIPPERMAN
- ---------------------------------------- ----------- ----------- ------------- --------------- ---------------
<S> <C> <C> <C> <C> <C>
Savings Plan Matching Contributions..... $ 3,200 $ 4,800 $ 3,469 $ 4,800 $ 4,800
Supplemental Savings Plan Matching
Contributions......................... 20,200 6,600 7,031 5,700 4,500
Split-Dollar Insurance.................. 71,621 35,173 28,340 31,439 43,135
Subsidiaries Directors Fees............. 9,920 9,920 200 9,920 6,000
----------- ----------- ------------- --------------- ---------------
Total ALL OTHER COMPENSATION............ $ 104,941 $ 56,493 $ 39,040 $ 51,859 $ 58,435
----------- ----------- ------------- --------------- ---------------
----------- ----------- ------------- --------------- ---------------
</TABLE>
(3) No 1996 or 1997 compensation information is reported for Messrs. Clements
and Vipperman because they were not executive officers in these years.
LONG-TERM INCENTIVE PLANS -- AWARDS IN 1998
Each of the awards set forth below establishes performance share unit
targets, 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 unit targets were established in the form of
shares of Common Stock are not included in the table.
The ability to earn performance share unit targets 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
unit targets 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 unit targets 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 unit targets. 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.
<TABLE>
<CAPTION>
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 (#) (#) (#)
- ------------------------ ------------- ------------ ---------- --------- ----------
<S> <C> <C> <C> <C> <C>
E. L. Draper, Jr. 7,730 1998-2000 1,932 7,730 15,460
W. J. Lhota 2,636 1998-2000 659 2,636 5,272
D. M. Clements, Jr. 2,428 1998-2000 607 2,428 4,856
J. J. Markowsky 2,428 1998-2000 607 2,428 4,856
J. H. Vipperman 2,150 1998-2000 537 2,150 4,300
</TABLE>
11
<PAGE>
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 AEP. 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
<TABLE>
<CAPTION>
YEARS OF ACCREDITED SERVICE
HIGHEST AVERAGE ----------------------------------------------------------------------------
ANNUAL EARNINGS 15 20 25 30 35 40
- ---------------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
$ 300,000 $ 69,525 $ 92,700 $ 115,875 $ 139,050 $ 162,225 $ 182,175
400,000 93,525 124,700 155,875 187,050 218,225 244,825
500,000 117,525 156,700 195,875 235,050 274,225 307,475
700,000 165,525 220,700 275,875 331,050 386,225 432,775
900,000 213,525 284,700 355,875 427,050 498,225 558,075
1,200,000 285,525 380,700 475,875 571,050 666,225 746,025
</TABLE>
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 55 and 62. If an employee
retires after age 62, there is no reduction in the retirement annuity.
AEP 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
Senior Officer Annual Incentive Compensation Plan (and predecessor 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, 1998, the number of full years of
service applicable for retirement benefit calculation purposes for such officers
were as follows: Dr. Draper, six years; Mr. Lhota, 34 years; Mr. Clements, four
years; Dr. Markowsky, 27 years; and Mr. Vipperman, 35 years.
Dr. Draper and Mr. Clements have agreements with AEP which provide them with
supplemental retirement annuities that credit Dr. Draper with 24 years of
service and Mr. Clements with 15 years of service in addition to their years of
service with AEP. Their supplemental retirement benefits are reduced by their
actual pension entitlement under the Retirement Plan and any pension entitlement
from the Gulf States Utilities Company Trusteed Retirement Plan, a plan
sponsored by their prior employer.
Ten AEP System employees (including Messrs. Lhota and Vipperman 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 are eligible for
certain supplemental retirement benefits. Such payments, if any, will be equal
to any reduction occurring because of such amendments. Assuming retirement in
1999 of the executive officers named in the Summary Compensation Table, none of
them would receive any supplemental benefits.
AEP 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
12
<PAGE>
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.
<TABLE>
<CAPTION>
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)
- ----------------------------------------- --------------- ---------------- --------------- ----------------
<S> <C> <C> <C> <C>
J. H. Vipperman.......................... $11,000 $90,750 $10,000 $67,500
</TABLE>
SEVERANCE PLAN
In connection with the proposed merger with Central and South West
Corporation, AEP's Board of Directors adopted a severance plan on February 24,
1999, effective March 1, 1999, that includes Dr. Markowsky and Messrs. Lhota,
Clements and Vipperman. The severance plan provides for payments and other
benefits if, within two years after the merger is completed, the officer's
employment is terminated by AEP without "cause" or by the officer because of a
detrimental change in responsibilities or a reduction in salary or benefits.
Under the severance plan, the officer will receive:
- A lump sum payment equal to three times the officer's annual base salary
plus target annual incentive under the Senior Officer Annual Incentive
Compensation Plan.
- Maintenance for a period of three additional years of all medical and
dental insurance benefits substantially similar to those benefits to which
the officer was entitled immediately prior to termination, reduced to the
extent comparable benefits are otherwise received.
- Outplacement services not to exceed a cost of $30,000 or use of an office
and secretarial services for up to one year.
AEP's obligation for the payments and benefits under the severance plan is
subject to the waiver by the officer of any other severance benefits that may be
provided by AEP. In addition, the officer agrees to refrain from the disclosure
of confidential information relating to AEP.
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 8.
The Human Resources Committee recognizes that the executive officers are
charged with managing a $19 billion, multi-state electric utility with
international investments during challenging times and with addressing many
difficult and complex issues.
AEP's executive compensation program is designed to maximize shareholder
value, to support the implementation of the Company's business strategy and to
improve both corporate and personal performance. The Committee's compensation
policies supporting this program are:
- Pay for performance, motivating both short- and long-term performance.
Compensation for short- and long-term performance focuses on meeting
specified corporate performance goals and the long-term interests of
shareholders, respectively.
- Require a significant amount of compensation for senior executives to be
"at risk", variable incentive compensation
13
<PAGE>
versus fixed or base pay -- with much of this risk similar to the risk
experienced by other AEP shareholders.
- Enhance the Company's ability to attract, retain, reward, motivate and
encourage the development of exceptionally knowledgeable, highly qualified
and experienced executives through compensation opportunities.
- Target compensation levels at rates that are reflective of current market
practices to maintain a stable, successful management team.
In carrying out its responsibilities, the Committee utilizes independent
compensation consultants to obtain information and recommendations relating to
changing industry compensation practices and programs.
The Committee also considers management's responses 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 and implement strategies effectively to position the Company for the
future. This includes the Company's development of unregulated business
activities, proposals and actions taken in connection with the industry's
transition to competition, establishment of a national energy trading
organization and the merger agreement with Central and South West Corporation.
Two specific significant 1998 initiatives were the acquisition of CitiPower, an
Australian electricity distribution and retail sales company, and the
acquisition of midstream natural gas assets in Louisiana and Texas. The success
of these efforts and their benefits to the Company cannot be precisely measured
in advance, but the Committee believes they are vital to the Company's long-term
success.
STOCK OWNERSHIP GUIDELINES. The Board of Directors, upon the Committee's
recommendation, underscored the importance of aligning executive and shareholder
interests by adopting in December 1994 stock ownership guidelines for senior
management participants in the Performance Share Incentive Plan. The Committee
and senior management believe that linking a significant portion of an
executive's current and potential future net worth to the Company's success, as
reflected in the stock price and dividends paid, gives the executive a stake
similar to that of the Company's owners and further encourages long-term
management for the benefit of those owners.
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 targets for the CEO and the other four
officers named in the Summary Compensation Table are 45,000 shares and 15,000
shares, respectively. Each officer is expected to achieve the ownership target
within a five year period. Common Stock equivalents earned through the Senior
Officer Annual Incentive Compensation Plan and Performance Share Incentive Plan,
described below, are included in determining compliance with the ownership
targets. As of January 1, 1999, Dr. Draper has met his ownership requirement and
all of the other officers named in the Summary Compensation Table have either
met, or are on target to meet, their respective targets within the specified
time period. See the table on page 18 for actual ownership amounts.
COMPONENTS OF EXECUTIVE COMPENSATION
BASE SALARY. When reviewing base salaries, the Committee considers pay
practices used by other electric utilities and 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 base salaries to the base 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 base salary levels are targeted to the second
highest 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 1998 for the CEO
14
<PAGE>
and next four most highly compensated executive officers of AEP named in the
Summary Compensation Table were within this second highest quartile. In
establishing base salary levels against that range, the Human Resources
Committee considers the competitiveness of AEP's entire compensation package.
Base salaries are adjusted, as appropriate, and reviewed 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 all outside directors of the Board. After full
discussion, these directors then act on the Committee's recommendation.
ANNUAL INCENTIVE. The primary purpose of annual incentive compensation is
to motivate senior managers, through short-term (one-year) incentives and
rewards, to maximize shareholder value by maximizing the Company's financial
performance.
The Senior Officer Annual Incentive Compensation Plan ("SOIP") provides a
variable, performance-based portion of the executive officers' total
compensation and this compensation is set forth in the BONUS column of the
Summary Compensation Table. SOIP participants are assigned an annual target
award expressed as a percentage of annual salary. For 1998, the target awards
for Dr. Draper and the other executive officers named in the compensation table
were 40% and 35%, respectively. Actual awards can vary from 0-150% of the target
award -- based on performance.
For 1998, SOIP awards were based on the following preestablished performance
criteria, each weighted at 25%:
- Total investor return, which reflects stock price and dividends paid,
measured relative to the performance of utilities in the S&P Electric
Utility Index.
- Return on stockholder equity, measured relative to the performance of
utilities in the S&P Electric Utility Index and on absolute performance.
- Average price of power sold to AEP's retail customers compared with other
utilities in the states which AEP serves.
- Safety.
For 1998, AEP performance merited an award of 62.3%. 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, SOIP participants may elect to defer their awards,
with the deferrals treated as if invested in Common Stock of the Company,
although no stock is actually purchased. Dividend equivalents are credited
during the deferral period.
LONG-TERM INCENTIVE. The primary purpose of longer-term, equity-based,
incentive compensation is to motivate senior managers to maximize shareholder
value by linking a portion of their compensation directly to shareholder return.
The Performance Share Incentive Plan ("PSIP") annually establishes
performance share unit targets which are earned based on AEP's subsequent
three-year total shareholder returns measured relative to the S&P peer
utilities. In 1998, the Committee established targets for Dr. Draper and the
other executive officers named in the Summary Compensation Table equivalent to
50% and 35%, respectively, of their then base salaries. The target number of
performance share units has been determined after an evaluation of long-term
incentive opportunities provided by the S&P peer utilities, again targeting the
second highest quartile of competitive practice. However, the awards which will
ultimately be paid to participants under the PSIP for a performance period are
not determinable in advance and can range from 0-200% of the target.
The PSIP ended a three-year performance period at year end 1998. AEP's total
shareholder return for 1996-1998 ranked fourteenth relative to the S&P peer
utilities and, as a result, 85% of the performance share unit targets originally
established (and dividend credits) were earned. The associated awards are listed
in the Summary Compensation Table.
Similar to the SOIP awards which are deferred, payments of earned awards
under the
15
<PAGE>
PSIP are also deferred in the form of restricted stock units (equivalent to
shares of AEP Common Stock). Such PSIP deferrals continue until termination of
employment or, if so elected by the recipient, with payments commencing not
later than 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 PSIP awards in
cash and/ or Common Stock. When awards are deferred, dividend equivalents are
credited as though reinvested in additional restricted stock units. The PSIP is
further described on page 11.
TAX POLICY
The Committee has considered the impact of Section 162(m) of the Internal
Revenue Code, which provides a limit on the deductibility of compensation in
excess of $1,000,000 paid in any year to the Company's chief executive officer
or any of its four other most highly compensated executive officers. It is the
Committee's policy, consistent with sound executive compensation principles and
the needs of the Company, to qualify compensation for deductibility where
practicable.
Award payments under the PSIP have been structured to be exempt from the
deduction limit because they are made pursuant to a shareholder-approved
performance-driven plan.
Award payments under the SOIP are not eligible for the performance-based
exemption and the deduction limit does apply to such awards. Since Dr. Draper
has deferred his 1998 SOIP award to dates past his retirement from the Company
(providing an exemption from the deduction limit), the Committee has not deemed
it necessary at this time to qualify compensation paid pursuant to the SOIP for
deductibility under Section 162(m). The Committee may decide to do so in the
future.
No named officer in the Summary Compensation Table had taxable compensation
for 1998 in excess of the deduction limit. The Committee intends to continue to
evaluate the impact of this Code restriction.
HUMAN RESOURCES
COMMITTEE MEMBERS
Morris Tanenbaum, Chairman
John P. DesBarres
Lester A. Hudson, Jr.
Donald G. Smith
16
<PAGE>
COMPARISON OF FIVE YEAR CUMULATIVE TOTAL RETURN*
AEP, S&P 500 INDEX & S&P ELECTRIC UTILITY INDEX**
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
AEP S&P 500 S&P ELECTRIC UTILITY
<S> <C> <C> <C>
1993 100 100 100
1994 95.4 101.32 86.98
1995 125.9 139.4 113.93
1996 135.32 171.4 113.89
1997 179.59 228.58 144.18
1998 172.23 294.3 167.88
</TABLE>
Assumes $100 Invested on January 1, 1994 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.
17
<PAGE>
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, 1999 for all directors as of the date of this
proxy statement, 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.
<TABLE>
<CAPTION>
STOCK
NAME SHARES UNITS(a) TOTAL
- ---------------------------------------------------------------------- ------------------ --------- ---------
<S> <C> <C> <C>
D. M. Clements, Jr.................................................... 1,134(b) 11,418 12,552
J. P. DesBarres....................................................... 5,000(c) 640 5,640
E. L. Draper, Jr...................................................... 7,934(b)(c) 77,612 85,546
R. M. Duncan.......................................................... 2,200 3,334 5,534
R. W. Fri............................................................. 1,000 1,290 2,290
L. A. Hudson, Jr...................................................... 1,853(d) 3,334 5,187
L. J. Kujawa.......................................................... 900 1,539 2,439
W. J. Lhota........................................................... 16,042(b)(c)(e) 14,902 30,944
J. J. Markowsky....................................................... 3,942(b)(d) 13,062 17,004
A. E. Peyton.......................................................... 4,960(f) 4,224 9,184
D. G. Smith........................................................... 2,000 1,632 3,632
L. G. Stuntz.......................................................... 1,500(c) 2,428 3,928
K. D. Sullivan........................................................ -- 865 865
M. Tanenbaum.......................................................... 1,509 3,291 4,800
J. H. Vipperman....................................................... 10,734(b)(c)(e) 4,718 15,452
All directors and executive officers as a group
(16 persons)......................................................... 145,939(e)(g) 144,289 290,228
</TABLE>
- ------------
(a) This column includes amounts deferred in stock units and held under AEP's
various director and officer benefit plans. Certain of these stock units are
subject to forfeiture based on service as a director.
(b) Includes the following numbers of share equivalents held in the AEP
Employees Savings Plan over which such persons have sole voting power, but
the investment/disposition power is subject to the terms of the Savings
Plan: Mr. Clements, 1,134: Dr. Draper, 3,033; Mr. Lhota, 13,862; Dr.
Markowsky, 3,888; Mr. Vipperman, 10,002; and all executive officers, 36,063.
(c) Includes the following numbers of shares held in joint tenancy with a family
member: Mr. DesBarres, 5,000; Dr. Draper, 4,901; Mr. Lhota, 2,180; Ms.
Stuntz, 300; and Mr. Vipperman, 67.
(d) Includes the following numbers of shares held by family members over which
beneficial ownership is disclaimed: Dr. Hudson, 750; and Dr. Markowsky, 20.
(e) Does not include, for Messrs. Lhota and Vipperman, 85,231 shares in the
American Electric Power System Educational Trust Fund over which Messrs.
Lhota and Vipperman 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.
(f) Includes 1,500 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 1,000 of such shares.
(g) Represents less than 1% of the total number of shares outstanding.
18
<PAGE>
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
SECTION 16(a) of the Securities Exchange Act of 1934 requires AEP's executive
officers and directors to file initial reports of ownership and reports of
changes in ownership of Common Stock of AEP with the Securities and Exchange
Commission. Executive officers and directors are required by SEC regulations to
furnish AEP with copies of all reports they file. Based solely on a review of
the copies of such reports furnished to AEP and written representations from
AEP's executive officers and directors during the fiscal year ended December 31,
1998, AEP notes that Leonard J. Kujawa, a director, did not timely report three
acquisitions of 200 shares each of AEP Common Stock that occurred in April, July
and August 1998, although he reported them thereafter.
SHARE OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
SET FORTH BELOW is the only person or group known to AEP as of December 31,
1998, with beneficial ownership of five percent or more of AEP Common Stock.
<TABLE>
<CAPTION>
AEP SHARES
--------------------------
AMOUNT OF
NAME, ADDRESS OF BENEFICIAL PERCENT OF
BENEFICIAL OWNER OWNERSHIP CLASS
- ------------------------- ------------- -----------
<S> <C> <C>
Sanford C................ 18,036,071(a) 9.4 %
Bernstein & Co., Inc.
767 Fifth Avenue
New York, NY 10153
</TABLE>
- ------------
(a) Based on the Schedule 13G filed with the SEC, Sanford C. Bernstein & Co.,
Inc. reported that it has sole voting power for 10,646,428 shares, shared
voting power for 1,833,458 shares, and sole dispositive power for 18,036,071
shares.
SHAREHOLDER PROPOSALS
TO BE INCLUDED in AEP's proxy statement and form of proxy for the 2000 annual
meeting of shareholders, any proposal which a shareholder intends to present at
such meeting must be received by AEP at its office at 1 Riverside Plaza,
Columbus, Ohio 43215 by November 12, 1999.
For any proposal intended to be presented by a shareholder without inclusion
in AEP's proxy statement and form of proxy for the 2000 annual meeting, the
proxies named in AEP's form of proxy for that meeting will be entitled to
exercise discretionary authority on that proposal unless AEP receives notice of
the matter by February 1, 2000. However, even if notice is timely received, the
proxies may nevertheless be entitled to exercise discretionary authority on the
matter to the extent permitted by Securities and Exchange Commission
regulations.
SOLICITATION EXPENSES
THE COSTS of this proxy solicitation will be paid by AEP. Proxies will be
solicited principally by mail, but some telephone, telegraph or personal
solicitations of holders of AEP Common Stock may be made. Any officers or
employees of the AEP System who make or assist in such solicitations will
receive no compensation, other than their regular salaries, for doing so. AEP
will request brokers, banks and other custodians or fiduciaries holding shares
in their names or in the names of nominees to forward copies of the
proxy-soliciting materials to the beneficial owners of the shares held by them,
and AEP will reimburse them for their expenses incurred in doing so at rates
prescribed by the New York Stock Exchange.
19
<PAGE>
- --------------------------------------------------------------------------------
[LOGO]
1 Riverside Plaza
Columbus, OH 43215-2373
[PRINTED WITH SOY INK]
[PRINTED ON RECYCLED PAPER]
<PAGE>
APPENDIX A TO THE
PROXY STATEMENT
AMERICAN ELECTRIC POWER
1998 ANNUAL REPORT
AUDITED FINANCIAL STATEMENTS AND
MANAGEMENT'S DISCUSSION AND ANALYSIS
[LOGO]
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER
1 RIVERSIDE PLAZA
COLUMBUS, OHIO 43215-2373
<TABLE>
<CAPTION>
CONTENTS
- -------------------------------------------------------------------------------
<S> <C>
Selected Consolidated Financial Data ........................................2
Management's Discussion and Analysis of
Results of Operations and Financial Condition.........................3 - 24
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings..............................25
Consolidated Balance Sheets............................................26 - 27
Consolidated Statements of Cash Flows.......................................28
Notes to Consolidated Financial Statements.............................29 - 57
Schedule of Consolidated Cumulative
Preferred Stocks of Subsidiaries..........................................58
Schedule of Consolidated Long-term Debt of Subsidiaries.....................59
Management's Responsibility.................................................60
Independent Auditors' Report................................................61
</TABLE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
<TABLE>
<CAPTION>
Year Ended December 31, 1998 1997 1996 1995 1994
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
INCOME STATEMENTS DATA (in millions):
Operating Revenues $6,346 $5,880 $5,849 $5,670 $5,505
Operating Income 957 984 1,008 965 932
Income Before Extraordinary Item 536 620 587 530 500
Extraordinary Loss -
UK Windfall Tax - 109 - - -
Net Income 536 511 587 530 500
</TABLE>
<TABLE>
<CAPTION>
December 31, 1998 1997 1996 1995 1994
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
BALANCE SHEETS DATA (in millions):
Electric Utility Plant $20,146 $19,597 $18,970 $18,496 $18,175
Accumulated Depreciation
and Amortization 8,416 7,964 7,550 7,111 6,827
------- ------- ------- ------- -------
Net Electric
Utility Plant $11,730 $11,633 $11,420 $11,385 $11,348
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Total Assets $19,483 $16,615 $15,883 $15,900 $15,736
Common Shareholders' Equity 4,842 4,677 4,545 4,340 4,229
Cumulative Preferred Stocks
of Subsidiaries:
Not Subject to Mandatory Redemption 46 47 90 148 233
Subject to Mandatory Redemption* 128 128 510 523 590
Long-term Debt* 7,006 5,424 4,884 5,057 4,980
Obligations Under Capital Leases* 533 538 414 405 400
</TABLE>
*Including portion due within one year
<TABLE>
<CAPTION>
Year Ended December 31, 1998 1997 1996 1995 1994
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
COMMON STOCK DATA:
Earnings per Common Share:
Before Extraordinary Item $2.81 $ 3.28 $3.14 $2.85 $2.71
Extraordinary Loss - UK Windfall Tax - (0.58) - - -
------- ------- ------- ------- -------
Net Income $2.81 $ 2.70 $3.14 $2.85 $2.71
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Average Number of Shares
Outstanding (in thousands) 190,774 189,039 187,321 185,847 184,666
Market Price Range: High $53-5/16 $ 52 $44-3/4 $40-5/8 $37-3/8
Low 42-1/16 39-1/8 38-5/8 31-1/4 27-1/4
Year-end Market Price 47-1/16 51-5/8 41-1/8 40-1/2 32-7/8
Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio 85.4% 88.7%(a) 76.5% 84.1% 88.6%
Book Value per Share $25.24 $24.62 $24.15 $23.25 $22.83
</TABLE>
(a) Dividend Payout Ratio before Extraordinary Loss - UK Windfall Tax is
73.1%.
2
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
This discussion includes forward-looking statements within the meaning of
Section 21E of the Securities Exchange Act of 1934. These forward-looking
statements reflect assumptions, and involve a number of risks and
uncertainties. Among the factors that could cause actual results to differ
materially from forward looking statements are: electric load and customer
growth; abnormal weather conditions; available sources and costs of fuels;
availability of generating capacity; the impact of the proposed merger with
Central and South West Corporation (CSW) including any regulatory conditions
imposed on the merger or the inability to consummate the merger with CSW; the
speed and degree to which competition is introduced to our power generation
business, the structure and timing of a competitive market and its impact on
energy prices or fixed rates; the ability to recover stranded costs in
connection with possible deregulation of generation; new legislation and
government regulations; the ability of the Company to successfully control
its costs; the success of new business ventures; international developments
affecting our foreign investments; the economic climate and growth in our
service territory; unforeseen events affecting the Company's nuclear plant
which is on an extended safety related shutdown; problems or failures related
to Year 2000 readiness of computer software and hardware; inflationary
trends; electricity and gas market prices; interest rates and other risks and
unforeseen events. This discussion contains a "Year 2000 Readiness
Disclosure" within the meaning of the Year 2000 Information and Readiness
Disclosure Act.
GROWTH OF THE BUSINESS
In 1998 management continued to implement its growth-oriented strategy
with a goal of being America's Energy Partner and a global energy and related
services company. We have adopted a strategy to expand our geographic reach
and to build and acquire capabilities across a broader spectrum of the energy
products and services value chain. AEP is working to position itself to be
successful in an increasingly competitive market that will allow customers to
choose their energy supplier. AEP made several acquisitions in 1998 that
expanded its energy operations overseas and in the United States. The
expansion of the foreign energy business in 1998 included the purchase of
CitiPower, an Australian electric distribution utility, the acquisition of an
equity interest in Pacific Hydro, an Australian hydroelectric generating
company, and continued on- schedule construction of two generating units in
China.
The $1.1 billion acquisition of CitiPower, completed on December 31,
1998, was accounted for using the purchase method of accounting. CitiPower
serves approximately 240,000 customers in the city of Melbourne. CitiPower
will contribute to earnings beginning in the first quarter of 1999.
In March 1998 the Company invested $10 million to acquire a 20% equity
interest in Pacific Hydro. Pacific Hydro operates four hydroelectric power
stations in Australia with an installed capacity of 40 megawatts (MW) and has
interests in two hydroelectric projects under construction in the Philippines.
3
<PAGE>
The generating units under construction in China are owned 70% by the
Company with the remaining 30% owned by two Chinese partners. Construction of
the two unit 250 MW, coal-fired station is proceeding on schedule. The first
unit began commercial operation in February of 1999 and the second unit is
expected to go into commercial service in July of 1999. These units are
expected to contribute to earnings in 1999.
In addition, the Company has a 50% investment in Yorkshire Electricity
Group plc (Yorkshire), a United Kingdom (UK) distribution electric company.
The investment was made in April 1997 and contributed $38.5 million to
nonregulated, nonoperating income in 1998. In September 1998 certain
residential and commercial customers in the UK could choose their electricity
supplier marking the start of a transition to competition. Yorkshire serves
approximately 2.2 million customers.
One disappointment we suffered in 1998 was the withdrawal of a joint
venture partner. In 1997 the Company announced a joint venture with Conoco,
an energy subsidiary of DuPont. The venture was to provide energy management
and financing for steam and electric generation facilities for commercial and
industrial customers. Conoco withdrew from the joint venture after its parent
announced plans to sell Conoco.
The past year also saw the expansion of AEP's domestic energy operations.
On December 1, 1998, the Company purchased the midstream gas operations of
Equitable Resources, Inc. for approximately $340 million including working
capital funds. The midstream operations include a fully integrated natural
gas gathering, processing, storage and transportation operation in Louisiana
and a gas trading and marketing operation in Houston, Texas. Assets include
an intrastate pipeline system, four natural gas processing plants plus a
fifth plant under construction, one natural gas storage facility and an
additional storage facility under construction. The gas trading operation
included in this purchase was merged with AEP's existing gas trading
organization which began operating in December 1997. This acquisition is
expected to enhance AEP's gas trading operations by improving management's
knowledge of the Henry Hub gas market.
Traditionally a major marketer of electricity, AEP has recently become a
major participant in the electricity trading market. Our electricity trading
operation, which commenced in mid 1997, significantly expanded its trading
volume in 1998. Electricity trading involves the trading of contracts for the
future delivery or receipt of electricity in both regulated and non-regulated
operations. It also involves the purchase and sale of options, swaps and
other electricity derivative financial instruments. Open access transmission,
the introduction of competition to the wholesale electricity market and the
development of a trading market and settlement process have fostered the
growth of electricity trading in the United States. The electricity trading
market is a highly volatile market which requires enhanced credit and market
risk management skills. Electricity trading requires little capital
investment and profit margins are usually smaller than margins on traditional
electricity sales. The Company's goal is to utilize its knowledge of energy
markets to trade electricity and gas to contribute to net income, thereby
enhancing both customer and shareholder value.
4
<PAGE>
In December 1997 the Company and CSW agreed to merge. The merger is
intended to expand AEP's geographic reach. The benefits of the merger include
costs savings; improved prices and services; increased financial strength;
greater diversity in fuel, generation and service territory; and increased
scale (the size of the Company which contributes to business success in a
competitive market). At the 1998 annual meeting AEP shareholders approved the
issuance of common shares to effect the merger and approved an increase in
the number of authorized shares of AEP Common Stock from 300,000,000 to
600,000,000 shares. CSW stockholders approved the merger at their May 1998
annual meeting. Approval of the merger has been requested from the Federal
Energy Regulatory Commission (FERC), the Securities and Exchange Commission,
the Nuclear Regulatory Commission (NRC) and all of CSW's state regulatory
commissions: Arkansas, Louisiana, Oklahoma and Texas. In the near future, AEP
and CSW plan to make the final two filings associated with approval of the
merger with the Federal Communications Commission and the Department of
Justice.
Regulatory approvals for the merger have been received from the Arkansas
Public Service Commission (APSC) and the NRC. In December 1998 the APSC
approved a stipulated agreement related to a proposed merger regulatory plan
submitted by the Company, CSW and CSW's Arkansas operating subsidiary,
Southwestern Electric Power Company. The regulatory plan, agreed to with the
APSC staff, provides for a sharing of net merger savings through a $6 million
rate reduction over 5 years following the completion of the merger.
The application to the NRC by CSW's operating subsidiary, Central Power
and Light Company (CPL), requesting permission to transfer indirect control
of the license from CSW to AEP for CPL's interest in the South Texas Project
nuclear generating station was approved by the NRC in November 1998.
In October 1998 the Oklahoma Corporation Commission (OCC) approved plans
by AEP and CSW to submit an amended filing seeking approval of the proposed
merger. The amended application is being made as a result of an Oklahoma
administrative law judge's recommendation that the merger filing be dismissed
without prejudice for lack of sufficient information regarding the potential
impact of the merger on the retail electric market in Oklahoma. Submission of
the amended application will reset Oklahoma's 90-day statutory time period
for OCC action on the merger phase of the application. The filing of the
amended application should not affect the timing of the merger closing.
A settlement agreement between AEP, CSW and certain key parties to the
Texas merger proceeding has been reached. The staff of the Public Utility
Commission of Texas was not a signatory to the settlement agreement, which
resolves all issues for the signatories. The settlement provides for, among
other things, rate reductions totaling approximately $180 million over a six
year period following completion of the merger to share net merger savings of
$84 million and settle existing rate issues of $96 million. Hearings are
scheduled for April 1999.
5
<PAGE>
In July 1998 the FERC issued an order which confirmed that a 250 megawatt
firm contract path with the Ameren System is available. The contract path was
obtained by AEP and CSW to meet the requirement of the Public Utility Holding
Company Act of 1935 that the two systems operate on an integrated and
coordinated basis.
In November 1998 the FERC issued an order establishing hearing procedures
for the merger and scheduled the hearings to begin on June 1, 1999. The FERC
order indicated that the review of the proposed merger will address the issues
of competition, market power and customer protection and instructed the
companies to refile an updated market power study.
The proposed merger of CSW into AEP would result in common ownership of
two UK regional electricity companies (RECs), Yorkshire and Seeboard, plc.
AEP has a 50% ownership interest in Yorkshire and CSW has a 100% interest in
Seeboard. Although the merger of CSW into AEP is not subject to approval by
UK regulatory authorities, the common ownership of two UK RECs could be
referred by the UK Secretary of State for Trade and Industry to the UK
Monopolies and Mergers Commission for investigation.
AEP has received a request from the staff of the Kentucky Public Service
Commission (KPSC) to file an application seeking KPSC approval for the
indirect change in control of Kentucky Power Company that will occur as a
result of the proposed merger. Although AEP does not believe that the KPSC
has the jurisdictional authority to approve the merger, management will
prepare a merger application filing to be made with the KPSC, which is
expected to be filed by April 15, 1999. Under the governing statute the KPSC
must act on the application within 60 days. Therefore this is not expected to
impact the timing of the merger.
The merger is conditioned upon, among other things, the approval of the
above state and federal regulatory agencies. The transaction must satisfy
many conditions, a number of which may not be waived by the parties,
including the condition that the merger must be accounted for as a pooling of
interests. The merger agreement will terminate on December 31, 1999 unless
extended by either party as provided in the merger agreement. Although
consummation of the merger is expected to occur in the fourth quarter of
1999, the Company is unable to predict the outcome or the timing of the
required regulatory proceedings.
BUSINESS OUTLOOK
The most significant factors affecting the Company's future earnings are
the ability to recover its costs as the domestic electric generating business
becomes more competitive and the performance of the recently acquired energy
investments and business ventures described above. The Company continues to
evaluate domestic and international markets for investments to grow the
business in the best interests of our shareholders, customers and employees.
The performance of any future acquisitions, mergers and investments will also
impact future earnings.
The introduction of competition and customer choice for retail customers
in the Company's domestic service territory has been slow and continues at a
deliberate pace as legislators and regulatory officials recognize the
complexity of the issues. Federal
6
<PAGE>
legislation has been proposed to mandate competition and customer choice at
the retail level. In February 1999 the Virginia general assembly passed
legislation, subject to the governor's signature, that would provide Virginia
retail customers the ability to choose their electric supplier beginning in
2002. The legislation provides for the recovery of "just and reasonable net
stranded costs". Prior to January 1, 2001 the Virginia State Corporation
Commission must establish rates that will be "capped" through as long as July
1, 2007. Statement of Financial Accounting Standards (SFAS) 71 "Accounting
for the Effects of Certain Types of Regulation" will no longer apply to the
Company's Virginia retail jurisdiction once the "capped" rates are
established. When this occurs the application of SFAS 71 will be discontinued
for the Virginia retail jurisdiction portion of the generating business and
net regulatory assets applicable to the Virginia generating business would
have to be written off to the extent that they are not probable of recovery.
Although management does not believe that the impact of the new legislation
on regulatory assets would have a material adverse impact on results of
operations, cash flows or financial condition, the amount of an impairment
loss, if any, cannot be estimated with any certainty until the "capped" rates
are determined (See requirements of EITF 97-4 discussed below).
All of the other states within our service territory have initiatives to
implement or review customer choice, although the timing is uncertain. The
Company supports customer choice and deregulation of generation and is
proactively involved in discussions at both the state and federal levels
regarding the best competitive market structure and method to transition to a
competitive marketplace.
As the pricing of generation in the electric energy market evolves from
regulated cost-of-service ratemaking to market-based rates, many complex
issues must be resolved, including the recovery of stranded costs. Stranded
costs are those costs above market and potentially would not be recoverable
in a competitive market. At the wholesale level recovery of stranded costs
under certain conditions was addressed by the FERC when it established rules
for open transmission access and competition in the wholesale markets.
However, the issue of stranded cost is generally unresolved at the retail
level where it is much larger than it is at the wholesale level. The amount
of stranded costs the Company could experience depends on the timing and
extent to which competition is introduced to its generation business and the
future market prices of electricity. The recovery of stranded cost is
dependent on the terms of future legislation and related regulatory
proceedings.
Under the provisions of SFAS 71, regulatory assets (deferred expenses)
and regulatory liabilities (deferred revenues) are included in the
consolidated balance sheets of regulated utilities in accordance with
regulatory actions in order to match expenses and revenues with cost-based
rates. In order to maintain net regulatory assets on the balance sheet, SFAS
71 requires that rates charged to customers be cost-based and provide for the
recovery of the deferred expenses over future accounting periods. In the
event a portion of AEP's business no longer meets the requirements of SFAS
71, SFAS 101 "Accounting for the Discontinuance of Application of Statement
71" requires that net regulatory assets be written off for that portion of
the business. The provisions of SFAS 71 and SFAS 101 never anticipated that
deregulation would
7
<PAGE>
include an extended transition period or that it could provide for recovery
of stranded costs during and after the transition period. In 1997 the
Financial Accounting Standards Board's Emerging Issues Task Force (EITF)
addressed such a situation with the consensus reached on issue 97-4 that
requires the application of SFAS 71 to a segment of a regulated electric
utility cease when that segment is subject to a legislatively approved plan
for competition or an enabling rate order is issued containing sufficient
detail for the utility to reasonably determine what the plan would entail.
The EITF indicated that the cessation of application of SFAS 71 would require
that regulatory assets and impaired plant be written off unless they are
recoverable in future rates.
Although certain FERC orders provide for competition in the firm
wholesale market, that market is a relatively small part of our business and
most of our firm wholesale sales are still under cost-of-service contracts.
As of December 31, 1998 AEP's generation business is cost-based regulated.
The enactment of enabling legislation in Virginia to deregulate the
generation business will cause a portion of the Company's generation business
to become deregulated. This could ultimately result in adverse impacts on
results of operations and cash flows depending on the market price of
electricity and the ability of the Company to recover its stranded costs. We
believe that enabling state legislation should provide for the recovery of
any generation-related net regulatory assets and other reasonable stranded
costs from impaired generating assets. However, if in the future AEP's
generation business were to no longer be cost-based regulated and if it were
not possible to demonstrate probability of recovery of resultant stranded
costs including regulatory assets, results of operations, cash flows and
financial condition would be adversely affected.
COST CONTAINMENT AND PROCESS IMPROVEMENTS
Efforts continue to reduce the costs of AEP's products and services in
order to maintain competitiveness. The accounting department completed its
consolidation of operations and the marketing department completed its
reorganization in 1998 producing significant cost reductions. In 1998 plans
were announced to close one of the Company's coal mining operations in
October 1999 and the Company reviewed its staffing levels for power
generation and energy delivery and developed plans to reduce staff in 1999.
The cost of staff reductions planned for 1999 was provided for in the fourth
quarter of 1998. Although cost savings are expected to result from the power
generation and energy delivery reorganizations and the planned mine closing,
the Company continues to incur expenses related to investments in new
business growth and development; marketing and customer services; and the
reengineering and improvement of business processes.
During 1998, AEP completed installation of a new unified customer service
system which is designed to support customer requests for service, billings,
accounts receivable, credit and collection functions. On January 1, 1999, the
Company's new financial data base and PeopleSoft client server accounting and
purchasing software became operational. The move to client server business
software and related online data bases will empower AEP employees to maximize
the benefits of their personal computers and will position AEP to access the
power of the Internet and other new technologies.
8
<PAGE>
FUEL COSTS
The management and control of coal costs is critical to AEP's competitive
position. Approximately 90% of AEP's generation is coal fired and
approximately 13% of the 54 million tons of coal burned in 1998 were supplied
by affiliated mines with the remainder acquired under long-term contracts and
purchases in the spot market. As long-term contracts expire we are
negotiating with unaffiliated suppliers to lower coal costs. We intend to
continue to prudently supplement our long-term coal supplies with spot market
purchases when spot market prices are favorable.
We have agreed in our Ohio jurisdiction to certain limitations on the
current recovery of affiliated coal costs. At December 31, 1998, the Company
had deferred $106 million for future recovery under the agreements which
established the limitation. See discussion in Note 2 of the Notes to
Consolidated Financial Statements. Our analysis shows that we should be able
to recover the Ohio jurisdictional portion of the costs of our affiliated
mining operations including future mine closure costs before the expiration
of the agreement in 2009. The Company has announced plans to close the
Muskingum mine in 1999. A provision for Muskingum mine closing cost of $45
million was recorded in 1998. Management intends to seek recovery of its
non-Ohio jurisdictional portion of its investment in and the liabilities and
closing costs of affiliated mines estimated at $100 million after tax.
Should it become apparent that these affiliated mining costs will not be
recovered from Ohio and/or non-Ohio jurisdictional customers, the other mines
may have to be closed and future earnings, cash flows and possibly financial
condition would be adversely affected. In addition compliance with Phase II
requirements of the Clean Air Act Amendments of 1990 (CAAA), which become
effective in January 2000, could also cause the remaining mining operations
to close. Unless the cost of any mine closure and the coal cost deferrals in
the Ohio jurisdiction are recovered either in regulated rates or as a
stranded cost under a plan to transition the generation business to
competition, future earnings, cash flows and possibly financial condition
would be adversely affected.
COSTS FOR SPENT NUCLEAR FUEL AND DECOMMISSIONING
AEP, as the owner of the Cook Nuclear Plant, like other nuclear power
plants, has a significant future financial commitment to safely dispose of
spent nuclear fuel (SNF) and decommission and decontaminate the plant. The
Nuclear Waste Policy Act of 1982 established federal responsibility for the
permanent off-site disposal of SNF and high-level radioactive waste. By law
we participate in the Department of Energy's (DOE) SNF disposal program which
is described in Note 4 of the Notes to Consolidated Financial Statements.
Since 1983 we have collected $272 million from customers for the disposal of
nuclear fuel consumed at the Cook Plant. $115 million of these funds have
been deposited in external trust funds to provide for the future disposal of
spent nuclear fuel and $157 million has been remitted to the DOE. Under the
provisions of the Nuclear Waste Policy Act, collections from customers are to
provide the DOE with money to build a repository for spent fuel. However, in
December 1996, the DOE notified AEP that it would be unable to begin
accepting SNF by the January 1998 deadline required by law.
9
<PAGE>
As a result of DOE's failure to make sufficient progress toward a
permanent repository or otherwise assume responsibility for SNF, AEP along
with a number of unaffiliated utilities and states filed suit in the U.S.
Court of Appeals for the District of Columbia Circuit requesting, among other
things, that the court order DOE to meet its obligations under the law. The
court ordered the parties to proceed with contractual remedies but declined
to order DOE to begin accepting SNF for disposal. DOE estimates its planned
site for the nuclear waste will not be ready until 2010. In June 1998, AEP
filed a complaint in the U.S. Court of Federal Claims seeking damages in
excess of $150 million due to the DOE's partial material breach of its
unconditional contractual deadline to begin disposing of SNF generated by the
Cook Nuclear Plant. Similar lawsuits have been filed by other utilities. As
long as the delay in the availability of a government approved storage
repository for SNF continues, the cost of both temporary and permanent
storage will increase.
The cost to decommission the Cook Plant is affected by both NRC
regulations and the delayed SNF disposal program. Studies completed in 1997
estimate the cost to decommission the Cook Plant ranges from $700 million to
$1,152 million in 1997 dollars. This estimate could escalate due to continued
uncertainty in the SNF disposal program and the length of time that SNF may
need to be stored at the plant site. External trust funds have been
established with amounts collected from customers to decommission the plant.
At December 31, 1998, the total decommissioning trust fund balance was $443
million which includes earnings on the trust investments. We will work with
regulators and customers to recover the remaining estimated cost of
decommissioning the Cook Plant. However, AEP's future results of operations,
cash flows and possibly its financial condition would be adversely affected
if the cost of SNF disposal and decommissioning continues to increase and
cannot be recovered.
COOK NUCLEAR PLANT SHUTDOWN
We shut down both units of the Cook Nuclear Plant in September 1997 due
to questions, which arose during a NRC architect engineer design inspection,
regarding the operability of certain safety systems. The NRC issued a
Confirmatory Action Letter in September 1997 requiring AEP to address the
issues identified in the letter. We are working with the NRC to resolve the
remaining open issue in the letter.
In April 1998 the NRC notified I&M that it had convened a Restart Panel
for Cook Plant. A list of required restart activities was provided by the NRC
in July 1998 and in October the NRC expanded the list. In order to identify
and resolve the issues necessary to restart the Cook units, AEP is and will
be meeting with the Panel on a regular basis, until the units are returned to
service.
In January 1999 we announced that we will conduct additional engineering
reviews at the Cook Plant that will delay restart of the units. Previously,
the units were scheduled to return to service at the end of the first and
second quarters of 1999. The decision to delay restart resulted from internal
assessments that indicated a need to conduct expanded system readiness
reviews. A new restart schedule will be developed based on the results of the
expanded reviews and should be available in June 1999. When maintenance and
other activities required for restart are complete, AEP will seek concurrence
from the NRC to return the
10
<PAGE>
Cook Plant to service. Until these additional reviews are completed,
management is unable to determine when the units will be returned to service.
Unless the costs of the extended outage and restart efforts are recovered
from customers, there would be a material adverse effect on results of
operations, cash flows and possibly financial condition.
One of the steps AEP has taken toward expediting the restart of the Cook
units is to augment its existing nuclear generation management and staff with
personnel experienced in restarting unaffiliated companies' nuclear plants
during NRC supervised extended outages.
The incremental costs incurred in 1997 and 1998 for restart of the Cook
units were $6 million and $78 million, respectively, and recorded as
operation and maintenance expense. Currently incremental restart expenses are
approximately $12 million a month.
In July 1998 AEP received an "adverse trend letter" from the NRC
indicating that NRC senior managers determined that there had been a slow
decline in performance at the Cook Plant during the 18 month period preceding
the letter. The letter indicated that the NRC will closely monitor efforts to
address issues at Cook Plant through additional inspection activities. In
October 1998 the NRC issued AEP a Notice of Violation and proposed a $500,000
civil penalty for alleged violations at the Cook Plant discovered during five
inspections conducted between August 1997 and April 1998. AEP paid the
penalty.
The cost of electricity supplied to certain retail customers rose due to
the outage of the two units since higher cost coal-fired generation and coal
based purchased power were substituted for low cost nuclear generation. AEP's
Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms
permit the recovery, subject to regulatory commission review and approval, of
changes in fuel costs including the fuel component of purchased power in the
Indiana jurisdiction and changes in replacement power in the Michigan
jurisdiction. Under these fuel cost recovery mechanisms, retail rates contain
a fuel cost adjustment factor that reflects estimated fuel costs for the
period during which the factor will be in effect subject to reconciliation to
actual fuel costs in a future proceeding. When actual fuel costs exceed the
estimated costs reflected in the billing factor a regulatory asset is
recorded and revenues are accrued. Therefore, a regulatory asset has been
recorded and revenues accrued in anticipation of the future reconciliation
and billing under the fuel cost recovery mechanisms of the higher fuel costs
to replace Cook energy during the extended outage. At December 31, 1998, the
regulatory asset was $65 million.
The Indiana Utility Regulatory Commission approved, subject to future
reconciliation or refund, agreements authorizing AEP, during the billing
months of July 1998 through March 1999, to include in rates a fuel cost
adjustment factor less than that requested by AEP. The agreements provide the
parties to the proceedings with the opportunity to conduct discovery
regarding certain issues that were raised in the proceedings, including the
appropriateness of the recovery of replacement energy cost due to the
extended Cook Plant outage, in anticipation of resolving the issues in a
future fuel cost adjustment proceeding. Management believes that it should be
allowed to recover the deferred Cook replacement energy costs; however, if
11
<PAGE>
recovery of the replacement costs is denied, future results of operations and
cash flows would be adversely affected by the writeoff of the regulatory
asset.
ENVIRONMENTAL CONCERNS AND ISSUES
We take great pride in our efforts to economically produce and deliver
electricity while minimizing the impact on the environment. Over the years
AEP has spent more than a billion dollars to equip its facilities with the
latest cost effective clean air and water technologies and to research new
technologies. We are also proud of our award winning efforts to reclaim our
mining properties. We intend to continue in a leadership role fostering
economically prudent efforts to protect and preserve the environment.
By-products from the generation of electricity include materials such as
ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion
by-products, which constitute the overwhelming percentage of these materials,
are typically disposed of or treated in captive disposal facilities or are
beneficially utilized. In addition, our generating plants and transmission
and distribution facilities have used asbestos, polychlorinated biphenyls
(PCBs) and other hazardous and nonhazardous materials. We are currently
incurring costs to safely dispose of such substances. Additional costs could
be incurred to comply with new laws and regulations if enacted.
The Comprehensive Environmental Response, Compensation and Liability Act
(Superfund) addresses clean-up of hazardous substances at disposal sites and
authorized the United States Environmental Protection Agency (Federal EPA) to
administer the clean-up programs. As of year-end 1998, we are involved in
litigation with respect to three sites overseen by the Federal EPA and have
been named by the Federal EPA as a potentially responsible party (PRP) for
three other sites. There is one additional site for which AEP has received an
information request which could lead to PRP designation. Our liability has
been resolved for a number of sites with no significant effect on results of
operations. In those instances where we have been named a PRP or defendant,
our disposal or recycling activity was in accordance with the then-applicable
laws and regulations. Unfortunately, Superfund 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 our potential
future liability. AEP's disposal of materials at a particular site is often
unsubstantiated and the quantity of materials deposited at a site was small
and often nonhazardous. Typically many parties are named as PRPs for each
site and, although liability is joint and several, generally several of the
parties are financially sound enterprises. Therefore, our present estimates
do not anticipate material cleanup costs for identified sites for which we
have been declared PRPs. However, if for reasons not currently identified
significant cleanup costs are attributed in the future to AEP, results of
operations, cash flows and possibly financial condition would be adversely
affected unless the costs can be recovered from customers.
In December 1998 the Company purchased gas assets from Equitable
Resources, Inc. (Equitable). The purchase contract contains details of
partial indemnification by Equitable for certain environmental and soil and
12
<PAGE>
ground water contamination cleanup liabilities which existed at the time of
AEP's purchase. An outside consultant has estimated total environmental
liabilities for the acquired entities to range from $10 million to $16
million. By contract the Company must seek indemnification by December 1,
2000. The indemnification clause requires that AEP incur $3 million of
cleanup liabilities before seeking reimbursement. Based upon the consultant's
estimate, environmental liabilities resulting from the gas asset acquisition
should not have a material impact on results of operations, cash flows or
financial condition.
In December 1998, the Company purchased CitiPower, an Australian
distribution utility, from Entergy, an unaffiliated company. CitiPower
operates under Australian environmental laws. Prior to the purchase, AEP
hired an outside consultant, experienced in Australian environmental laws, to
identify CitiPower's exposure. The consultant's assessment identified sites
with contaminated land, PCBs and storm water runoff. Cost of environmental
remediation are estimated at $3.5 million by the consultant. Based upon this
estimate, environmental costs from the acquisition of CitiPower are not
expected to have a material impact on results of operations, cash flows or
financial condition.
Federal EPA is required by the CAAA to issue rules to implement the law.
In 1996 Federal EPA issued final rules governing nitrogen oxides (NOx)
emissions that must be met after January 1, 2000 (Phase II of CAAA). The
final rules will require substantial reductions in NOx emissions from certain
types of boilers including those in AEP's power plants. To comply with Phase
II of CAAA, the Company plans to install NOx emission control equipment on
certain units and switch fuel at other units. Total capital costs to meet the
requirements of Phase II of CAAA are estimated to be approximately $90
million of which $69 million has been incurred through December 31, 1998.
On September 24, 1998, the administrator of Federal EPA signed final
rules which require reductions in NOx emissions in 22 eastern states,
including the states in which the Company's generating plants are located.
The implementation of the final rules would be achieved through the revision
of state implementation plans (SIPs) by September 1999. SIPs are a procedural
method used by each state to comply with Federal EPA rules. The final rules
anticipate the imposition of a NOx reduction on utility sources of
approximately 85% below 1990 emission levels by the year 2003. On October 30,
1998, a number of utilities, including the operating companies of the AEP
System, filed petitions in the U.S. Court of Appeals for the District of
Columbia Circuit seeking a review of the final rules.
Should the states fail to adopt the required revisions to their SIPs
within one year of the date the final rules were signed (September 24, 1999),
Federal EPA has proposed to implement a federal plan to accomplish the NOx
reductions. Federal EPA also proposed the approval of portions of petitions
filed by eight northeastern states that would result in imposition of NOx
emission reductions on utility and industrial sources in upwind midwestern
states. These reductions are substantially the same as those required by the
final NOx rules and could be adopted by Federal EPA in the event the states
fail to implement SIPs in accordance with the final rules.
13
<PAGE>
Preliminary estimates indicate that compliance costs could result in
required capital expenditures of approximately $1.2 billion for the AEP
System. Compliance costs cannot be estimated with certainty and the actual
costs incurred to comply could be significantly different from this
preliminary estimate depending upon the compliance alternatives selected to
achieve reductions in NOx emissions. Unless such costs are recovered from
customers, they would have a material adverse effect on results of
operations, cash flows and possibly financial condition.
At the Third Conference of the Parties to the United Nations Framework
Convention on Climate Change held in Kyoto, Japan in December 1997 more than
160 countries, including the United States, negotiated a treaty requiring
legally-binding reductions in emissions of greenhouse gases, chiefly carbon
dioxide, which many scientists believe are contributing to global climate
change. The treaty, which requires the advice and consent of the United
States Senate for ratification, would require the United States to reduce
greenhouse gas emissions seven percent below 1990 levels in the years
2008-2012. Although the United States has agreed to the treaty and signed it
on November 12, 1998, President Clinton has indicated that he will not submit
the treaty to the Senate for consideration until it contains requirements for
"meaningful participation by key developing countries" and the rules,
procedures, methodology and guidelines of the treaty's market-based policy
instruments, joint implementation programs and compliance enforcement
provisions have been negotiated. At the Fourth Conference of the Parties,
held in Buenos Aires, Argentina, in November 1998, the parties agreed to a
work plan to complete negotiations on outstanding issues with a view toward
approving them at the Sixth Conference of the Parties to be held in December
2000. We will continue to work with the Administration and Congress to
monitor the development of public policy on this issue.
If the Kyoto treaty is approved by Congress, the costs to comply with the
emission reductions required by the treaty are expected to be substantial and
would have a material adverse impact on results of operations, cash flows and
possibly financial condition if not recovered from customers.
RESULTS OF OPERATIONS
NET INCOME
Net income increased 5% to $536 million or $2.81 per share from $511
million or $2.70 per share in 1997 primarily due to the effect of a 1997
extraordinary loss of $109 million. The extraordinary loss, recorded in 1997,
was a result of the UK's one-time windfall tax which was based on a revision
or recomputation of the original privatization value of certain privatized
utilities, including Yorkshire. In 1997 net income decreased 13% to $511
million primarily due to the extraordinary loss of $109 million from the UK's
one-time windfall tax.
INCOME BEFORE EXTRAORDINARY ITEM
In 1998 income before the extraordinary loss, recorded in 1997, decreased
14% to $536 million or $2.81 per share from $620 million or $3.28 per share
in 1997. Several major items reduced 1998 earnings including the cost of
restart activities during an extended outage at the Cook Nuclear Plant, a
write-down of Yorkshire's investment in Ionica, a UK telecommunications
company, severance accruals for reductions in power generation and energy
delivery staff and mild winter and fall weather.
14
<PAGE>
AEP's 1997 income before the extraordinary loss increased 6% to $620
million or $3.28 per share from $587 million or $3.14 per share in 1996. The
increase was primarily attributable to increased transmission service
revenues, reduced preferred stock dividends due to a redemption program and
an increase in nonoperating income from equity earnings, exclusive of the
extraordinary loss, since the April 1997 investment in Yorkshire.
REVENUES INCREASE
Operating revenues increased 8% in 1998 and were relatively unchanged in
1997. Increased revenues from retail, wholesale and transmission service
customers were the primary reasons for the increase in 1998. The slight
increase in 1997 is primarily due to increased transmission service revenues.
The changes in the components of revenues are as follows:
<TABLE>
<CAPTION>
Increase (Decrease)
From Previous Year
----------------------------------------
(Dollars in Millions) 1998 1997
- ------------------------------------------------------------------------
Amount % Amount %
--------- ----- --------- -----
<S> <C> <C> <C> <C>
Retail:
Residential $ 37.6 $(34.7)
Commercial 57.0 1.8
Industrial 90.1 18.2
Other 3.8 0.4
------ ------
188.5 3.8 (14.3) (0.3)
Wholesale 206.8 25.9 6.1 0.8
Transmission 68.0 61.7 33.3 43.2
Miscellaneous 2.8 4.8 5.5 10.9
------ ------
Total $466.1 7.9 $ 30.6 0.5
------ ------
------ ------
</TABLE>
Retail revenues increased 4% in 1998 reflecting a 2% sales increase and
higher fuel recoveries. The increase in retail fuel recoveries reflects
higher cost coal fired generation and purchased power replacing power usually
generated at the Cook Nuclear Plant. The Cook Plant has been unavailable
since September 1997. Although residential sales were flat reflecting mild
winter and fall weather in 1998, revenues from residential customers
increased 2%. The accrual of revenues for the recovery of the Cook related
increased fuel costs accounted for the increase in residential revenues. The
rise in commercial revenues resulted from a 4% increase in sales reflecting
increased usage and growth in the number of customers. Industrial revenues
increased 6% reflecting a sales increase of 2% following the resumption of
operations by a major industrial customer after an extended labor strike.
Also contributing to the increase in industrial revenues were favorable
contract price adjustments to certain major industrial customers and the
pass-through of higher power costs during periods of peak demand.
In 1997 retail revenues decreased slightly although retail sales rose one
half of a percent. Residential revenues and sales each declined 2% reflecting
mild weather. Sales to commercial customers increased slightly causing a
small increase in commercial revenues. Industrial sales increased 2%
accounting for the increase in industrial revenues. The increase in lower
priced sales to industrial customers resulted from increased usage.
The 26% increase in wholesale revenues in 1998 is attributable to trading
of electricity with other utilities and power marketers in the Company's
traditional marketing area and increased power marketing sales. Revenues from
the trading of electricity are recorded net of purchases. Regulated trading
activities are conducted as part of AEP's electric power wholesale marketing
and trading operations and involve the purchase and sale of substantial
amounts of electricity. Power marketing sales are for the resale of power
purchased from unaffiliated companies to other unaffiliated companies.
Although
15
<PAGE>
wholesale revenues rose, total wholesale sales declined due to a reduction in
coal conversion service sales. These sales are for the generation of
electricity from the purchaser's coal and as a result do not include fuel
costs. Consequently, the drop in coal conversion service sales did not have a
significant effect on wholesale revenues.
In 1997 wholesale revenues increased slightly primarily due to the
commencement of trading activities in July 1997 and a significant increase in
coal conversion service sales. Since the price of coal conversion service
sales is for the generation of electricity from coal provided by the
electricity purchaser and excludes fuel cost, a large change in coal
conversion service sales has a small impact on revenues.
The 62% increase in transmission service revenues in 1998 is attributable
to a substantial rise in the quantity of energy transmitted for other
entities over AEP's transmission lines. The increase in 1997 of 43% in
transmission service revenues was also due to an increase in the volume of
other companies' electricity transmitted through AEP's transmission system.
The issuance in 1996 of open transmission access rules by the FERC
facilitated the growth in transmission services.
The level of wholesale transactions, including transmission services,
tends to fluctuate due to the highly competitive nature of the short-term
energy market and other factors, such as affiliated and unaffiliated
generating plant availability, the weather and the economy. The FERC rules
which introduced a greater degree of competition into the wholesale energy
market have had a major effect on wholesale sales and increased transmission
service revenues as more electricity is traded in the short-term (spot)
market. The Company's sales and in turn its results of operations were
impacted by the quantities of energy and services sold to wholesale customers
as well as the sale prices and cost of goods sold. Future results of
operations will be affected by the quantity and price of both retail and
wholesale transactions which often depend on factors the Company does not
control including the level of competition, the weather and affiliated and
unaffiliated power plant availability. However, we work to keep abreast of
these factors and to take advantage of them whenever possible.
OPERATING EXPENSES INCREASE
Operating expenses increased 10% in 1998 and 1% in 1997. Changes in the
components of operating expenses were as follows:
<TABLE>
<CAPTION>
Increase (Decrease)
From Previous Year
---------------------------------------
(Dollars in Millions) 1998 1997
- ----------------------------------------------------------------------
Amount % Amount %
-------- ------ --------- -----
<S> <C> <C> <C> <C>
Fuel $ 90.1 5.5 $ 26.4 1.6
Purchased Power 301.7 223.9 48.6 56.5
Other Operation 75.7 6.2 17.3 1.4
Maintenance 59.7 12.3 (19.6) (3.9)
Depreciation and Amortization (11.1) (1.9) (9.7) (1.6)
Taxes Other Than Federal
Income Taxes 2.8 0.6 (8.0) (1.6)
Federal Income Taxes (25.1) (7.3) (0.9) (0.3)
------ ------
Total $493.8 10.1 $ 54.1 1.1
------ ------
------ ------
</TABLE>
Fuel expense increased in 1998 and 1997 primarily due to an increase in
the average cost of fuel consumed reflecting the reduced availability of
lower cost nuclear generation due to the unplanned shutdown of both of AEP's
nuclear units which began in September 1997 and continued throughout 1998.
16
<PAGE>
The significant increases in purchased power expense in both 1998 and
1997 were primarily due to purchases of electricity for resale to other
utilities and power marketers and for replacement of energy usually generated
at the Cook Plant. The increase in purchases made for resale to other
entities reflects an expanding and evolving wholesale marketplace.
Other operation expenses increased in 1998 due to the extended Cook Plant
outage, power marketing and trading compensation and severance accruals for
reductions in power generation and energy delivery staff.
Maintenance expense increased in 1998 largely due to expenditures to
prepare the Cook Plant units for restart and to restore service interrupted
by two severe snowstorms.
The decrease in federal income tax expense attributable to operations in
1998 was primarily due to a decrease in pre-tax operating income.
NONOPERATING INCOME
The significant decline in nonoperating income in 1998 was due to losses
from non-regulated energy trading activity and the write-down of Yorkshire's
investment in Ionica ($30 million). The trading of gas and electricity
outside of AEP's traditional marketing area is marked-to-market and recorded
in nonoperating income.
The increase in nonoperating income in 1997 was mainly due to income from
the Company's share of earnings from its April 1997 investment in Yorkshire.
The $34 million of equity in Yorkshire earnings included $10 million of tax
benefits related to a reduction of the UK corporate income tax rate from 33%
to 31% effective April 1, 1997. The utilization of foreign tax credits also
contributed to the increase in nonoperating income.
INTEREST CHARGES AND PREFERRED STOCK DIVIDEND REQUIREMENTS
In 1997 interest charges on both long-term and short-term debt increased
reflecting additional borrowing primarily to fund the Company's investment in
non-regulated operations including the investment in Yorkshire. Preferred
stock dividend requirements of the subsidiaries decreased in 1997 due to the
reacquisition of over 4 million shares of cumulative preferred stock.
FINANCIAL CONDITION
AEP's financial condition continues to be strong. The 1998 payout ratio
was 85.4%. It has been a management objective to reduce the payout ratio
through efforts to increase earnings in order to enhance AEP's ability to
invest in new energy based businesses that can leverage our core competencies
and improve shareholder value. AEP's three-year total shareholder return
ranked 14th among the companies in the S&P Electric Utility Index. While this
placed us just below the midpoint, it has been and continues to be
management's goal to be in the top quartile of the S&P Electric Utility Index
for three-year total shareholder return.
CAPITAL INVESTMENTS
The total consideration paid by AEP to acquire CitiPower was
approximately $1.1 billion which was financed by the issuance of debt in
Australia and an equity investment by AEP Resources, Inc. (AEPR). The
purchase, for approximately $340 million, of domestic gas assets in Louisiana
was funded with part of the
17
<PAGE>
proceeds from an issuance of $400 million of 6-1/2% senior notes by AEPR. For
more information see Note 6 of the Notes to Consolidated Financial
Statements. Also AEP's 70% interest in the construction of two 125 MW units
in China required approximately $61 million of investment during 1998.
Consolidated construction expenditures for all subsidiaries are expected to
be $2.4 billion over the next three years. All expenditures for domestic
electric utility construction, estimated to be $2.2 billion for the next three
years, are expected to be financed with internally generated funds.
CAPITAL RESOURCES - STRUCTURE AND LIQUIDITY
AEP's ratio of common equity to total capitalization including amounts
due within one year was 40.3% for 1998, compared with 45.5% for 1997 and
45.3% for 1996. The decline in 1998 reflects borrowing to support the
acquisitions which were completed in December.
The Company and its subsidiaries issued $1.9 billion principal amount of
long-term obligations in 1998 at interest rates ranging from 5% to 10.53%.
The Company also increased its borrowing under a long-term revolving credit
agreement which expires in June 2000 by $270 million. The principal amount of
long-term debt retirements, including maturities, totaled $563 million with
interest rates ranging from 2.85% to 9.60%. The operating subsidiaries senior
secured debt/first mortgage bond ratings are listed in the following table:
<TABLE>
<CAPTION>
Company Moody's S&P Fitch D & P
- ------- -------- ------- ------- -------
<S> <C> <C> <C> <C>
APCo A3 A A A
CSPCo A3 A- A- A
I&M Baa1 A- BBB+ BBB+
KPCo Baa1 A BBB+ BBB+
OPCo A3 A- A- A
</TABLE>
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 additional capital contributions by the
parent company. The companies formed to pursue non-regulated businesses use
short-term debt (through a revolving credit facility) which is replaced with
long-term debt when financial market conditions are favorable and capital
contributions by the parent company. They also assume outstanding debt as
part of the acquisition of existing business entities. Short-term debt
increased $62 million from the prior year-end balance and increased by $235
million in 1997. At December 31, 1998, AEP Co., Inc. (the parent company) and
its subsidiaries had unused short-term lines of credit of $763 million, and
several of AEP's subsidiaries engaged in non-regulated energy investments and
businesses had available $60 million under a $600 million revolving credit
agreement which expires in June 2000. The sources of funds available to AEP
are dividends from its subsidiaries, short-term and long-term borrowings and
proceeds from the issuance of common stock. AEP issued 1,826,000 shares of
common stock in 1998, 1,755,000 shares in 1997 and 1,600,000 shares in 1996
through a Dividend Reinvestment and Direct Stock Purchase Plan and the
Employee Savings Plan raising $86 million, $77 million and $65 million,
respectively. Additional sales of common stock and/or equity linked
securities may be necessary in the future to support the Company's growth.
Unless the domestic electric operating utility subsidiaries meet certain
earnings or coverage tests, they cannot issue additional mortgage bonds. In
18
<PAGE>
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.
The following debt coverages of AEP's principal domestic electric
operating utility subsidiaries remained strong in 1998:
<TABLE>
<CAPTION>
Coverages at
December 31, 1998
-----------------
Mortgage
--------
<S> <C>
APCo 3.88
CSPCo 6.36
I&M 6.39
KPCo 4.40
OPCo 13.43
</TABLE>
As the above table indicates, the major domestic electric operating
utility subsidiaries presently exceed the minimum coverage requirements.
MARKET RISKS
The Company as a major power producer and a trader of wholesale
electricity and natural gas has certain market risks inherent in its business
activities. The trading of electricity and natural gas and related financial
derivative instruments exposes the Company to market risk. Market risk
represents the risk of loss that may impact the Company due to adverse
changes in commodity market prices and rates. In 1998 the Company
substantially increased the volume of its wholesale electricity and natural
gas marketing and trading activities. Various policies and procedures have
been established to manage market risk exposures including the use of a risk
measurement model utilizing Value at Risk (VaR). Throughout the year ending
December 31, 1998, the highest, lowest and average quarterly VaR in the
wholesale trading portfolio was less than $11 million at a 95% confidence
level with a holding period of three business days. The Company used the
variance-covariance method for calculating VaR based on three months of daily
prices. Based on this VaR analysis, at December 31, 1998 a near term change
in commodity prices is not expected to have a material effect on the
Company's results of operations, cash flows or financial condition. At
December 31, 1997, the exposure for financial derivatives in electricity and
natural gas marketing activities were not material to the Company's
consolidated results of operations, financial position or cash flows.
Investments in foreign ventures expose the Company to risk of foreign
currency fluctuations. The Company's exposure to changes in foreign currency
exchange rates related to these foreign ventures and investments is not
expected to be significant for the foreseeable future since these foreign
investments are considered long-term and not expected to be liquidated in the
near-term. The Company does not presently utilize derivatives to manage its
exposures to foreign currency exchange rate movements.
The Company is exposed to changes in interest rates primarily due to
short-and long-term borrowings to fund its business operations. The debt
portfolio has both fixed and variable interest rates, terms from one day to
forty years and an average duration of five years at December 31, 1998.
The Company measures interest rate market risk exposure utilizing a VaR
model. The model is based on the Monte Carlo method of simulated price
movements with a 95% confidence level and a one year holding period. The
volatilities and correlations were based on three years of monthly prices.
The risk of potential loss in fair value
19
<PAGE>
attributable to the Company's exposure to interest rates, primarily related
to long-term debt with fixed interest rates, was $589 million at December 31,
1998 and $501 million at December 31, 1997. The Company would not expect to
liquidate its entire debt portfolio in a one year holding period. Therefore,
a near term change in interest rates should not materially affect results of
operations or the consolidated financial position of the Company. The Company
is currently utilizing interest rate swaps to manage its exposure to interest
rate fluctuations in Australia.
The Company has investments in debt and equity securities which are held
in nuclear trust funds. Approximately 85% of the trust fund value is invested
in tax exempt and taxable bonds, short-term debt instruments or cash. The
trust investments and their fair value are discussed in Note 11 of the Notes
to Consolidated Financial Statements. Instruments in the trust funds have not
been included in the market risk calculation for interest rates as these
instruments are marked-to-market and changes in market value are reflected in
a corresponding decommissioning liability. Any differences between the trust
fund assets and the ultimate liability should be recoverable from ratepayers.
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 result from the repayment of long-term debt with
inflated dollars partly offset such losses.
OTHER MATTERS
YEAR 2000 READINESS DISCLOSURE
On or about midnight on December 31, 1999, digital computing systems may
begin to produce erroneous results or fail, unless these systems are modified
or replaced, because such systems may be programmed incorrectly and interpret
the date of January 1, 2000 as being January 1st of the year 1900 or another
incorrect date. In addition, certain systems may fail to detect that the year
2000 is a leap year. Problems can also arise earlier than January 1, 2000, as
dates in the next millennium are entered into non-Year 2000 ready programs.
READINESS PROGRAM - Internally, the Company is modifying or replacing its
computer hardware and software programs to minimize Year 2000-related
failures and repair such failures if they occur. This includes both
information technology systems (IT), which are mainframe and client server
applications, and embedded logic systems (non-IT), such as process controls
for energy production and delivery. Externally, the problem is being
addressed with entities that interact with the Company, including suppliers,
customers, creditors, financial service organizations and other parties
essential to the Company's operations. In the course of the external
evaluation, the Company has sought written assurances from third parties
regarding their state of Year 2000 readiness.
Another issue we are addressing is the impact of electric power grid
problems that may occur outside of our transmission system. AEP, along with
other electric utilities in North America, regularly submits information to
the North American Electric Reliability Council (NERC) as part of NERC's Year
2000 readiness program. NERC then publicly reports summary information to the
U.S.
20
<PAGE>
Department of Energy (DOE) regarding the Year 2000 readiness of electric
utilities. In 1999 AEP plans to participate in two NERC-sponsored coordinated
electric industry Year 2000 readiness drills.
The second NERC report, dated January 11, 1999 and entitled: PREPARING
THE ELECTRIC POWER SYSTEMS OF NORTH AMERICAN FOR TRANSITION TO THE YEAR 2000
- - A STATUS REPORT AND WORK PLAN, FOURTH QUARTER 1998, states that: "With more
than 44% of mission critical components tested through November 30, 1998,
findings continue to indicate that transition through critical Year 2000
(Y2K) rollover dates is expected to have minimal impact on electric system
operations in North America." The Company continues to set a target date of
June 30, 1999 for having all mission critical and high priority systems and
components Y2K ready.
Through the Electric Power Research Institute, an electric industry-wide
effort has been established to deal with Year 2000 problems affecting
embedded systems. Under this effort, participating utilities, including AEP,
are working together to assess specific vendors' system problems and test
plans.
The state regulatory commissions in the Company's service territory are
also reviewing the Year 2000 readiness of the Company.
COMPANY'S STATE OF READINESS - Work has been prioritized in accordance
with business risk. The highest priority has been assigned to activities that
potentially affect safety, the physical generation and delivery of energy and
communications; followed by back office activities such as customer
service/billing, regulatory reporting, internal reporting and administrative
activities (e.g. payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in normal
business operations.
The following chart shows our progress toward becoming ready for the Year
2000 as of December 31, 1998:
<TABLE>
<CAPTION>
IT SYSTEMS NON-IT SYSTEMS
COMPLETION COMPLETION
DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE
- ------------------------
<S> <C> <C> <C> <C>
LAUNCH: Initiation of 2/24/1998 100% 5/31/1998 100%
the Year 2000
activities within
the organization.
Establishment of
organizational
structure, personnel
assignments and budget
for the workgroup.
Continuous management
update and awareness
program.
INVENTORY AND ASSESSMENT: 7/31/1998 100% 2/15/1999 99%
Identifying all Company
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.
REMEDIATION/TESTING: The 6/30/1999 Mainframe 6/30/1999 37%
process of modifying, 70%
replacing or retiring
those mission critical and ---------
high priority digital-based Client
systems with problems Server:
processing dates past the 18%
Year 2000. Testing these
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been
maintained.
</TABLE>
21
<PAGE>
The above chart does not reflect progress of recently acquired midstream
gas operations and CitiPower. The mission critical systems for the midstream
gas operations are expected to be ready by June 30, 1999 and the mission
critical systems for CitiPower are expected to be ready by October 1, 1999.
COSTS TO ADDRESS THE COMPANY'S YEAR 2000 ISSUES - Through December 31,
1998, the Company has spent $21 million on the Year 2000 project and
estimates spending an additional $35 million to $47 million to achieve Year
2000 readiness. Most Year 2000 costs are for software, IT consultants and
salaries and are expensed; however, in certain cases the Company has acquired
hardware that was capitalized. The Company intends to fund these expenditures
through internal sources. Although significant, the cost of becoming Year
2000 compliant is not expected to have a material impact on the Company's
results of operations, cash flows or financial condition.
RISKS OF THE COMPANY'S YEAR 2000 ISSUES - The applications posing the
greatest business risk to the Company's operations should they experience Y2K
problems are:
* Automated power generation, transmission and distribution systems
* Telecommunications systems
* Energy trading systems
* Time-in-use, demand and remote metering systems for
commercial and industrial customers
* Work management and billing systems.
The potential problems related to erroneous processing by, or failure of,
these systems are:
* Power service interruptions to customers
* Interrupted revenue data gathering and collection
* Poor customer relations resulting from delayed billing and
settlement.
CitiPower operates under a legal and regulatory regime which may expose
it to customer claims, that may differ from claims under the US legal and
regulatory regime, for service interruptions and/or power quality problems
resulting from Y2K problems.
In addition, although as discussed the Company is monitoring its
relationships with third parties, such as suppliers, customers and other
electric utilities, these third parties nonetheless represent a risk that
cannot be assessed with precision or controlled with certainty.
Due to the complexity of the problem and the interdependent nature of
computer systems, if our corrective actions, and/or the actions of others not
affiliated with AEP, fail for critical applications, Year 2000-related issues
may materially adversely affect AEP.
COMPANY'S CONTINGENCY PLANS - To address possible failures of electric
generation and delivery of electrical energy due to Year 2000 related
failures, we have established a draft Year 2000 contingency plan and
submitted it to the East Central Area Reliability Council (ECAR) in December
1998 as part of NERC's review of regional and individual electric utility
contingency plans in 1999. NERC's target date is June 1999 for the completion
of this contingency plan. In addition, the Company intends to establish
contingency plans for its business units to address alternatives if Year 2000
related failures occur. AEP's
22
<PAGE>
contingency plans will be developed by the end of 1999. AEP's plans build
upon the disaster recovery, system restoration, and contingency planning that
we have had in place.
NEW ACCOUNTING STANDARDS
In 1997 the FASB issued SFAS 130 "Reporting Comprehensive Income" and
SFAS No. 131 "Disclosures About Segments of an Enterprise and Related
Information." SFAS 130 establishes the standards for reporting and displaying
components of "comprehensive income," which is the total of net income and
all transactions not included in net income affecting equity except those
with shareholders. The Company adopted SFAS 130 in the first quarter of 1998.
For 1998 there were no material differences between net income and
comprehensive income.
SFAS 131 initiates reporting standards for annual and interim financial
statements about operating segments of a business for which separate
financial information is available and regularly evaluated by the chief
operating decision maker in allocating resources and reviewing performance.
Information about products and services and geographic areas is to be
reported at an enterprise-level instead of by segment. SFAS 131 was required
to be adopted by the Company for the year ended December 31, 1998 with
restatement of prior period comparative information. Adoption of SFAS 131 did
not have any effect on results of operations, cash flows or financial
condition.
In the first quarter of 1998 the Company adopted the American Institute
of Certified Public Accountants' (AICPA) Statement of Position (SOP) 98-1,
"Accounting for the Costs of Computer Software Developed or Obtained for
Internal Use". The SOP requires the capitalization and amortization of
certain costs of acquiring or developing internal use computer software.
Previously the Company expensed all software acquisition and development
costs. The SOP had to be adopted at the beginning of a fiscal year with no
restatement or retroactive adjustment of prior periods. The adoption of the
SOP effective January 1, 1998 did not have a material effect on results of
operations, cash flows or financial condition.
In February 1998, the FASB issued SFAS 132 "Employers' Disclosure about
Pensions and Other Postretirement Benefits" which revised employers'
disclosures about pensions and other postretirement benefit plans and
suggested that the disclosure be combined. It did not change the measurement
or recognition requirements for postretirement benefit accounting. The
adoption of SFAS 132 did not have a material effect on results of operations,
cash flows or financial condition. Prior periods were restated to comply with
SFAS 132 presentation requirements.
EITF 98-10 "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" was issued in November 1998 to address the application
of mark-to-market accounting for energy trading contracts. Under the
provisions of this standard, which must be adopted by the Company in January
1999, energy trading contracts can no longer be accounted for on a settlement
basis. Instead they are to be marked-to-market. Adoption of EITF 98-10 is not
expected to have a significant impact on results of operations, cash flows or
financial condition.
The FASB issued SFAS 133 "Accounting for Derivative Instruments and
Hedging Activities" in June 1998.
23
<PAGE>
SFAS 133 establishes accounting and reporting standards for derivative
instruments. It requires that all derivatives be recognized as either an
asset or a liability and measured at fair value in the financial statements.
If certain conditions are met a derivative may be designated as a hedge of
possible changes in fair value of an asset, liability or firm commitment;
variable cash flows of forecasted transactions; or foreign currency exposure.
The accounting/reporting for changes in a derivative's fair value (gains and
losses) depend on the intended use and resulting designation of the
derivative. Management is currently studying the provisions of SFAS 133 to
determine the impact of its adoption on January 1, 2000 on results of
operations, cash flows and financial condition.
In April 1998 the AICPA issued SOP 98-5 "Reporting on the Costs of
Start-up Activities". The SOP clarifies the accounting and reporting for one
time start-up activities and organization costs, requiring that they be
expensed as incurred. The adoption of this standard in January 1999 is not
expected to have a material effect on results of operations, cash flows or
financial condition.
LITIGATION
CORPORATE OWNED LIFE INSURANCE
The Internal Revenue Service (IRS) agents auditing the AEP System's
consolidated federal income tax returns requested a ruling from their
National Office that certain interest deductions claimed by the Company
relating to AEP's corporate owned life insurance (COLI) program should not be
allowed. As a result of a suit filed by AEP in United States District Court
(discussed below) this request for ruling was withdrawn by the IRS agents.
Adjustments have been or will be proposed by the IRS disallowing COLI
interest deductions for taxable years 1991-96. A disallowance of the COLI
interest deductions through December 31, 1998 would reduce earnings by
approximately $316 million (including interest). The Company has made no
provision for any possible adverse earnings impact from this matter.
In 1998 the Company made payments of taxes and interest attributable to
COLI interest deductions for taxable years 1991-97 to avoid the potential
assessment by the IRS of any additional above market rate interest on the
contested amount. The payments to the IRS are included on the balance sheet
in other property and investments pending the resolution of this matter. The
Company will seek refund, either administratively or through litigation, of
all amounts paid plus interest. In order to resolve this issue without
further delay, on March 24, 1998, the Company filed suit against the United
States in the United States District Court for the Southern District of Ohio.
Management believes that it has a meritorious position and will vigorously
pursue this lawsuit. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results of operations,
cash flows and possibly financial condition.
AEP is involved in a number of other 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, cash flows and/or financial condition.
24
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands - except per share amounts)
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
OPERATING REVENUES $6,345,902 $5,879,820 $5,849,234
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 1,717,177 1,627,066 1,600,659
Purchased Power 436,388 134,718 86,095
Other Operation 1,303,084 1,227,368 1,210,027
Maintenance 542,935 483,268 502,841
Depreciation and Amortization 579,997 591,071 600,851
Taxes Other Than Federal Income Taxes 493,386 490,595 498,567
Federal Income Taxes 316,201 341,280 342,222
---------- ---------- ----------
TOTAL OPERATING EXPENSES 5,389,168 4,895,366 4,841,262
---------- ---------- ----------
OPERATING INCOME 956,734 984,454 1,007,972
NONOPERATING INCOME (net) 9,463 59,572 2,212
---------- ---------- ----------
INCOME BEFORE INTEREST CHARGES AND
PREFERRED DIVIDENDS 966,197 1,044,026 1,010,184
INTEREST CHARGES 419,088 405,815 381,328
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES 10,926 17,831 41,426
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 536,183 620,380 587,430
EXTRAORDINARY LOSS - UK WINDFALL TAX - (109,419) -
---------- ---------- ----------
NET INCOME $ 536,183 $ 510,961 $ 587,430
---------- ---------- ----------
---------- ---------- ----------
AVERAGE NUMBER OF SHARES OUTSTANDING 190,774 189,039 187,321
---------- ---------- ----------
---------- ---------- ----------
EARNINGS PER SHARE:
Before Extraordinary Item $2.81 $3.28 $3.14
Extraordinary Loss - (0.58) -
---------- ---------- ----------
Net Income $2.81 $2.70 $3.14
---------- ---------- ----------
---------- ---------- ----------
CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
----------------------------------------------------
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(in thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
RETAINED EARNINGS JANUARY 1 $1,605,017 $1,547,746 $1,409,645
NET INCOME 536,183 510,961 587,430
DEDUCTIONS:
Cash Dividends Declared 457,638 453,453 449,353
Other 1 237 (24)
---------- ---------- ----------
RETAINED EARNINGS DECEMBER 31 $1,683,561 $1,605,017 $1,547,746
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
See Notes to Consolidated Financial Statements.
25
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(in thousands - except share data)
<TABLE>
<CAPTION>
December 31,
----------------------------
1998 1997
---- ----
<S> <C> <C>
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 9,591,211 $ 9,493,158
Transmission 3,570,717 3,501,580
Distribution 4,779,772 4,654,234
General (including mining assets and nuclear fuel) 1,641,676 1,604,671
Construction Work in Progress 562,891 342,842
----------- -----------
Total Electric Utility Plant 20,146,267 19,596,485
Accumulated Depreciation and Amortization 8,416,397 7,963,636
----------- -----------
NET ELECTRIC UTILITY PLANT 11,729,870 11,632,849
----------- -----------
OTHER PLANT 841,451 62,213
----------- -----------
OTHER PROPERTY AND INVESTMENTS 2,515,103 1,294,291
----------- -----------
CURRENT ASSETS:
Cash and Cash Equivalents 172,985 91,481
Accounts Receivable:
Customers 557,382 559,203
Miscellaneous 360,783 115,075
Allowance for Uncollectible Accounts (11,075) (6,760)
Fuel - at average cost 215,699 224,967
Materials and Supplies - at average cost 279,823 263,613
Accrued Utility Revenues 186,006 189,191
Energy Marketing and Trading Contracts 372,380 2,306
Prepayments and Other 83,686 81,366
----------- -----------
TOTAL CURRENT ASSETS 2,217,669 1,520,442
----------- -----------
REGULATORY ASSETS 1,846,718 1,817,540
----------- -----------
DEFERRED CHARGES 332,391 288,011
----------- -----------
TOTAL $19,483,202 $16,615,346
----------- -----------
----------- -----------
</TABLE>
See Notes to Consolidated Financial Statements.
26
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31,
--------------------------
1998 1997
---- ----
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock-Par Value $6.50:
1998 1997
---- ----
Shares Authorized. .600,000,000 300,000,000
Shares Issued. . . .200,816,469 198,989,981
(8,999,992 shares were held in treasury) $ 1,305,307 $ 1,293,435
Paid-in Capital 1,852,912 1,778,782
Retained Earnings 1,683,561 1,605,017
----------- -----------
Total Common Shareholders' Equity 4,841,780 4,677,234
Cumulative Preferred Stocks of Subsidiaries:*
Not Subject to Mandatory Redemption 46,002 46,724
Subject to Mandatory Redemption 127,605 127,605
Long-term Debt* 6,799,641 5,129,463
----------- -----------
TOTAL CAPITALIZATION 11,815,028 9,981,026
----------- -----------
OTHER NONCURRENT LIABILITIES 1,428,968 1,246,537
----------- -----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year* 206,476 294,454
Short-term Debt 616,604 555,075
Accounts Payable 618,019 353,256
Taxes Accrued 381,905 380,771
Interest Accrued 75,184 76,361
Obligations Under Capital Leases 81,661 101,089
Energy Marketing and Trading Contracts 360,248 1,983
Other 461,540 322,687
----------- -----------
TOTAL CURRENT LIABILITIES 2,801,637 2,085,676
----------- -----------
DEFERRED INCOME TAXES 2,601,402 2,560,921
----------- -----------
DEFERRED INVESTMENT TAX CREDITS 350,946 376,250
----------- -----------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 222,042 231,320
----------- -----------
DEFERRED CREDITS 263,179 133,616
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 4)
TOTAL $19,483,202 $16,615,346
----------- -----------
----------- -----------
</TABLE>
* See Accompanying Schedules.
27
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net Income $ 536,183 $ 510,961 $ 587,430
Adjustments for Noncash Items:
Depreciation and Amortization 619,557 608,217 590,657
Deferred Federal Income Taxes 41,449 (6,549) (21,478)
Deferred Investment Tax Credits (25,304) (25,241) (25,808)
Amortization of Operating Expenses
and Carrying Charges (net) 14,786 12,001 55,458
Equity in Earnings of Yorkshire
Electricity Group plc (38,459) (33,780) -
Extraordinary Item - UK Windfall Tax - 109,419 -
Deferred Costs Under Fuel Clause Mechanisms (73,219) (52,469) 51
Changes in Certain Current Assets
and Liabilities:
Accounts Receivable (net) (141,637) (136,186) (39,049)
Fuel, Materials and Supplies 2,108 (1,427) 35,831
Accrued Utility Revenues 3,185 (14,225) 32,953
Accounts Payable 200,195 147,029 (13,915)
Taxes Accrued (826) (33,402) (6,019)
Payment of Disputed Tax and Interest
Related to COLI (302,739) (3,080) -
Other (net) 194,247 116,654 40,951
---------- ----------- ----------
Net Cash Flows From Operating Activities 1,029,526 1,197,922 1,237,062
---------- ----------- ----------
INVESTING ACTIVITIES:
Construction Expenditures (792,118) (760,394) (577,691)
Investment in Yorkshire Electricity Group plc - (363,436) -
Investment in CitiPower (1,054,081) - -
Investment in Gas Assets (340,131) - -
Other (26,370) 2,142 12,283
---------- ----------- ----------
Net Cash Flows Used For
Investing Activities (2,212,700) (1,121,688) (565,408)
---------- ----------- ----------
FINANCING ACTIVITIES:
Issuance of Common Stock 85,515 76,745 65,461
Issuance of Long-term Debt 2,491,113 880,522 407,291
Retirement of Cumulative Preferred Stock (547) (433,329) (70,761)
Retirement of Long-term Debt (915,294) (348,157) (601,278)
Change in Short-term Debt (net) 61,529 235,380 (45,430)
Dividends Paid on Common Stock (457,638) (453,453) (449,353)
---------- ----------- ----------
Net Cash Flows From (Used For)
Financing Activities 1,264,678 (42,292) (694,070)
---------- ----------- ----------
Net Increase (Decrease) in Cash and
Cash Equivalents 81,504 33,942 (22,416)
Cash and Cash Equivalents January 1 91,481 57,539 79,955
---------- ----------- ----------
Cash and Cash Equivalents December 31 $ 172,985 $ 91,481 $ 57,539
---------- ----------- ----------
---------- ----------- ----------
</TABLE>
See Notes to Consolidated Financial Statements.
28
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Organization - American Electric Power (AEP or the Company) is one of the
United States' (US) largest investor-owned public utility holding companies
engaged in the generation, purchase, transmission and distribution of
electric power to 3 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 and power marketers. AEP also has
other energy holdings in the US, the United Kingdom (UK), China and Australia.
The organization of AEP consists of American Electric Power Company, Inc.
(AEP Co., Inc.), the parent holding company; seven domestic regulated
electric utility operating companies (domestic utility subsidiaries); a
domestic generating subsidiary, AEP Generating Company (AEGCo); three active
coal-mining companies; a service company, American Electric Power Service
Corporation (AEPSC); AEP Resources, Inc. (AEPR) which invests in, owns and
operates non-regulated energy-related domestic and international projects;
AEP Energy Services, Inc. (AEPES) which markets and trades energy
commodities; and other subsidiaries that provide non-regulated energy and
communication services.
The following domestic utility subsidiaries pool their generating and
transmission facilities and operate them as an integrated system: Appalachian
Power Company (APCo), Columbus Southern Power Company (CSPCo), Indiana
Michigan Power Company (I&M), Kentucky Power Company (KPCo) and Ohio Power
Company (OPCo). The remaining two domestic utility subsidiaries, Kingsport
Power Company (KGPCo) and Wheeling Power Company (WPCo) are distribution
companies that purchase power from APCo and OPCo, respectively. AEPSC
provides management and professional services to the AEP System subsidiaries.
The active coal-mining companies are wholly-owned by OPCo and sell most of
their production to OPCo. AEGCo 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. AEPR owns 50% of Yorkshire Electricity Group plc
(Yorkshire), a supply and distribution electric company in the UK (see Note
7); 70% of a joint venture which is constructing a two-unit power plant
nearing completion in China; 20% of Pacific Hydro, an Australian
hydroelectric generating company; all of the assets of a midstream natural
gas operation in Louisiana and 100% of CitiPower, a Melbourne, Australia
distribution utility. The acquisitions of the midstream natural gas assets
and CitiPower were completed in December 1998 (see Note 6). AEPES currently
markets and trades natural gas. The non-regulated subsidiaries are engaged in
providing power engineering, consulting and management services around the
world and fiber, wireless and information communication services in the US.
Although the domestic utility subsidiaries are managed centrally by AEPSC and
operate as American Electric Power they and AEPSC have not changed their
names and remain separate legal entities.
RATE REGULATION - The AEP System is subject to regulation by the Securities
and Exchange Commission (SEC) under the Public Utility Holding Company Act of
29
<PAGE>
1935 (1935 Act). The rates charged by the domestic utility subsidiaries are
approved by the Federal Energy Regulatory Commission (FERC) or 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
AEP Co., Inc. and its wholly-owned and majority-owned subsidiaries
consolidated with their wholly-owned subsidiaries. Significant intercompany
items are eliminated in consolidation. Yorkshire and Pacific Hydro are
accounted for using the equity method.
BASIS OF ACCOUNTING - As the owner of cost-based rate-regulated electric
public utility companies, AEP Co., 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) 71, "Accounting for the Effects of Certain Types of Regulation,"
regulatory assets (deferred expenses) and regulatory liabilities (deferred
income) are recorded to reflect the economic effects of regulation and to
match expenses with regulated revenues.
USE OF ESTIMATES - The preparation of these financial statements in
conformity with generally accepted accounting principles requires in certain
instances the use of estimates. Actual results could differ from those
estimates.
REGULATED UTILITY PLANT - Electric utility plant, which represents the costs
of service rate-regulated fixed assets of the domestic electric utility
subsidiaries, 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
regulated domestic utility plant are included in operating expenses. The
distribution utility plant assets of CitiPower are included in other plant.
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 amounts of AFUDC for
1998, 1997 and 1996 were not significant.
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. The annual composite depreciation rates for
regulated utility plant for 1998, 1997 and 1996 were as follows:
<TABLE>
<CAPTION>
Functional Class Annual Composite
of Property Depreciation Rates
- ----------------- ------------------
<S> <C>
Production:
Steam-Nuclear 3.4%
Steam-Fossil-Fired 3.2% to 4.4%
Hydroelectric-Conventional
and Pumped Storage 2.7% to 3.4%
Transmission 1.7% to 2.7%
Distribution 3.3% to 4.2%
General 2.5% to 3.8%
</TABLE>
The domestic utility subsidiaries presently recover amounts to be used for
demolition and removal 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
30
<PAGE>
useful life or the estimated life of the mine, whichever is shorter, 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 to amortize
coal rights and mine development costs based on estimated recoverable
tonnages at a current average rate of $1.85 per ton in 1998, $1.91 per ton in
1997 and $1.49 per ton in 1996. 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.
FOREIGN CURRENCY TRANSLATION - The financial statements of subsidiaries
outside the US are measured using the local currency as the functional
currency. Assets and liabilities are translated to US dollars at year-end
rates of exchange and revenues and expenses are translated at monthly average
exchange rates throughout the year. Currency translation gain and loss
adjustments are accumulated in shareholders' equity. The accumulated total of
such adjustments at December 31, 1998 and 1997 is not material. Currency
transaction gains and losses are recorded in income.
DERIVATIVE FINANCIAL INSTRUMENTS - During 1998, the Company substantially
increased the volume of its wholesale electricity and natural gas marketing
and trading transactions (trading activities). Trading activities involve the
sale of energy under physical forward contracts at fixed and variable prices
and the trading of energy contracts including exchange traded futures and
options, over-the-counter options and swaps. The majority of these
transactions represent physical forward contracts in the Company's
traditional marketing area and are typically settled by entering into
offsetting contracts. The net revenues from these transactions in the
Company's traditional economic marketing area are included in regulated
revenues for ratemaking, regulatory accounting and reporting purposes.
The Company has also purchased and sold electricity and gas options, futures
and swaps, and entered into forward purchase and sale contracts for
electricity outside its traditional marketing area. These transactions
represent non-regulated trading activities that are included in nonoperating
income. The unrealized mark-to-market gains and losses from such
non-regulated trading activity are reported as assets and liabilities,
respectively.
The Company enters into contracts to manage the exposure to unfavorable
changes in the cost of debt to be issued. These anticipatory debt instruments
are entered into in order to manage the change in interest rates between the
time a debt offering is initiated and the issuance of the debt (usually a
period of 60 days). Gains or losses are deferred and amortized over the life
of the debt issuance. There were no such forward contracts outstanding at
December 31, 1998 or 1997.
See Note 11 - Financial Instruments, Credit and Risk Management for further
discussion.
OPERATING REVENUES AND FUEL COSTS - Revenues include the accrual of
electricity consumed but unbilled at month-end as well as billed revenues.
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 or refund to customers in later months. Wholesale jurisdictional fuel
cost
31
<PAGE>
changes are expensed and billed as incurred.
LEVELIZATION OF NUCLEAR REFUELING OUTAGE COSTS - In accordance with SFAS 71
incremental operation and maintenance costs associated with refueling outages
at I&M's Cook Plant are deferred and amortized over the period beginning with
the commencement of an outage and ending with 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 the 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, deferred
income taxes are recorded with related regulatory assets and liabilities 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 reacquisition of 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.
Discount or premium and expenses of debt issuances are amortized over the
term of the related debt, with the amortization included in interest charges.
Redemption premiums paid to reacquire preferred stock are included in paid-in
capital and amortized to retained earnings commensurate with their recovery
in rates. The excess of par value over costs of preferred stock reacquired is
credited to paid-in capital and amortized to retained earnings.
OTHER PLANT - Other plant is comprised primarily of the plant and its related
construction work in progress for midstream gas operations, an Australian
distribution company and a Chinese generation project.
OTHER PROPERTY AND INVESTMENTS - Other property and investments are comprised
primarily of nuclear decommissioning and spent nuclear fuel disposal trust
funds; licenses for operating franchises and goodwill for the Australian
distribution company; amounts for corporate owned life insurance and a
related disputed tax payment; and the investment in Yorkshire and Pacific
Hydro which are accounted for under the equity method of accounting.
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 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. Unrealized gains and
losses from securities in these trust funds are not reported in equity but
result in adjustments to the liability account for the nuclear
decommissioning trust funds and to regulatory assets or liabilities for the
spent nuclear fuel disposal trust funds. Excluding decommissioning and spent
nuclear fuel disposal trust funds and the
32
<PAGE>
investment in Yorkshire and Pacific Hydro, other property and investments are
stated at cost.
EPS - Earnings per share is determined based upon the weighted average number
of shares outstanding. There are no dilutive potential common shares.
Therefore, the computation of earnings per share is the same for basic
earnings per share and diluted earnings per share.
COMPREHENSIVE INCOME - There were no material differences between net income
and comprehensive income.
RECLASSIFICATION - In the fourth quarter of 1998 the Company changed the
presentation of its trading activities from a gross basis (purchases and
sales reported separately) to a net basis (net amount from transactions
reported as revenues). This reclassification had no impact on net income.
Certain prior year amounts have been reclassified to conform to current year
presentation. Such reclassification had no impact on previously reported net
income.
2. RATE MATTERS:
OPCO'S 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. A 1995 Settlement Agreement set the fuel
component of the electric fuel component (EFC) factor at 1.465 cents per Kwh
for the period June 1, 1995 through November 30, 1998. With the end of the
period covered by the 1995 Settlement Agreement, the escalated Gavin
predetermined price cap under the stipulation agreement will determine Ohio
jurisdictional fuel recoveries. To the extent the actual cost of coal burned
at the Gavin Plant is below the predetermined prices, the stipulation
agreement provides OPCo with the opportunity to recover over its term the
Ohio jurisdictional share of OPCo's investment in and the liabilities and
future shut-down costs of its affiliated mines as well as any fuel costs
incurred above the predetermined rate. The Company announced plans to close
the Muskingum mine which supplies all of its output to OPCo. The mine will be
closed in October 1999 and efforts will begin to reclaim the properties, sell
or scrap all mining equipment, terminate both capital and operating leases
and perform other miscellaneous activities necessary to shut down the mine.
Reclamation activities should be completed approximately two years after
shutdown, postremediation monitoring is anticipated to continue for five
years after completion of reclamation. The Company established a liability
for mine closing costs of $44.6 million comprised of a curtailment loss of
$24.7 million, provisions for workers compensation claims incurred through
October 1998 of $4.7 million, severance costs of $4.1 million (related to
approximately 200 employees), postremediation monitoring costs of $4.9
million, write-off of remaining materials and supplies of $4.6 million and
other mine site closure costs of $1.6 million. Pursuant to terms of the
agreements, $18.5 million of these accrued mine closure costs have been
deferred for the Muskingum mine, the remainder are included in fuel expense
on the Consolidated Statements of Income. For the three years ended December
31, 1998, 1997 and 1996 revenues and net income from the Muskingum mining
operation were $110.2 million and $1,000; $66.3 million and zero; and $65.5
million and $1.8 million; respectively. After full recovery of the deferrals
or after November 2009, whichever comes first, the price that OPCo can
recover for coal from its affiliated Meigs mine which supplies the
33
<PAGE>
Gavin Plant will be limited to the lower of cost or market price at the time.
Pursuant to these agreements OPCo has deferred for future recovery $106
million at December 31, 1998.
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 including
deferred amounts will be recovered under the terms of the predetermined price
agreement. Management intends to seek from non-Ohio jurisdictional 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 $100
million after tax at December 31, 1998.
Management anticipates closing the Windsor mine in December 2000 in order to
comply with the Phase II requirements of the Clean Air Act Amendments of 1990
(CAAA) or it could close earlier depending on the economics of continued
operation under the terms of the above stipulation agreement. Unless the cost
of affiliated coal production and/or shutdown costs of the Meigs, Muskingum
and Windsor mines can be recovered, results of operations, cash flows and
possibly financial condition would be adversely affected.
3. EFFECTS OF REGULATION AND PHASE-IN PLANS:
In accordance with SFAS 71 the consolidated financial statements include
assets (deferred expenses) and liabilities (deferred income) recorded in
accordance with regulatory actions to match expenses and revenues from
cost-based rates. Regulatory assets are expected to be recovered in future
periods through the rate-making process and regulatory liabilities are
expected to reduce future cost recoveries. Management has reviewed 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, net regulatory assets would have
to be written off for that portion of the business and assets attributable to
that portion of the business would have to be tested for possible impairment
and if required an impairment loss recorded unless the net regulatory assets
and impairment losses are recoverable as a stranded cost.
Recognized regulatory assets and liabilities are comprised of the following
at:
<TABLE>
<CAPTION>
December 31,
---------------------------
1998 1997
---- ----
(in thousands)
<S> <C> <C>
Regulatory Assets:
Amounts Due From Customers For
Future Income Taxes $1,324,217 $1,372,926
Deferred Fuel Costs 193,430 75,552
Unamortized Loss on Reacquired Debt 90,997 96,793
Other 238,074 272,269
---------- ----------
Total Regulatory Assets $1,846,718 $1,817,540
---------- ----------
---------- ----------
Regulatory Liabilities:
Deferred Investment Tax Credits $350,946 $376,250
Other Regulatory Liabilities* 147,569 78,802
---------- ----------
Total Regulatory Liabilities $498,515 $455,052
---------- ----------
---------- ----------
</TABLE>
* Included in Deferred Credits on Consolidated Balance Sheets
At January 1, 1997 rate phase-in plan deferrals existed for the Zimmer Plant
and 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. As a result of an
Ohio Supreme Court decision, in January 1994 the PUCO approved a temporary
3.39% surcharge effective February 1, 1994. In June 1997 the Company
34
<PAGE>
completed recovery of its Zimmer Plant phase-in plan deferrals and
discontinued the 3.39% temporary rate surcharge. In 1997 and 1996 $15.4
million and $31.5 million, respectively, of net phase-in deferrals were
collected through the surcharge.
The Rockport Plant consists of two 1,300 mw coal-fired units. I&M and AEGCo
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 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 the Indiana and the FERC jurisdictions provided
for the recovery and straight-line amortization of deferred Rockport Plant
Unit 1 costs over a ten year period that ended in 1997. In 1997 and 1996
amortization and recovery of the deferred Rockport Plant Unit 1 phase-in plan
costs were $11.9 million and $15.6 million, respectively. During the recovery
period net income was unaffected by the recovery of the phase-in deferrals.
4. COMMITMENTS AND CONTINGENCIES:
CONSTRUCTION AND OTHER COMMITMENTS - The AEP System has substantial
construction commitments to support its utility operations including the
replacement of the Cook Plant Unit 1 steam generators. Such commitments do
not presently include any expenditures for new generating capacity. Aggregate
construction expenditures for 1999-2001 are estimated to be $2.4 billion
including construction cost estimates for the newly acquired CitiPower and
midstream gas assets.
Long-term domestic fuel supply contracts contain clauses for periodic price
adjustments, and most domestic 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 extends 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 approximately 1,100 mw of capacity
domestically on a long-term basis to unaffiliated utilities. Certain
contracts totaling 750 mw of capacity are unit power agreements requiring the
delivery of energy only if the unit capacity is available. The power sales
contracts expire from 1999 to 2010.
NUCLEAR PLANT - I&M owns and operates the two-unit 2,110 mw Cook Plant under
licenses granted by the Nuclear Regulatory Commission (NRC). 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 US, 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 in rates is not
possible, results of operations, cash flows and financial condition could be
negatively affected.
NUCLEAR PLANT SHUTDOWN - I&M shut down both units of the Cook Nuclear Plant
in September 1997 due to questions, which arose during a NRC architect
engineer design inspection, regarding the operability of certain safety
systems. The NRC issued a Confirmatory Action Letter
35
<PAGE>
in September 1997 requiring I&M to address the issues identified in the
letter. I&M is working with the NRC to resolve the remaining open issue in
the letter.
In April 1998 the NRC notified I&M that it had convened a Restart Panel for
Cook Plant. A list of required restart activities was provided by the NRC in
July 1998 and in October the NRC expanded the list. In order to identify and
resolve the issues necessary to restart the Cook units, I&M is and will be
meeting with the Panel on a regular basis, until the units are returned to
service.
In January 1999 I&M announced that it will conduct additional engineering
reviews at the Cook Plant that will delay restart of the units. Previously,
the units were scheduled to return to service at the end of the first and
second quarters of 1999. The decision to delay restart resulted from internal
assessments that indicated a need to conduct expanded system readiness
reviews. A new restart schedule will be developed based on the results of the
expanded reviews and should be available in June 1999. When maintenance and
other activities required for restart are complete, I&M will seek concurrence
from the NRC to return the Cook Plant to service. Until these additional
reviews are completed, management is unable to determine when the units will
be returned to service. Unless the costs of the extended outage and restart
efforts are recovered from customers, there would be a material adverse
effect on results of operations, cash flows and possibly financial condition.
The incremental cost incurred in 1997 and 1998 for restart of the Cook units
were $6 million and $78 million, respectively, and recorded as operation and
maintenance expense. Currently incremental restart expenses are approximately
$12 million a month.
In July 1998 I&M received an "adverse trend letter" from the NRC indicating
that NRC senior managers determined that there had been a slow decline in
performance at the Cook Plant during the 18 month period preceding the
letter. The letter indicated that the NRC will closely monitor efforts to
address issues at Cook Plant through additional inspection activities. In
October 1998 the NRC issued I&M a Notice of Violation and proposed a $500,000
civil penalty for alleged violations at the Cook Plant discovered during five
inspections conducted between August 1997 and April 1998. I&M paid the
penalty.
The cost of electricity supplied to certain retail customers rose due to the
outage of the two units since higher cost coal-fired generation and coal
based purchased power were substituted for low cost nuclear generation. I&M's
Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms
permit the recovery, subject to regulatory commission review and approval, of
changes in fuel costs including the fuel component of purchased power in the
Indiana jurisdiction and changes in replacement power in the Michigan
jurisdiction. The Indiana Utility Regulatory Commission approved, subject to
future reconciliation or refund, agreements authorizing I&M, during the
billing months of July 1998 through March 1999, to include in rates a fuel
cost adjustment factor less than that requested by I&M. The agreements
provide the parties to the proceedings with the opportunity to conduct
discovery regarding certain issues that were raised in the proceedings,
including the appropriateness of the recovery of replacement energy cost due
to the extended Cook Plant outage, in anticipation of resolving the issues in
a future fuel cost adjustment proceeding. A regulatory asset in the amount of
$65 million has been recorded at December 31, 1998.
36
<PAGE>
Historically, the Company has been permitted to recover through the fuel
recovery mechanism the cost of replacement energy during outages. Management
believes that it should be allowed to recover the deferred Cook replacement
energy costs; however, if recovery of the replacement costs is denied, future
results of operations and cash flows would be adversely affected by the
writeoff of the regulatory asset.
NUCLEAR INCIDENT LIABILITY - Public liability is limited by law to $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 US the remainder of
the liability would be provided by a deferred premium assessment of $88
million on each licensed reactor payable in annual installments of $10
million. As a result, I&M could be assessed $176 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 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 unaffiliated nuclear units. I&M could be assessed up to $23.2
million annually under these policies.
SPENT NUCLEAR FUEL (SNF) DISPOSAL - Federal law provides for government
responsibility for permanent SNF disposal and assesses nuclear plant owners
fees for SNF disposal. A fee of one mill per kilowatthour for fuel consumed
after April 6, 1983 is being collected from customers and remitted to the US
Treasury. Fees and related interest of $190 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 continued delays and uncertainties
related to the federal disposal program. At December 31, 1998, funds
collected from customers towards payment of the pre-April 1983 fee and
related earnings thereon approximate 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 ranges from $700 million
to $1,152 million in 1997 nondiscounted dollars. The wide range is caused by
variables in assumptions including the estimated length of time SNF may need
to be stored at the plant site subsequent to ceasing operations. This, in
turn, depends on future developments in the federal government's SNF 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 an increase in its noncurrent liabilities equal to the
decommissioning cost recovered in rates; such amounts were $29 million in
1998,
37
<PAGE>
$28 million in 1997 and $27 million in 1996. Decommissioning costs recovered
from customers are deposited in external trusts. Trust fund earnings increase
the fund assets and the recorded liability and decrease the amount needed to
be recovered from ratepayers. During 1998 I&M withdrew $3 million and expects
to withdrawal $8 million in 1999 for decommissioning of original steam
generators removed from Unit 2. At December 31, 1998 and 1997, I&M has
recognized a decommissioning liability of $446 million and $381 million,
respectively, which is included in other noncurrent liabilities.
CLEAN AIR ACT/AIR QUALITY - The US Environmental Protection Agency (Federal
EPA) is required by the CAAA to issue rules to implement the law. In 1996
Federal EPA issued final rules governing nitrogen oxides (NOx) emissions that
must be met after January 1, 2000 (Phase II of CAAA). The final rules will
require substantial reductions in NOx emissions from certain types of boilers
including those in AEP's power plants. To comply with Phase II of CAAA, the
Company plans to install NOx emission control equipment on certain units and
switch fuel at other units. Total capital costs to meet the requirements of
Phase II of CAAA are estimated to be approximately $90 million of which $69
million has been incurred through December 31, 1998.
On September 24, 1998, Federal EPA finalized rules which require reductions
in NOx emissions in 22 eastern states, including the states in which the
Company's generating plants are located. The implementation of the final
rules would be achieved through the revision of state implementation plans
(SIPs) by September 1999. SIPs are a procedural method used by each state to
comply with Federal EPA rules. The final rules anticipate the imposition of a
NOx reduction on utility sources of approximately 85% below 1990 emission
levels by the year 2003. On October 30, 1998, a number of utilities,
including the operating companies of the AEP System, filed petitions in the
US Court of Appeals for the District of Columbia Circuit seeking a review of
the final rules.
Should the states fail to adopt the required revisions to their SIPs within
one year of the date of the final rules (September 24, 1999), Federal EPA has
proposed to implement a federal plan to accomplish the NOx reductions.
Federal EPA also proposed the approval of portions of petitions filed by
eight northeastern states that would result in imposition of NOx emission
reductions on utility and industrial sources in upwind midwestern states.
These reductions are substantially the same as those required by the final
NOx rules and could be adopted by Federal EPA in the event the states fail to
implement SIPs in accordance with the final rules.
Preliminary estimates indicate that compliance costs could result in required
capital expenditures of approximately $1.2 billion for the AEP System.
Compliance costs cannot be estimated with certainty and the actual costs
incurred to comply could be significantly different from this preliminary
estimate depending upon the compliance alternatives selected to achieve
reductions in NOx emissions. Unless such costs are recovered from customers,
they would have a material adverse effect on results of operations, cash
flows and possibly financial condition.
LITIGATION - The Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns requested a ruling from
their National Office that certain interest deductions claimed by the Company
relating to AEP's corporate owned life insurance
38
<PAGE>
(COLI) program should not be allowed. As a result of a suit filed in US
District Court (discussed below) this request for ruling was withdrawn by the
IRS agents. Adjustments have been or will be proposed by the IRS disallowing
COLI interest deductions for taxable years 1991-96. A disallowance of the
COLI interest deductions through December 31, 1998 would reduce earnings by
approximately $316 million (including interest). The Company has made no
provision for any possible adverse earnings impact from this matter.
In 1998 the Company made payments of taxes and interest attributable to COLI
interest deductions for taxable years 1991-97 to avoid the potential
assessment by the IRS of any additional above market rate interest on the
contested amount. The payments to the IRS are included on the balance sheet
in other property and investments pending the resolution of this matter. The
Company will seek refund, either administratively or through litigation, of
all amounts paid plus interest. In order to resolve this issue without
further delay, on March 24, 1998, the Company filed suit against the US in
the US District Court for the Southern District of Ohio. Management believes
that it has a meritorious position and will vigorously pursue this lawsuit.
In the event the resolution of this matter is unfavorable, it will have a
material adverse impact on results of operations, cash flows and possibly
financial condition.
The Company is involved in a number of other 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, cash flows or financial
condition.
5. PROPOSED MERGER
In December 1997 the Company and Central and South West Corporation (CSW)
agreed to merge. At the 1998 annual meeting AEP shareholders approved the
issuance of common shares to effect the merger and approved an increase in
the number of authorized shares of AEP Common Stock from 300,000,000 to
600,000,000 shares. CSW stockholders approved the merger at their May 1998
annual meeting. Approval of the merger has been requested from the FERC, the
SEC, the NRC and all of CSW's state regulatory commissions: Arkansas,
Louisiana, Oklahoma and Texas. In the near future, AEP and CSW plan to make
the final two filings associated with approval of the merger with the Federal
Communications Commission and the Department of Justice.
Regulatory approvals for the merger have been received from the Arkansas
Public Service Commission (APSC) and the NRC. In December 1998 the APSC
approved a stipulated agreement related to a proposed merger regulatory plan
submitted by the Company, CSW and CSW's Arkansas operating subsidiary,
Southwestern Electric Power Company. The regulatory plan, agreed to with the
APSC staff, provides for a sharing of net merger savings through a $6 million
rate reduction over 5 years following the completion of the merger.
The application to the NRC by CSW's operating subsidiary, Central Power and
Light Company (CPL), requesting permission to transfer indirect control of
the license from CSW to AEP for CPL's interest in the South Texas Project
nuclear generating station was approved by the NRC in November 1998.
39
<PAGE>
In October 1998 the Oklahoma Corporation Commission (OCC) approved plans by
AEP and CSW to submit an amended filing seeking approval of the proposed
merger. The amended application is being made as a result of an Oklahoma
administrative law judge's recommendation that the merger filing be dismissed
without prejudice for lack of sufficient information regarding the potential
impact of the merger on the retail electric market in Oklahoma. An amended
application was filed in Oklahoma in February 1999. Submission of the amended
application will reset Oklahoma's 90-day statutory time period for OCC action
on the merger phase of the application.
A settlement agreement between AEP, CSW and certain key parties to the Texas
merger proceeding has been reached. The staff of the Public Utility
Commission of Texas was not a signatory to the settlement agreement, which
resolves all issues for the signatories. The settlement provides for, among
other things, rate reductions totaling approximately $180 million over a six
year period following completion of the merger to share net merger savings of
$84 million and settle existing rate issues of $96 million. Hearings are
scheduled for April 1999.
In July 1998 the FERC issued an order which confirmed that a 250 megawatt
firm contract path with the Ameren System is available. The contract path was
obtained by AEP and CSW to meet the requirement of the 1935 Act that the two
systems operate on an integrated and coordinated basis.
In November 1998 the FERC issued an order establishing hearing procedures for
the merger and scheduled the hearings to begin on June 1, 1999. The FERC
order indicated that the review of the proposed merger will address the
issues of competition, market power and customer protection and instructed
the companies to refile an updated market power study which was done in
January 1999.
The proposed merger of CSW into AEP would result in common ownership of two
UK regional electricity companies (RECs), Yorkshire and Seeboard, plc. AEP
has a 50% interest in Yorkshire and CSW has a 100% interest in Seeboard.
Although the merger of CSW into AEP is not subject to approval by UK
regulatory authorities, the common ownership of two UK RECs could be referred
by the UK Secretary of State for Trade and Industry to the UK Monopolies and
Mergers Commission for investigation.
AEP has received a request from the staff of the Kentucky Public Service
Commission (KPSC) to file an application seeking KPSC approval for the
indirect change in control of Kentucky Power Company that will occur as a
result of the proposed merger. Although AEP does not believe that the KPSC
has the jurisdictional authority to approve the merger, management will
prepare a merger application filing to be made with the KPSC, which is
expected to be filed by April 15, 1999. Under the governing statute the KPSC
must act on the application within 60 days. Therefore this is not expected to
impact the timing of the merger.
The merger is conditioned upon, among other things, the approval of the above
state and federal regulatory agencies. The transaction must satisfy many
conditions a number of which may not be waived by the parties, including the
condition that the merger must be accounted for as a pooling of interests.
The merger agreement will terminate on December 31, 1999 unless extended by
either party as provided in the merger agreement. Although consummation of
the merger is expected to occur in the fourth quarter of 1999, the Company is
40
<PAGE>
unable to predict the outcome or the timing of the required regulatory
proceedings.
As of December 31, 1998 the Company had deferred $20 million of incremental
costs incurred in connection with the proposed merger. The amounts deferred
are included in deferred charges on the Consolidated Balance Sheets.
6. ACQUISITIONS
The Company completed two non-regulated energy related acquisitions in 1998
through a subsidiary, AEPR. Both acquisitions have been included in the
December 31, 1998 consolidated financial statements using the purchase method
of accounting. The first acquisition was of CitiPower, an Australian
distribution utility, that serves approximately 240,000 customers in
Melbourne with 3,100 miles of distribution lines in a service area of
approximately 100 square miles. All of the stock of CitiPower was acquired on
December 31, 1998 for approximately $1.1 billion. The acquisition of
CitiPower had no effect on the results of operations for 1998. The financial
statements reflect a preliminary purchase price allocation. Estimated
goodwill of $557 million has been recorded in other property and investments
which will be amortized over a period of not more than 40 years.
The second acquisition was of midstream gas operations that include a fully
integrated natural gas gathering, processing, storage and transportation
operation in Louisiana and a gas trading and marketing operation in Houston.
The gas operations were acquired for approximately $340 million, including
working capital funds, on December 1, 1998 with one month of earnings
reflected in AEP's consolidated results of operations for the year ended
December 31, 1998. The financial statements reflect a preliminary purchase
price allocation. Estimated goodwill of approximately $158 million for the
midstream gas storage operations and $17 million for the gas trading and
marketing operation has been recorded in other property and investments and
is being amortized on a straight-line basis over not more than 40 years and
10 years, respectively.
7. YORKSHIRE ACQUISITION AND UK WINDFALL TAX
In April 1997 the Company and New Century Energies, Inc. through an equally
owned joint venture, Yorkshire Power Group Limited (YPG), acquired all of the
outstanding shares of Yorkshire. Total consideration paid by the joint
venture was approximately $2.4 billion which was financed by a combination of
equity and non-recourse debt. The Company uses the equity method of
accounting for its investment in YPG. The Company's investment in the joint
venture was $325.8 million and $287.4 million at December 31, 1998 and 1997,
respectively, and is included in other property and investments.
In July 1997 the British government enacted a new law that imposed a one-time
windfall tax on a revised privatization value which originally had been
computed in 1990 on certain privatized utilities. The windfall tax is
actually an adjustment by the UK government of the original privatization
price. The windfall tax liability for Yorkshire was 134 million pounds
sterling ($219 million) and was paid in two equal installments made in
December 1997 and December 1998. The Company's $109.4 million share of the
tax is reported as an extraordinary loss in 1997.
41
<PAGE>
The 1998 equity earnings from the Yorkshire investment are $38.5 million and are
included in nonoperating income. Equity earnings from the Yorkshire investment
for 1997, excluding the extraordinary loss, were $34 million.
The following amounts which are not included in AEP's consolidated financial
statements represent summarized consolidated financial information of YPG:
<TABLE>
<CAPTION>
December 31,
------------------------
1998 1997
----- ----
(in millions)
<S> <C> <C>
Assets:
Property, Plant and Equipment $1,602.2 $1,644.6
Current Assets 552.2 602.2
Goodwill (net) 1,547.3 1,602.5
Other Assets 294.5 292.9
-------- --------
Total Assets $3,996.2 $4,142.2
-------- --------
-------- --------
Capitalization and Liabilities:
Common Shareholders' Equity $ 666.4 $ 542.1
Long-term Debt 2,121.3 704.3
Other Noncurrent Liabilities 413.5 488.7
Long-term Debt Within One Year 13.3 1,776.4
Current Liabilities 781.7 630.7
-------- --------
Total Capitalization and
Liabilities $3,996.2 $4,142.2
-------- --------
-------- --------
</TABLE>
<TABLE>
<CAPTION>
Twelve Months Ended Nine Months Ended
December 31, 1998 December 31, 1997
------------------- -----------------
(in millions)
<S> <C> <C>
Income Statement Data:
Operating Revenues $2,284.0 $1,492.9
Operating Income 298.0 202.3
Income Before
Extraordinary Item 76.9 67.5
Net Income (Loss) 76.9 (151.3)
</TABLE>
8. STAFF REDUCTIONS
During 1998 an internal evaluation of the power generation organization was
conducted with a goal of developing an optimum organizational structure for a
competitive generation market. The study was completed in October 1998 and
called for the elimination of approximately 450 positions. In addition, a
review of energy delivery staffing levels in 1998 identified 65 positions for
elimination.
Severance accruals totaling $25.5 million were recorded in December 1998 for
reductions in power generation and energy delivery staffs and were charged to
other operation expense in the Consolidated Statements of Income. In January
1999, employment terminated for 65 energy delivery employees. In February
1999 the power generation staff reductions were made.
42
<PAGE>
9. BENEFIT PLANS:
AEP SYSTEM PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS - The AEP System
sponsors a qualified pension plan and a nonqualified pension plan. All
employees, except participants in the United Mine Workers of America (UMWA)
pension plans are covered by one or both of the pension plans. Other
Postretirement Benefit Plans (OPEB) are sponsored by the AEP System to
provide medical and death benefits for retired employees.
The following tables provide a reconciliation of the changes in the plans'
benefit obligations and fair value of assets over the two-year period ending
December 31, 1998, and a statement of the funded status as of December 31 for
both years:
<TABLE>
<CAPTION>
Pension Plan OPEB
---------------------- ---------------------
1998 1997 1998 1997
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
RECONCILIATION OF BENEFIT
OBLIGATION:
Obligation at January 1 $1,909,400 $1,676,200 $ 849,700 $726,400
Service Cost 45,100 36,000 17,500 14,000
Interest Cost 133,200 128,600 59,300 55,900
Participant Contributions - - 5,900 5,300
Plan Amendments (a) 48,400 - - -
Actuarial Loss 96,000 170,500 133,100 90,900
Acquisitions (b) 100 - 2,800 -
Benefit Payments (105,900) (101,900) (46,600) (42,800)
---------- ---------- ---------- --------
Obligation at December 31 $2,126,300 $1,909,400 $1,021,700 $849,700
---------- ---------- ---------- --------
---------- ---------- ---------- --------
RECONCILIATION OF FAIR VALUE
OF PLAN ASSETS:
Fair value of plan assets at
January 1 $2,370,300 $2,009,500 $311,900 $232,500
Actual Return on Plan Assets 385,900 462,700 52,600 44,100
Company Contributions 400 - 72,600 72,800
Participant Contributions - - 5,900 5,300
Benefit Payments (105,900) (101,900) (46,600) (42,800)
---------- ---------- ---------- --------
Fair value of plan assets at
December 31 $2,650,700 $2,370,300 $396,400 $311,900
---------- ---------- ---------- --------
---------- ---------- ---------- --------
FUNDED STATUS:
Funded status at December 31 $ 524,400 $ 460,900 $(625,300)$(537,800)
Unrecognized Net Transition
(Asset) Obligation (49,200) (59,100) 360,700 416,400
Unrecognized Prior-Service Cost 157,400 123,500 - -
Unrecognized Actuarial
(Gain) Loss (756,300) (640,800) 175,000 66,100
---------- ---------- ---------- --------
Accrued Benefit Liability $(123,700) $(115,500) $ (89,600)$ (55,300)
---------- ---------- ---------- --------
---------- ---------- ---------- --------
</TABLE>
(a) Early retirement factors for the Company pension plan were changed to
provide more generous benefits to participants retiring between ages 55 and
60.
(b) On December 1, 1998 the Company acquired midstream gas operations
resulting in approximately 170 new employees becoming participants in the
Company's pension and OPEB plans.
43
<PAGE>
The following table provides the amounts recognized in the consolidated balance
sheets as of December 31 of both years:
<TABLE>
<CAPTION>
Pension Plan OPEB
----------------------- ---------------------
1998 1997 1998 1997
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
Accrued Benefit Liability $(123,700) $(115,500) $(89,600) $(55,300)
Additional Minimum Liability (3,400) (900) - -
Intangible Asset 3,400 900 - -
--------- --------- -------- --------
Net Amount Recognized $(123,700) $(115,500) $(89,600) $(55,300)
--------- --------- -------- --------
--------- --------- -------- --------
</TABLE>
The Company's nonqualified pension plan had an accumulated benefit obligation
in excess of plan assets of $25 million and $19.4 million at December 31,
1998 and 1997, respectively. There are no plan assets in the nonqualified
plan due to the nature of the plan.
The Company's OPEB plans had accumulated benefit obligations in excess of
plan assets of $625.3 million and $537.8 million at December 31, 1998 and
1997, respectively.
The following table provides the components of net periodic benefit cost for
the plans for fiscal years 1998 and 1997:
<TABLE>
<CAPTION>
Pension Plan OPEB
--------------------- --------------------
1998 1997 1998 1997
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
Service cost $ 45,100 $ 36,000 $ 17,500 $ 14,000
Interest cost 133,200 128,600 59,300 55,900
Expected return on
plan assets (172,000) (154,200) (28,500) (22,200)
Amortization of transition
(asset) obligation (9,900) (9,900) 32,000 32,000
Amortization of prior-service
cost 14,400 13,800 - -
Amortization of net actuarial
(gain) loss (2,600) (4,700) 200 (400)
--------- --------- -------- --------
Net periodic benefit cost 8,200 9,600 80,500 79,300
Curtailment loss - - 24,100(a) -
--------- --------- -------- --------
Net periodic benefit cost
after curtailments $ 8,200 $ 9,600 $104,600 $ 79,300
--------- --------- -------- --------
--------- --------- -------- --------
</TABLE>
(a) Curtailment charges were recognized during 1998 in anticipation of the
October 31, 1999 shutdown of Muskingum Mine by Central Ohio Coal Company, a
subsidiary of AEP.
44
<PAGE>
The assumptions used in the measurement of the Company's benefit obligation are
shown in the following table:
<TABLE>
<CAPTION>
Pension Plan OPEB
---------------- ----------------
1998 1997 1998 1997
---- ---- ---- ----
<S> <C> <C> <C> <C>
Weighted-average assumptions
as of December 31
Discount rate 6.75% 7.00% 6.75% 7.00%
Expected return on plan assets 9.00% 9.00% 8.75% 8.75%
Rate of compensation increase 3.2% 3.2% N/A N/A
</TABLE>
For measurement purposes, a 5.5% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 1999. The rate was
assumed to decrease gradually each year to a rate of 4.25% for 2005 and
remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the OPEB health care plans. A 1% change in assumed health care
cost trend rates would have the following effects:
<TABLE>
<CAPTION>
1% Increase 1% Decrease
----------- -----------
(in thousands)
<S> <C> <C>
Effect on total of service and
interest cost components of
net periodic postretirement
health care benefit cost $ 9,700 $ (8,400)
Effect on the health care
component of the accumulated
postretirement benefit obligation 113,000 (99,800)
</TABLE>
CitiPower, a subsidiary acquired on December 31, 1998 sponsors a defined
benefit pension plan. At December 31, 1998, the fair value of the plan assets
was $24.6 million and the accumulated benefit obligation of this plan was
$25.3 million. This plan's actuarial assumptions are not significantly
different from AEP's.
AEP SYSTEM SAVINGS PLAN - The AEP System Savings Plan is a defined
contribution plan offered to non-UMWA employees. The cost for contributions
to this plan totaled $20.5 million in 1998, $19.6 million in 1997 and $19
million in 1996.
OTHER UMWA BENEFITS - The Company provides UMWA pension, health and welfare
benefits for certain unionized mining employees, retirees, and their
survivors who meet eligibility requirements. The benefits are administered by
UMWA trustees and contributions are made to their trust funds. Contributions
based on hours worked are expensed as paid as part of the cost of active
mining operations and were not material in 1998, 1997 and 1996. Based upon
the UMWA actuary estimate, the Company's share of unfunded pension liability
was $28 million at June 30, 1998. In the event the Company should
significantly reduce or cease mining operations or contributions to the UMWA
trust funds, a withdrawal obligation will be triggered for both the pension
and health and welfare plans. If the mining operations had been closed on
December 31, 1998 the estimated annual withdrawal liability for all UMWA
benefit plans would have been $6.5 million. The UMWA withdrawal liability for
the anticipated shutdown of Central
45
<PAGE>
Ohio Coal Company's Muskingum mine has been included as a curtailment loss in
the net periodic benefit cost under the Company's OPEB plans in 1998.
10. BUSINESS SEGMENTS
As of December 31, 1998, the Company adopted SFAS 131, "Disclosure about
Segments of an Enterprise and Related Information." SFAS 131 established
standards for reporting information about operating segments in annual
financial statements and requires selected information about operating
segments in interim financial reports issued to shareholders. It also
established standards for related disclosures about products and services,
and geographic areas. Operating segments are defined as components of an
enterprise about which separate financial information is available and
evaluated regularly by the chief operating decision maker.
The Company's reportable segments are primarily differentiated based on
whether the business activity is conducted within a regulated environment.
The Company manages its operations on this basis because of the substantial
impact of regulatory oversight on business processes, cost structures and
operating results.
The Company's principal business segment is its cost based rate regulated
Domestic Electric Utilities business consisting of seven regulated utility
operating companies providing retail, commercial, industrial and wholesale
electric services in seven Atlantic and Midwestern states. Also included in
this segment are the Company's electric power wholesale marketing and trading
activities that are conducted as part of regulated operations and subject to
regulatory ratemaking oversight. The World Wide Energy Investments segment
represents principally international investments in energy-related projects
and operations. It also includes the development and management of such
projects and operations. Such investment activities include electric
generation, supply and distribution, and natural gas pipeline, storage and
other natural gas services. Other business segments include non-regulated
electric and gas trading activities, telecommunication services, and the
marketing of various energy saving products and services. Intersegment
revenues, ie. revenues from transactions with operating segments, are not
material. As of December 31, 1998 and 1997 less than 6% of long-lived assets
were located in foreign countries.
46
<PAGE>
<TABLE>
<CAPTION>
World
Regulated Domestic Wide Energy Reconciling AEP
Year Electric Utilities Investments Other Adjustments Consolidated
- ---- ------------------ ---------- ----- ----------- ------------
(in thousands)
<S> <C> <C> <C> <C> <C>
1998
Revenues from
external customers $6,345,900 $57,600 $(28,300) $(29,300) $6,345,900
Revenues from transactions
with other operating
segments - 1,600 1,900 (3,500) -
Interest revenues 400 200 600
Interest expense 399,200 16,900 3,000 419,100
Depreciation, depletion and
amortization expense 580,000 1,000 1,400 (2,400) 580,000
Net income (loss) for equity
method subsidiaries - 38,600 - 38,600
Income tax expense (benefit) 299,100 (15,300) (21,200) 262,600
Segment net income (loss) 563,400 12,300 (39,500) 536,200
Total assets 16,837,300 2,063,300 582,600 19,483,200
Investments in equity method
subsidiaries 100 335,200 - 335,300
Gross property additions 699,700 1,481,000 23,000 2,203,700
1997
Revenues from
external customers $5,879,800 $14,600 $ 2,200 $(16,800) $5,879,800
Revenues from transactions
with other operating
segments - - - - -
Interest revenues - 1,700 - 1,700
Interest expense 390,300 14,900 600 405,800
Depreciation, depletion and
amortization expense 591,100 - - - 591,100
Net income for equity method
subsidiaries - 33,300 - - 33,300
Income tax expense (benefit) 330,100 (25,000) (6,600) 298,500
Extraordinary Loss -
UK Windfall Tax - (109,400) - - (109,400)
Segment net income (loss) 602,900 (79,600) (12,300) 511,000
Total assets 16,223,700 367,100 24,500 16,615,300
Investments in equity method
subsidiaries 100 287,300 - 287,400
Gross property additions 694,400 62,400 3,600 760,400
1996
Revenues from
external customers $5,849,200 $12,500 $ - $(12,500) $5,849,200
Revenues from transactions
with other operating
segments - 100 - (100) -
Interest revenues - - - - -
Interest expense 381,000 300 - - 381,300
Depreciation, depletion and
amortization expense 600,900 - - - 600,900
Income tax expense (benefit) 325,500 (1,000) (1,900) 322,600
Segment net income (loss) 597,600 (6,600) (3,600) 587,400
Total assets 15,858,900 5,100 19,000 15,883,000
Investments in equity method
subsidiaries 100 - - 100
Gross property additions 577,700 - - 577,700
</TABLE>
47
<PAGE>
11. FINANCIAL INSTRUMENTS, CREDIT AND RISK MANAGEMENT
The Company is subject to market risk as a result of changes in commodity
prices, foreign currency exchange rates, and interest rates. The Company has
a wholesale electricity and gas trading and marketing operation that manages
the exposure to commodity price movements using physical forward purchase and
sale contracts at fixed and variable prices, and financial derivative
instruments including exchange traded futures and options, over-the-counter
options, swaps and other financial derivative contracts at both fixed and
variable prices. Physical forward electricity contracts and certain
qualifying hedges within AEP's traditional economic market area are recorded
as net operating revenues in the month when the physical contract settles.
Net gains for the year ended December 31, 1998 were $111 million. Physical
forward electricity contracts outside AEP's traditional marketing area, and
all financial electricity trading transactions which do not qualify as a
hedge, and/or where the underlying physical commodity is outside AEP's
traditional economic market area are marked to market and recorded net in
nonoperating income. Net losses for the year ended December 31, 1998 were $37
million. All physical and financial instruments for natural gas are marked to
market and are included on a net basis in nonoperating income. Net gains for
the year ended December 31, 1998 were $6 million. The unrealized
mark-to-market gains and losses from such trading of financial instruments
are reported as assets and liabilities, respectively. These activities were
not material in prior periods.
Investment in foreign ventures exposes the Company to risk of foreign
currency fluctuations. Also, the Company is exposed to changes in interest
rates primarily due to short- and long-term borrowings used to fund its
business operations. The debt portfolio has both fixed and variable interest
rates with terms from one day to forty years and an average duration of 5
years at December 31, 1998. The Company does not presently utilize
derivatives to manage its exposures to foreign currency exchange rate
movements.
MARKET VALUATION - The book value 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. The book value
amount of the pre-April 1983 spent nuclear fuel disposal liability
approximates the Company's best estimate of its fair value.
The book value amounts and fair values of the Company's significant financial
instruments at December 31, 1998 are summarized in the following table. The
fair values of long-term debt and preferred stock are 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 fair
value of those financial instruments that are marked-to-market are based on
management's best estimates using over-the-counter quotations, exchange
prices, volatility factors and valuation methodology. The estimates presented
herein are not necessarily indicative of the amounts that the Company could
realize in a current market exchange.
48
<PAGE>
<TABLE>
<CAPTION>
Book Value Fair Value
---------- ----------
(in thousands)
<S> <C> <C>
NON-DERIVATIVES
1998
Long-term Debt $7,006,100 $7,291,200
Preferred Stock 127,600 134,100
1997
Long-term Debt 5,423,900 5,670,400
Preferred Stock 127,600 136,000
DERIVATIVES
</TABLE>
<TABLE>
<CAPTION>
TRADING ASSETS
Notional Amount Fair Value Average Fair Value
--------------- ----------- ------------------
(in thousands)
<S> <C> <C> <C>
ELECTRIC
Physicals $ (62,000) $ 46,100 $ 40,800
Options (4,700) 32,200 79,000
Swaps (15,600) 3,400 1,000
GAS
Futures (70,300) 5,900 1,900
Physicals (285,200) 43,600 29,900
Options (3,600) 18,000 11,700
Swaps 1,477,900 245,600 143,000
TRADING LIABILITIES
ELECTRIC
Futures 20,300 (7,200) (1,800)
Physicals 27,500 (50,600) (46,300)
Options 9,700 (28,700) (78,300)
Swaps 16,200 (7,700) (1,900)
GAS
Physicals 283,900 (42,400) (28,700)
Options 4,700 (22,600) (14,100)
Swaps (1,524,900) (231,200) (135,700)
</TABLE>
At December 31, 1998 the fair value of the assets and liabilities related to
the wholesale electric forward contracts was $367 million and $356 million,
respectively. The respective notional amounts were $828 million and $772
million, respectively. The average fair value amounts outstanding during the
period were $922 million of assets and $882 million of liabilities.
AEP routinely enters into exchange traded futures and options transactions
for electricity and natural gas as part of its wholesale trading operations.
These transactions are executed through brokerage accounts with brokers who
are registered with the Commodity Futures Trading Commission. Brokers require
cash or cash related instruments to be deposited on these accounts as margin
calls against the customer's open
49
<PAGE>
position. The amount of these deposits at December 31, 1998 was $10 million.
CREDIT AND RISK MANAGEMENT - In addition to market risk associated with price
movements, AEP is also subject to the credit risk inherent in its risk
management activities. Credit risk refers to the financial risk arising from
commercial transactions and/or the intrinsic financial value of contractual
agreements with trading counter parties, by which there exists a potential
risk of nonperformance. The Company has established and enforced credit
policies that minimize or eliminate this risk. AEP accepts as counter parties
to forwards, futures, and other derivative contracts primarily those entities
that are classified as Investment Grade, or those that can be considered as
such due to the effective placement of credit enhancements and/or collateral
agreements. Investment Grade is the designation given to the four highest
debt rating categories (i.e., AAA, AA, A, BBB) of the major rating services,
e.g., ratings BBB- and above at Standard & Poor's and Baa3 and above at
Moody's. When adverse market conditions have the potential to negatively
affect a counter party's credit position, the Company will require further
enhancements to mitigate risk. Since the formation of the trading business in
July of 1997, the Company has experienced no significant losses due to the
credit risk associated with its risk management activities; furthermore, the
Company does not anticipate any future material effect on its results of
operations, cash flow or financial condition as a result of counter party
nonperformance.
OTHER 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 of
tax-exempt municipal bonds and other securities.
At December 31, 1998 and 1997 the fair values of the trust investments were
$648 million and $566 million, respectively, and had a cost basis of $584
million and $527 million, respectively. Accumulated gross unrealized holding
gains were $65 million and $41 million at December 31, 1998 and 1997,
respectively and accumulated gross unrealized holding losses were $1.1
million and $1.2 million at December 31, 1998 and 1997, respectively. The
change in market value in 1998, 1997, and 1996 was a net unrealized holding
gain of $24 million, $19.1 million, and $2.6 million, respectively.
The trust investments' cost basis by security type were:
<TABLE>
<CAPTION>
December 31,
-------------------------
1998 1997
---- ----
(in thousands)
<S> <C> <C>
Tax-Exempt Bonds $326,239 $335,358
Equity Securities 95,854 74,398
Treasury Bonds 71,194 44,200
Corporate Bonds 10,661 9,167
Cash, Cash Equivalents and
Accrued Interest 80,065 63,392
-------- --------
Total $584,013 $526,515
-------- --------
-------- --------
</TABLE>
Proceeds from sales and maturities of securities of $225 million during 1998
resulted in $8.2 million of realized gains and $2.8 million of realized losses.
Proceeds from sales and maturities of securities of $147.3 million during 1997
resulted in $3.9 million of realized gains and $1.4 million of realized losses.
Proceeds from sales and maturities of securities of $115.3 million during 1996
resulted in $2.6 million of realized gains and $2.1 million of realized losses.
The cost of securities for determining realized gains and losses is original
acquisition cost including amortized premiums and discounts.
50
<PAGE>
At December 31, 1998, the year of maturity of trust fund investments other than
equity securities, was:
<TABLE>
<CAPTION>
(in thousands)
<S> <C>
1999 $106,316
2000 - 2003 157,224
2004 - 2008 175,751
After 2008 48,868
--------
Total $488,159
--------
--------
</TABLE>
An AEP Resources' subsidiary established a non-recourse variable-rate credit
facility in the aggregate amount of $775 million on December 31, 1998.
Certain assets of the subsidiary support the facility. The facility is
comprised of three tranches: $244 million maturing on December 31, 2000, $488
million maturing on December 31, 2003, and a $43 million short-term capital
facility. As of December 31, 1998 $732 million were outstanding at an average
interest rate of 5.833%.
The subsidiary entered into several interest rate swap agreements for $586
million of the borrowings under the credit facility. The swap agreements
involve the exchange of floating-rate for fixed-rate interest payments.
Interest is recognized currently based on the fixed rate of interest
resulting from use of these swap agreements. Market risks arise from the
movements in interest rates. If counterparties to an interest rate swap
agreement were to default on contractual payments, the subsidiary could be
exposed to increased costs related to replacing the original agreement.
However, the subsidiary does not anticipate non-performance by any
counterparty to any interest rate swap in effect as of December 31, 1998. As
of December 31, 1998, the subsidiary was a party to interest rate swaps
having a aggregate notional amount of $586 million, with $342 million
maturing on December 31, 2000, and $244 million maturing on December 31,
2003. The average fixed interest rate payable on the aggregate of the
interest rate swaps is 5.32%. The floating rate for interest rate swaps was
4.9% at December 31, 1998. The estimated fair value of the interest rate
swaps, which represents the estimated amount the subsidiary would pay to
terminate the swaps at December 31, 1998, based on quoted interest rates, is
a net liability of $5 million.
In accordance with the debt covenants included in the financing provisions of
this facility, the subsidiary must hedge at least 80% of its energy purchase
requirements through energy trading derivative instruments entered into with
market participants, predominantly generators. As of December 31, 1998, the
subsidiary had outstanding energy trading derivatives with a total contracted
load of 12,545 GWh's. These contracts have maturities in the range of 3
months to twelve years. Management's estimate of the fair value of these
derivatives as of December 31, 1998, is $3.3 million in excess of book value.
51
<PAGE>
12. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------
1998 1997 1996
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Charged (CREDITED) to Operating Expenses (net):
Current $294,139 $346,290 $375,528
Deferred 37,877 11,124 (17,008)
Deferred Investment Tax Credits (15,815) (16,134) (16,298)
-------- -------- --------
Total 316,201 341,280 342,222
-------- -------- --------
Charged (CREDITED) to Nonoperating Income (net):
Current (47,718) (16,038) (5,636)
Deferred 3,572 (17,673) (4,470)
Deferred Investment Tax Credits (9,489) (9,107) (9,510)
-------- -------- --------
Total (53,635) (42,818) (19,616)
-------- -------- --------
Total Federal Income Tax as Reported $262,566 $298,462 $322,606
-------- -------- --------
-------- -------- --------
</TABLE>
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.
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1998 1997 1996
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Income Before Preferred Stock Dividend
Requirements of Subsidiaries $547,109 $ 638,211 $628,856
Extraordinary Loss - UK Windfall Tax (Note 7) - (109,419) -
Federal Income Taxes 262,566 298,462 322,606
--------- -------- --------
Pre-Tax Book Income $809,675 $ 827,254 $951,462
--------- -------- --------
--------- -------- --------
Federal Income Tax on Pre-Tax Book Income
at Statutory Rate (35%) $283,386 $289,539 $333,012
Increase (Decrease) in Federal Income Tax
Resulting from the Following Items:
Depreciation 57,663 53,239 50,537
Corporate Owned Life Insurance (16,428) (18,240) (12,009)
Investment Tax Credits (net) (25,304) (25,241) (25,813)
Extraordinary Loss - UK Windfall Tax - 38,297 -
Other (36,751) (39,132) (23,121)
--------- -------- --------
Total Federal Income Taxes as Reported $262,566 $298,462 $322,606
--------- -------- --------
--------- -------- --------
Effective Federal Income Tax Rate 32.4% 36.1% 33.9%
--------- -------- --------
--------- -------- --------
</TABLE>
52
The following tables show the elements of the net deferred tax liability and the
significant temporary differences:
<TABLE>
<CAPTION>
December 31,
---------------------------
1998 1997
---- ----
(in thousands)
<S> <C> <C>
Deferred Tax Assets $ 879,322 $ 807,226
Deferred Tax Liabilities (3,480,724) (3,368,147)
----------- -----------
Net Deferred Tax Liabilities $(2,601,402) $(2,560,921)
----------- -----------
----------- -----------
Property Related Temporary Differences $(2,170,077) $(2,161,484)
Amounts Due From Customers For Future
Federal Income Taxes (395,605) (410,255)
Deferred State Income Taxes (193,867) (201,843)
All Other (net) 158,147 212,661
----------- -----------
Total Net Deferred Tax Liabilities $(2,601,402) $(2,560,921)
----------- -----------
----------- -----------
</TABLE>
The Company has settled with the 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 1996 are presently being audited by the IRS. With the
exception of interest deductions related to AEP's corporate owned life insurance
program, which are discussed under the heading, Litigation, in Note 4,
management is not aware of any issues for open tax years that upon final
resolution are expected to have a material adverse effect on results of
operations.
13. SUPPLEMENTARY INFORMATION:
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------
1998 1997 1996
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Purchased Power -
Ohio Valley Electric Corporation
(44.2% owned by AEP System) $42,612 $29,631 $22,156
Cash was paid for:
Interest (net of capitalized amounts) $413,341 $390,491 $373,570
Income Taxes $281,709 $398,833 $404,297
Noncash Investing and Financing Activities:
Acquisitions under Capital Leases $119,188 $234,846 $136,988
Assumption of Liabilities related
to Acquisitions $151,506 $ - $ -
</TABLE>
14. 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.
53
<PAGE>
Lease rentals are primarily charged to operating expenses in accordance with
rate-making treatment. The components of rentals are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1998 1997 1996
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Operating Leases $254,467 $257,042 $262,451
Amortization of Capital Leases 91,359 104,732 114,050
Interest on Capital Leases 37,516 31,601 28,696
-------- -------- --------
Total Rental Payments $383,342 $393,375 $405,197
-------- -------- --------
-------- -------- --------
</TABLE>
Properties under capital leases and related obligations on the Consolidated
Balance Sheets are as follows:
<TABLE>
<CAPTION>
December 31,
-----------------------------
1998 1997
---- ----
(in thousands)
<S> <C> <C>
LEASED ASSETS IN ELECTRIC UTILITY PLANT:
Production $ 46,532 $ 47,246
Transmission 4 3
Distribution 14,650 14,660
General:
Nuclear Fuel (net of amortization) 103,939 103,939
Mining Plant and Other 530,291 516,843
-------- --------
Total Electric Utility Plant 695,416 682,691
Accumulated Amortization 208,548 196,145
-------- --------
Net Electric Utility Plant 486,868 486,546
-------- --------
LEASED ASSETS IN OTHER PROPERTY 54,102 57,763
Accumulated Amortization 8,387 5,917
-------- --------
Net Other Property 45,715 51,846
-------- --------
Net Property under Capital Leases $532,583 $538,392
-------- --------
-------- --------
Capital Lease Obligations:*
Noncurrent Liability $450,922 $437,303
Liability Due Within One Year 81,661 101,089
-------- --------
Total Capital Lease Obligations $532,583 $538,392
-------- --------
-------- --------
</TABLE>
*Represents the present value of future minimum lease payments for plant and
nuclear fuel. The noncurrent portion of capital lease obligations is included
in other noncurrent liabilities in the Consolidated Balance Sheet.
54
<PAGE>
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, 1998:
<TABLE>
<CAPTION>
Noncancelable
Capital Operating
Leases Leases
-------- -------------
(in thousands)
<S> <C> <C>
1999 $109,395 $ 239,361
2000 97,132 237,522
2001 79,976 234,147
2002 67,103 228,144
2003 45,161 227,618
Later Years 148,121 3,437,925
-------- ----------
Total Future Minimum Lease Rentals 546,888 (a) $4,604,717
Less Estimated Interest Element 118,244 ----------
Estimated Present Value of Future -------- ----------
Minimum Lease Rentals 428,644
Unamortized Nuclear Fuel 103,939
--------
Total $532,583
--------
--------
</TABLE>
(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.
15. CAPITAL STOCKS AND PAID-IN CAPITAL:
Changes in capital stocks and paid-in capital during the period January 1, 1996
through December 31, 1998 were:
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C> <C> <C>
January 1, 1996 195,634,992 6,709,751 $1,271,627 $1,658,524 $ 148,240 $ 522,735
Issuances 1,600,000 - 10,400 55,061 - -
Retirements and
Other - (707,518) - 1,969 (57,917) (12,835)
----------- ---------- ---------- ---------- ---------- ----------
December 31, 1996 197,234,992 6,002,233 1,282,027 1,715,554 90,323 509,900
Issuances 1,754,989 - 11,408 65,337 - -
Retirements and
Other - (4,258,947) - (2,109) (43,599) (382,295)
----------- ---------- ---------- ---------- ---------- ----------
December 31, 1997 198,989,981 1,743,286 1,293,435 1,778,782 46,724 127,605
Issuances 1,826,488 - 11,872 73,643 - -
Retirements and
Other - (7,220) - 487 (722) -
----------- ---------- ---------- ---------- ---------- ----------
December 31, 1998 200,816,469 1,736,066 $1,305,307 $1,852,912 $ 46,002 $ 127,605
----------- ---------- ---------- ---------- ---------- ----------
----------- ---------- ---------- ---------- ---------- ----------
</TABLE>
(a) Includes 8,999,992 shares of treasury stock.
(b) Including portion due within one year.
55
<PAGE>
16. LINES OF CREDIT AND COMMITMENT FEES:
At December 31, 1998 and 1997, unused short-term bank lines of credit were
available in the amounts of $763 million and $442 million, respectively. In
addition several of the subsidiaries engaged in providing non-regulated energy
services share a line of credit under a revolving credit agreement. The amounts
of credit available under the revolving credit agreement were $60 million and
$330 million at December 31, 1998 and 1997, respectively. The short-term bank
lines of credit and the revolving credit agreement require the payment of
facility fees of approximately 1/10 of 1% on the daily amount of such
commitments.
Outstanding short-term debt consisted of:
<TABLE>
<CAPTION>
December 31,
-------------------------
1998 1997
---- ----
(dollars in thousands)
<S> <C> <C>
Balance Outstanding:
Notes Payable $197,304 $199,285
Commercial Paper 419,300 355,790
-------- --------
Total $616,604 $555,075
-------- --------
-------- --------
Year-End Weighted
Average Interest Rate:
Notes Payable 5.8% 6.3%
Commercial Paper 6.2% 6.8%
Total 6.1% 6.6%
</TABLE>
56
<PAGE>
17. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
<TABLE>
<CAPTION>
Quarterly Periods Ended
-----------------------------------------------------
1998
-----------------------------------------------------
March 31 June 30 Sept. 30 Dec. 31
(In Thousands - Except -------- ------- -------- -------
Per Share Amounts)
- ----------------------
<S> <C> <C> <C> <C>
Operating Revenues $1,509,410 $1,560,944 $1,845,228 $1,430,320
Operating Income 255,932 227,190 311,579 162,033
Net Income 150,586 118,084 195,365 72,148
Earnings per Share 0.79 0.62 1.02 0.38
</TABLE>
Fourth quarter 1998 earnings declined primarily as a result of unseasonably mild
weather, severance accruals and the negative impact of the extended Cook Plant
outage.
<TABLE>
<CAPTION>
Quarterly Periods Ended
-----------------------------------------------------
1997
-----------------------------------------------------
March 31 June 30 Sept. 30 Dec. 31
(In Thousands - Except -------- ------- -------- -------
Per Share Amounts)
- ----------------------
<S> <C> <C> <C> <C>
Operating Revenues $1,492,069 $1,382,158 $1,507,075 $1,498,518
Operating Income 271,978 221,255 275,090 216,131
Income Before
Extraordinary Item 172,562 121,139 201,746 124,933
Net Income 172,562 121,139 91,181 126,079
Earnings per Share
Before Extraordinary
Item* 0.92 0.64 1.07 0.66
Earnings per Share 0.92 0.64 0.48 0.66
</TABLE>
*Amounts for 1997 do not add to $3.28 earnings per share due to
rounding.
The third quarter of 1997 includes an extraordinary loss of $110.6 million or
$0.59 per share for a UK Windfall Tax which retroactively adjusted upward
Yorkshire's privatization price discussed in Note 7.
See "Reclassification" in Note 1 regarding reclassification of prior period
amounts.
57
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
<TABLE>
<CAPTION>
December 31, 1998
--------------------------------------------------------------------
Call
Price per Shares Shares Amount (In
Share (a) Authorized(b) Outstanding Thousands)
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 460,016 $ 46,002
--------
--------
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 388,100 $ 38,810
6.02% - 6-7/8% (c) (e) 1,950,000 637,950 63,795
7% (f) (f) 250,000 250,000 25,000
Total Subject to Mandatory --------
Redemption (c) $127,605
--------
--------
- ----------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
December 31, 1997
--------------------------------------------------------------------
Call
Price per Shares Shares Amount (In
Share (a) Authorized(b) Outstanding Thousands)
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 467,236 $ 46,724
--------
--------
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 388,100 $ 38,810
6.02% - 6-7/8% (c) (e) 1,950,000 637,950 63,795
7% (f) (f) 250,000 250,000 25,000
Total Subject to Mandatory --------
Redemption (c) $127,605
--------
--------
</TABLE>
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
plus accrued dividends. The involuntary liquidation preference is $100 per
share for all outstanding shares.
(b) As of December 31, 1998 the subsidiaries had 7,193,024, 22,200,000 and
7,583,313 shares of $100, $25 and no par value preferred stock,
respectively, that were authorized but unissued.
(c) 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. The subsidiaries reacquired
enough shares in 1997 to meet all sinking fund requirements on certain
series until 2008 and on certain series until 2009 when all remaining
outstanding shares must be redeemed.The sinking fund provisions of the
series subject to mandatory redemption aggregate $5,000,000 each year for
the years 2000, 2001, 2002 and $15,000,000 in 2003.
(d) Not callable prior to 2003; after that the call price is $100 per share.
(e) Not callable prior to 2000; after that the call price is $100 per share.
(f) With sinking fund. Redemption is restricted prior to 2000.
58
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
<TABLE>
<CAPTION>
Weighted Average
Maturity Interest Rate Interest Rates at December 31, December 31,
- -------- ----------------- ------------------------------ ------------------
December 31, 1998 1998 1997 1998 1997
----------------- ---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C> <C>
FIRST MORTGAGE BONDS
1998-2002 7.23% 6.35%-8.95% 6.35%-9.15% $ 759,000 $1,131,411
2003-2006 6.70% 6%-8% 6%-8% 846,000 846,000
2022-2025 7.90% 7.10%-8.80% 7.10%-8.80% 1,020,768 1,120,419
INSTALLMENT PURCHASE CONTRACTS (a)
1998-2002 4.40% 4.05%-5.15% 3.70%-7-1/4% 145,000 189,500
2007-2025 6.42% 5.00%-7-7/8% 5.45%-7-7/8% 776,245 756,745
NOTES PAYABLE (b)
1998-2008 5.97% 5.49%-9.60% 5.29%-9.60% 1,493,360 527,681
SENIOR UNSECURED NOTES
2003-2008 6.54% 6.24%-6.91% 6.73%-6.91% 786,000 144,000
2038 7.30% 7.20%-7-3/8% - 340,000 -
JUNIOR DEBENTURES
2025 - 2038 8.05% 7.60%-8.72% 7.92%-8.72% 620,000 495,000
OTHER LONG-TERM DEBT (c) 269,319 250,357
Unamortized Discount (net) (49,575) (37,196)
---------- ----------
Total Long-term Debt
Outstanding (d) 7,006,117 5,423,917
Less Portion Due Within One Year 206,476 294,454
---------- ----------
Long-term Portion $6,799,641 $5,129,463
---------- ----------
---------- ----------
</TABLE>
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 demand 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 and revolving credit agreements with a number of banks and
other financial institutions. At expiration all notes then issued and
outstanding are due and payable. Interest rates are both fixed and variable.
Variable rates generally relate to specified short-term interest rates.
(c) Other long-term debt consists of a liability along with accrued interest
for disposal of spent nuclear fuel (see Note 4 of the Notes to Consolidated
Financial Statements) and financing obligation under sale lease back
agreements.
(d) Long-term debt outstanding at December 31, 1998 is payable as follows:
<TABLE>
<CAPTION>
Principal Amount (in thousands)
<S> <C>
1999 $ 206,476
2000 786,222
2001 512,028
2002 294,546
2003 934,547
Later Years 4,321,873
----------
Total Principal
Amount 7,055,692
Unamortized
Discount (49,575)
----------
Total $7,006,117
----------
----------
</TABLE>
59
<PAGE>
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
unrestricted 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.
60
<PAGE>
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, 1998 and
1997, and the related consolidated statements of income, retained earnings, and
cash flows for each of the three years in the period ended December 31, 1998.
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, 1998 and 1997, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1998 in conformity with generally accepted accounting
principles.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 23, 1999
61
<PAGE>
[LOGO]
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC.
PROXY SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS
FOR THE ANNUAL MEETING TO BE HELD APRIL 28, 1999
----------------------------------------------------------------------
The undersigned appoints E. Linn Draper, Jr., Henry W. Fayne and
Joseph H. Vipperman, and each of them, acting by a majority if more
than one be present, attorneys and proxies of the undersigned,
P with power of substitution, to represent the undersigned at the
R annual meeting of shareholders of American Electric Power Company,
O Inc. to be held on April 28, 1999, and at any adjournments thereof,
X and to vote all shares of Common Stock of the Company which the
Y undersigned is entitled to vote on all matters coming before said
meeting.
TRUSTEE'S AUTHORIZATION. The undersigned authorizes Fidelity
Management Trust Company to vote all shares of Common Stock of the
Company credited to the undersigned's account under the American
Electric Power System Employees Savings Plan at the annual meeting in
accordance with the instructions on the reverse side.
Election of Directors. Nominees: 01. J.P. DesBarres, 02. E.L.
Draper, Jr., 03. R.M. Duncan, 04.
R.W. Fri, 05. L.A. Hudson, Jr., 06.
L.J. Kujawa, 07. D.G. Smith, 08.
L.G. Stuntz, 09. K.D. Sullivan, 10.
M. Tanenbaum.
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.
----------------------------------------------------------------------
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 ^
[LOGO]
ADMISSION TICKET
- ---------------------------------------------
ANNUAL MEETING OF SHAREHOLDERS AGENDA
Wednesday, April 28, 1999 - 9:30 a.m. - Introduction and Welcome
Grand Ballroom - Election of Directors
Embassy Suites Hotel and Conference Center - Ratification of Auditors
300 Court Street - Chairman's Report
Charleston, West Virginia - Comments and Questions
from Shareholders
----------------------------------------------------------------------
EMBASSY SUITES CHARLESTON
(304) 347-8700
Embassy Suites Charleston is located just off [MAP]
the I-77 and I-64 interchange, adjacent to the
Charleston Town Center Mall. From the airport,
take I-77 to I-64 west.
----------------------------------------------------------------------
IF YOU PLAN TO ATTEND THE ANNUAL MEETING, PLEASE BRING THIS ADMISSION
TICKET WITH YOU.
- --------------------------------------------------------------------------------
<PAGE>
PLEASE MARK YOUR 0116
/X/ 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 OF
DIRECTORS / / / / AUDITORS. / / / / / /
(SEE REVERSE).
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.
____________________________, 1999
____________________________, 1999
SIGNATURE(S) DATE
- --------------------------------------------------------------------------------
^ FOLD AND DETACH HERE ^
YOUR VOTE IS IMPORTANT. You may vote the shares held in this account in any
one of the following three ways:
- VOTE BY MAIL. Complete, date, sign and mail your proxy card
(above) in the enclosed postage-paid envelope or, otherwise,
return it to AEP, P.O. Box 8673, Edison, New Jersey 08818.
- VOTE BY PHONE. Call TOLL-FREE, 1-877-PRX-VOTE
(1-877-779-8683) 24 hours a day, 7 days a week from the U.S.
and Canada to vote your proxy.
- VOTE BY INTERNET. Access the Web site at
http://www.eproxyvote.com/aep 24 hours a day, 7 days a week.
If you vote by phone or via the internet, please have your social security
number and proxy card available. The sequence of numbers appearing in the
box above, just below the perforation, and your social security number are
necessary to verify your vote. A phone or internet vote authorizes the
named proxies in the same manner as if you marked, signed and returned this
proxy card.
IF YOU VOTE BY PHONE OR VOTE USING THE INTERNET, THERE IS NO NEED FOR YOU
TO MAIL BACK YOUR PROXY CARD.
THANK YOU FOR VOTING
- --------------------------------------------------------------------------------
